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Document and Entity Information Document - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Feb. 21, 2014	Jun. 30, 2013
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	8-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		558,235,474
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 12,590

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 590	$ 372
Accounts receivable, net	3,658	3,057
Accounts receivable from related companies	63	71
Inventories	1,807	1,522
Exchanges receivable	67	55
Price risk management assets	39	25
Current assets held for sale	0	184
Other current assets	312	311
Total current assets	6,536	5,597
PROPERTY, PLANT AND EQUIPMENT	33,917	30,388
ACCUMULATED DEPRECIATION	(3,235)	(2,104)
PROPERTY, PLANT AND EQUIPMENT, net	30,682	28,284
NON-CURRENT ASSETS HELD FOR SALE	0	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,014	4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	18	43
GOODWILL	5,894	6,434
INTANGIBLE ASSETS, net	2,264	2,291
OTHER NON-CURRENT ASSETS, net	922	533
Total assets	50,330	48,904
LIABILITIES AND EQUITY
Accounts payable	3,834	3,107
Accounts payable to related companies	14	15
Exchanges payable	284	156
Price risk management liabilities	53	115
Accrued and other current liabilities	1,678	1,754
Current maturities of long-term debt	637	613
Current liabilities held for sale	0	85
Total current liabilities	6,500	5,845
NON-CURRENT LIABILITIES HELD FOR SALE	0	142
LONG-TERM DEBT, less current maturities	22,562	21,440
DEFERRED INCOME TAXES	3,865	3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	73	162
PREFERRED UNITS (Note 7)	0	331
OTHER NON-CURRENT LIABILITIES	1,019	995
COMMITMENTS AND CONTINGENCIES (Note 11)
PREFERRED UNITS OF SUBSIDIARY (Note 7)	32	73
Partners' Capital
General Partner	(3)	0
Limited Partners:
Common Unitholders (559,923,300 and 559,911,216 units authorized, issued and outstanding as of December 31, 2013 and 2012, respectively)	1,066	2,125
Limited Partners Capital Account Class D Units	6	0
Accumulated other comprehensive income (loss)	9	(12)
Total partners’ capital	1,078	2,113
Noncontrolling interest	15,201	14,237
Total equity	16,279	16,350
Total liabilities and equity	$ 50,330	$ 48,904

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Authorized	559,923,300	559,911,216
Issued	559,923,300	559,911,216
Outstanding	559,923,300	559,911,216
Class D Units [Member]
Class of Stock [Line Items]
Authorized	1,540,000
Issued	1,540,000
Outstanding	1,540,000

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:
Natural gas sales	$ 3,842	$ 2,705	$ 2,982
NGL sales	3,618	2,253	1,716
Crude sales	15,477	2,872	0
Gathering, transportation and other fees	3,097	2,386	1,819
Refined product sales	18,479	5,299	0
Other	3,822	1,449	1,673
Total revenues	48,335	16,964	8,190
COSTS AND EXPENSES:
Cost of products sold	42,554	13,088	5,169
Operating expenses	1,642	1,116	945
Depreciation and amortization	1,313	871	586
Selling, general and administrative	586	529	253
Goodwill impairment	(689)	0	0
Total costs and expenses	46,784	15,604	6,953
OPERATING INCOME	1,551	1,360	1,237
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(1,221)	(1,018)	(740)
Bridge loan related fees	0	(62)	0
Equity in earnings of unconsolidated affiliates	236	212	117
Gain on deconsolidation of Propane Business	0	1,057	0
Gain on sale of AmeriGas common units	87	0	0
Losses on extinguishments of debt	(162)	(123)	0
Gains (losses) on interest rate derivatives	53	(19)	(78)
Impairments of investments in affiliates	0	0	(5)
Non-operating environmental remediation	(168)	0	0
Other, net	(1)	30	17
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	375	1,437	548
Income tax expense from continuing operations	93	54	17
INCOME FROM CONTINUING OPERATIONS	282	1,383	531
Income (loss) from discontinued operations	33	(109)	(3)
NET INCOME	315	1,274	528
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	119	970	218
NET INCOME ATTRIBUTABLE TO PARTNERS	196	304	310
GENERAL PARTNER’S INTEREST IN NET INCOME	0	2	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 196	$ 302	$ 309
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$ 0.33	$ 0.59	$ 0.69
Diluted	0.33	0.59	0.69
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	0.35	0.57	0.69
Diluted	$ 0.35	$ 0.57	$ 0.69

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income	$ 315	$ 1,274	$ 528
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(4)	(17)	(19)
Change in value of derivative instruments accounted for as cash flow hedges	(1)	12	7
Change in value of available-for-sale securities	2	0	(1)
Actuarial gain (loss) relating to pension and other postretirement benefits	66	(10)	0
Foreign currency translation adjustment	(1)	0	0
Change in other comprehensive income from equity investments	17	(9)	0
Other comprehensive income (loss), net of tax, total	79	(24)	(13)
Comprehensive income	394	1,250	515
Less: Comprehensive income attributable to noncontrolling interest	181	959	209
Comprehensive income attributable to partners	$ 213	$ 291	$ 306

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2010	$ 6,247	$ 1	$ 114	$ 0	$ 5	$ 6,127
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(526)	(2)	(524)	0	0	0
Distributions to noncontrolling interest	(779)	0	0	0	0	(779)
Units issued in Southern Union Merger (See Note 3)	0
Subsidiary equity offerings, net of issue costs	1,903	0	153	0	0	1,750
Subsidiary units issued in acquisition	3	0	0	0	0	3
Non-cash compensation expense, net of units tendered by employees for tax withholdings	34	0	1	0	0	33
Other, net	(9)	0	(1)	0	0	(8)
Other comprehensive income, net of tax	(13)	0	0	0	(4)	(9)
Net income	528	1	309	0	0	218
Balance at Dec. 31, 2011	7,388	0	52	0	1	7,335
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(666)	(2)	(664)	0	0	0
Distributions to noncontrolling interest	(1,017)	0	0	0	0	(1,017)
Units issued in Southern Union Merger (See Note 3)	2,354	0	2,354	0	0	0
Subsidiary equity offerings, net of issue costs	1,103	0	33	0	0	1,070
Subsidiary units issued in acquisition	2,295	0	47	0	0	2,248
Non-cash compensation expense, net of units tendered by employees for tax withholdings	32	0	1	0	0	31
Capital contributions received from noncontrolling interest	42	0	0	0	0	42
Holdco Transaction (see Note 3)	3,580	0	0	0	0	3,580
Other, net	(11)	0	0	0	0	(11)
Other comprehensive income, net of tax	(24)	0	0	0	(13)	(11)
Net income	1,274	2	302	0	0	970
Balance at Dec. 31, 2012	16,350	0	2,125	0	(12)	14,237
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(733)	(2)	(731)	0	0	0
Distributions to noncontrolling interest	(1,428)	0	0	0	0	(1,428)
Units issued in Southern Union Merger (See Note 3)	0
Subsidiary equity offerings, net of issue costs	1,759	0	122	0	0	1,637
Subsidiary units issued in acquisition	0	(1)	(506)	0	0	507
Non-cash compensation expense, net of units tendered by employees for tax withholdings	54	0	1	6	0	47
Capital contributions received from noncontrolling interest	18	0	0	0	0	18
Other, net	(35)	0	0	0	4	(39)
Conversion of Regency Preferred Units for Regency Common Units	41	0	0	0	0	41
Deemed distribution related to SUGS Transaction	(141)	0	(141)	0	0	0
Other comprehensive income, net of tax	79	0	0	0	17	62
Net income	315	0	196	0	0	119
Balance at Dec. 31, 2013	$ 16,279	$ (3)	$ 1,066	$ 6	$ 9	$ 15,201

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 315	$ 1,274	$ 528
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	1,313	871	586
Deferred income taxes	43	51	1
Gain on curtailment of other postretirement benefit plans	0	(15)	0
Amortization included in interest expense	(55)	(13)	20
Bridge loan related fees	0	62	0
Non-cash compensation expense	61	47	42
Gain on deconsolidation of Propane Business	0	(1,057)	0
Gain on sale of AmeriGas common units	(87)	0	0
Goodwill impairment	689	0	0
Losses on extinguishments of debt	162	123	0
Losses on disposal of assets	2	4	1
Equity in earnings of unconsolidated affiliates	(236)	(212)	(117)
Distributions from unconsolidated affiliates	313	208	126
LIFO valuation adjustments	(3)	75	0
Other non-cash	51	211	33
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2)	(149)	(551)	158
Net cash provided by operating activities	2,419	1,078	1,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions	(405)	(10)	(1,972)
Cash proceeds from contribution and sale of propane operations	0	1,443	0
Cash proceeds from the sale of the MGE and NEG assets (See Note 3)	1,008	0	0
Cash proceeds from the sale of AmeriGas common units	346	0	0
Proceeds from the sale of other assets	89	251	33
Capital expenditures (excluding allowance for equity funds used during construction)	(3,505)	(3,271)	(1,810)
Contributions in aid of construction costs	52	35	25
Contributions to unconsolidated affiliates	(3)	(37)	(222)
Distributions from unconsolidated affiliates in excess of cumulative earnings	419	189	72
Restricted cash	(348)	5	0
Other	0	171	0
Net cash used in investing activities	(2,347)	(4,196)	(3,874)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	12,934	12,870	8,262
Repayments of long-term debt	(11,951)	(8,848)	(6,264)
Subsidiary equity offerings, net of issue costs	1,759	1,103	1,903
Distributions to partners	(733)	(666)	(526)
Distributions to noncontrolling interests	(1,428)	(1,017)	(779)
Debt issuance costs	(87)	(112)	(53)
Capital contributions received from noncontrolling interest	18	42	0
Redemption of Preferred Units	(340)	0	0
Other, net	(26)	(8)	(7)
Net cash provided by financing activities	146	3,364	2,536
INCREASE IN CASH AND CASH EQUIVALENTS	218	246	40
CASH AND CASH EQUIVALENTS, beginning of period	372	126	86
CASH AND CASH EQUIVALENTS, end of period	590	372	126
SUG Merger [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions	$ 0	$ (2,972)	$ 0

Operations And Organization

12 Months Ended

Dec. 31, 2013

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, 2013, 2012 and 2011, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.

As discussed in Note 8, in January 2014, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented.

On March 26, 2012, we acquired all of the outstanding shares of Southern Union. On October 5, 2012, ETP completed the Sunoco Merger and we and ETP also completed the Holdco Transaction at that time. On April 30, 2013, ETP acquired our 60% interest in Holdco. See Note 3 for more information regarding these transactions.

At December 31, 2013, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:



	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	49.6	26.3
ETP Class H units	50.2	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

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


•	the Parent Company;


•	our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);


•	ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

As a result of the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

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 2013 presentation. These reclassifications had no impact on net income or total equity. In October 2012, ETP sold Canyon and the results of continuing operations of Canyon have been reclassified to income (loss) from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. Canyon was previously included in ETP’s midstream operations. In 2013, Southern Union sold its distribution operations. The results of operations of the distribution operations have been reported as income (loss) from discontinued operations. The assets and liabilities of the disposal group have been reported as assets and liabilities held for sale as of December 31, 2012.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco, Sunoco Logistics and Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:


•	ETP’s operations are conducted through the following subsidiaries:

•

ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star and also owns a convenience store operator with approximately 300 company-owned and dealer locations.


•	ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:


•	Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.


•	ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.


•	ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.


•	CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., which owns 100% of the FGT interstate natural gas pipeline.


•	ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.


•	Sunoco Logistics is a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets.


•	Holdco is a Delaware limited liability company that indirectly owns Panhandle and Sunoco. As discussed in Note 3, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Panhandle and Sunoco operations are described as follows:

•

Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, on April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interests in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. Also, as discussed in Note 3, Southern Union completed its sale of the assets of MGE and NEG in 2013. Additionally, as discussed in Note 3, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.


•	Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores in 24 states, primarily on the east coast and in the midwest region of the United States.

•

Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.


•	Trunkline LNG operates a LNG import terminal, which has approximately 9.0 bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Trunkline LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

As discussed in Note 15 to our consolidated financial statements, subsequent to the acquisition of Trunkline LNG in February 2014, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; Investment in Trunkline LNG; and Corporate and Other.

- Definition

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

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+ Details

Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2013

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 values and results could differ from those estimates.

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.

Investment in ETP

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, 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 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 ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP 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 ETP’s 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 ETP operate, 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 ETP’s 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 ETP 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 ETP’s 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, (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, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, 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.

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.

ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s 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.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

ETP’s retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. In addition, some of Sunoco’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.

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.

Investment in Trunkline LNG

Trunkline LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Trunkline LNG’s terminal.

Regulatory Accounting – Regulatory Assets and Liabilities

ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Southern Union recorded regulatory assets with respect to its distribution operations. At December 31, 2012, there were $123 million of regulatory assets included in our consolidated balance sheet as non-current assets held for sale. Southern Union’s distribution operations were sold in 2013.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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



	Years Ended December 31,
	2013			2012			2011
Accounts receivable	$	(556	)	$	267		$	6
Accounts receivable from related companies	64			(9		)	(24		)
Inventories	(254		)	(258		)	51
Exchanges receivable	(8		)	14			1
Other current assets	(81		)	597			(51		)
Other non-current assets, net	(23		)	(129		)	7
Accounts payable	541			(989		)	21
Accounts payable to related companies	(140		)	92			6
Exchanges payable	128			—			2
Accrued and other current liabilities	192			(159		)	84
Other non-current liabilities	147			26			—
Price risk management assets and liabilities, net	(159		)	(3		)	55
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(149	)	$	(551	)	$	158

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



	Years Ended December 31,
	2013			2012		2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	226		$	420	$	226
Net gains (losses) from subsidiary common unit transactions	$	(384	)	$	80	$	153
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	—		$	1,123	$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with Southern Union Merger (see Note 3)	$	—		$	2,354	$	—
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—		$	6,658	$	4
Subsidiary issuance of Common Units in connection with certain acquisitions	$	—		$	2,295	$	3
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,256		$	997	$	728
Cash paid for income taxes	$	58		$	23	$	27

Accounts Receivable

Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.

Inventories

Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:



	December 31,
	2013		2012
Natural gas and NGLs	$	523	$	338
Crude oil	488		418
Refined products	597		572
Appliances, parts and fittings and other	199		194
Total inventories	$	1,807	$	1,522

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.

Other Current Assets

Other current assets consisted of the following:



	December 31,
	2013		2012
Deposits paid to vendors	$	49	$	41
Prepaid and other	263		270
Total other current assets	$	312	$	311

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $128 million during the year ended December 31, 2012.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts - borrowed funds and equity funds.

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



	December 31,
	2013			2012
Land and improvements	$	881		$	553
Buildings and improvements (5 to 45 years)	939			692
Pipelines and equipment (5 to 83 years)	21,494			19,505
Natural gas and NGL storage facilities (5 to 46 years)	1,083			1,057
Bulk storage, equipment and facilities (2 to 83 years)	1,933			1,745
Tanks and other equipment (5 to 40 years)	1,697			1,194
Retail equipment (3 to 99 years)	450			258
Vehicles (1 to 25 years)	156			154
Right of way (20 to 83 years)	2,190			2,134
Furniture and fixtures (2 to 25 years)	51			67
Linepack	118			118
Pad gas	52			58
Other (1 to 48 years)	708			880
Construction work-in-process	2,165			1,973
	33,917			30,388
Less – Accumulated depreciation	(3,235		)	(2,104		)
Property, plant and equipment, net	$	30,682		$	28,284

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



	Years Ended December 31,
	2013		2012		2011
Depreciation expense ⁽¹⁾	$	1,128	$	801	$	531
Capitalized interest, excluding AFUDC	$	43	$	99	$	13


⁽¹⁾	Depreciation expense amounts have been adjusted by $26 million for the year ended December 31, 2011 to present Canyon’s operations as discontinued operations.

Advances to and Investments in Affiliates

Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations and during the fourth quarter for reporting units within ETP’s interstate transportation and storage and NGL transportation and services operations and all others, including all of Regency’s reporting units.

Changes in the carrying amount of goodwill were as follows:



	Investment in ETP			Investment in Regency		Corporate, Other and Eliminations			Total
Balance, December 31, 2011	$	1,220		$	790	$	29		$	2,039
Goodwill acquired ⁽¹⁾	5,138			337		(328		)	5,147
Goodwill sold in deconsolidation of ETP Propane Business	(619		)	—		—			(619		)
Goodwill allocated to the disposal group	(133		)	—		—			(133		)
Balance, December 31, 2012	5,606			1,127		(299		)	6,434
Goodwill acquired	156			—		—			156
Deconsolidation of SUGS ⁽¹⁾	(337		)	—		337			—
Goodwill impairment	(689		)	—		—			(689		)
Other	(7		)	—		—			(7		)
Balance, December 31, 2013	$	4,729		$	1,127	$	38		$	5,894

⁽¹⁾

As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013 which was a transaction between entities under common control. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012. Therefore, the December 31, 2012 goodwill balance includes goodwill attributable to SUGS of $337 million in both segments that was correspondingly included in the elimination column. ETP deconsolidated SUGS on April 30, 2013.

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. We recorded a net increase in goodwill of $4.40 billion during the year ended December 31, 2012 primarily due to the Southern Union and Sunoco Mergers where we recorded goodwill of $2.50 billion and $2.64 billion, respectively. We recorded a net decrease in goodwill of $540 million during the year ended December 31, 2013 primarily due to Trunkline LNG’s goodwill impairment of $689 million (see below). These decreases were offset by additional goodwill of $156 million from acquisitions in 2013. The additional goodwill recorded during the years ended December 31, 2012 and 2013 is not expected to be deductible for tax purposes.

During the fourth quarter of 2013, ETP performed a goodwill impairment test on its Trunkline LNG reporting unit. In accordance with GAAP, ETP performed step one of the goodwill impairment test and determined that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount, primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Trunkline LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount. ETP then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, ETP estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, ETP used current replacement costs adjusted for assumed depreciation. ETP also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. ETP adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, ETP recorded a goodwill impairment of $689 million during the fourth quarter of 2013.

No other goodwill impairments were identified or recorded for our 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.

Components and useful lives of intangible assets were as follows:



	December 31, 2013					December 31, 2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	2,135	$	(264	)	$	2,032	$	(150	)
Trade names (20 years)	66		(12		)	66		(8		)
Patents (9 years)	48		(6		)	48		(1		)
Other (10 to 15 years)	7		(4		)	4		(1		)
Total amortizable intangible assets	2,256		(286		)	2,150		(160		)
Non-amortizable intangible assets:
Trademarks	294		—			301		—
Total intangible assets	$	2,550	$	(286	)	$	2,451	$	(160	)

Aggregate amortization expense of intangibles assets was as follows:



	Years Ended December 31,
	2013		2012		2011
Reported in depreciation and amortization	$	120	$	70	$	55

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



Years Ending December 31:
2014	$	123
2015	123
2016	123
2017	123
2018	122

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:



	December 31,
	2013		2012
Unamortized financing costs (3 to 30 years)	$	167	$	152
Regulatory assets	86		93
Deferred charges	144		140
Restricted funds	378		—
Other	147		148
Total other non-current assets, net	$	922	$	533

Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Asset Retirement Obligation

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.

Except for the AROs of Southern Union, Sunoco Logistics and Sunoco discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2013 and 2012 because the settlement dates were indeterminable. Although a number of other onshore assets in Southern Union’s system are subject to agreements or regulations that give rise to an ARO upon Southern Union’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco has legal asset retirement obligations for several other assets at its refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Below is a schedule of AROs by entity recorded as other non-current liabilities in ETP’s consolidated balance sheet:



	December 31,
	2013		2012
Southern Union	$	55	$	46
Sunoco	84		53
Sunoco Logistics	41		41
	$	180	$	140

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have has in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2013, there were no legally restricted funds for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	December 31,
	2013		2012
Interest payable	$	357	$	334
Customer advances and deposits	142		61
Accrued capital expenditures	260		427
Accrued wages and benefits	173		250
Taxes payable other than income taxes	211		208
Income taxes payable	4		41
Deferred income taxes	119		130
Other	412		303
Total accrued and other current liabilities	$	1,678	$	1,754

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

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of December 31, 2013 and 2012 was $23.97 billion and $24.15 billion, respectively. As of December 31, 2013 and 2012, the aggregate carrying amount of our consolidated debt obligations was $23.20 billion and $22.05 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives, the Preferred Units, the preferred units of a subsidiary 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 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. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.

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, 2013 and 2012 based on inputs used to derive their fair values:



	Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	47		$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	8			1			7			—
Fixed Swaps/Futures	203			201			2			—
NGLs — Forwards/Swaps	7			5			2			—
Power — Forwards	3			—			3			—
Refined Products — Futures	5			5			—			—
Total commodity derivatives	231			217			14			—
Total assets	$	278		$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)	—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—			—
Swing Swaps IFERC	(6		)	—			(6		)	—
Fixed Swaps/Futures	(206		)	(201		)	(5		)	—
Forward Physical Contracts	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(9		)	(5		)	(4		)	—
Power — Forwards	(1		)	—			(1		)	—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(233		)	(215		)	(18		)	—
Total liabilities	$	(347	)	$	(215	)	$	(113	)	$	(19	)



	Fair Value Measurements at December 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	55		$	—		$	55		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	98			94			4			—
Options — Calls	3			—			3			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Swaps	2			1			1			—
Power:
Forwards	27			—			27			—
Futures	1			1			—			—
Options — Calls	2			—			2			—
Refined Products – Futures	5			1			4			—
Total commodity derivatives	156			108			48			—
Total assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products – Futures	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)

At December 31, 2013, the fair value of ETP’s Trunkline LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. ETP used the income approach to measure the fair value of the Trunkline LNG reporting unit. Under the income approach, ETP calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows.

The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:



	Unobservable Input	December 31, 2013
Embedded derivatives in the Regency Preferred Units	Credit Spread	4.16	%
	Volatility	23.71	%

Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2013. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2013 or 2012.



Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Redemption of Preferred Units	340
Net unrealized gains included in other income (expense)	6
Balance, December 31, 2013	$	(19	)

Contributions in Aid of Construction Cost

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and are as follows:



	Years Ended December 31,
	2013		2012		2011
Shipping and handling costs – recorded in operating expenses	$	28	$	25	$	40

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by ETP’s retail marketing operations were $2.22 billion and $573 million for the years ended December 31, 2013 and 2012, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon ETP’s or Regency’s issuance of respective ETP or Regency Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2013, 2012 and 2011, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. Holdco, which owns Sunoco and Southern Union, is a corporate subsidiary. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in gains (losses) on interest rate derivatives in the consolidated statements of operations.

Pensions and Other Postretirement Benefit Plans

Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in equity or are reflected as a regulatory asset or regulatory liability for regulated entities.

Allocation of Income

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

Acquisitions and Related Transactions

12 Months Ended

Dec. 31, 2013

Acquisitions and Dispositions [Abstract]

Acquisitions and Related Transactions

ACQUISITIONS AND RELATED TRANSACTIONS:

2014 Transactions

Panhandle Merger

On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and the Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have operations of its own, other than its ownership of Panhandle and noncontrolling interest in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (2.2 million ETP Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Trunkline LNG Transaction

On February 19, 2014, ETE and ETP completed the transfer to ETE of Trunkline LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, from ETP in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE. The transaction was effective as of January 1, 2014.

In connection with ETE’s acquisition of Trunkline LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8.

Regency’s Pending Acquisition of PVR Partners, L.P.

In October 2013, Regency announced that it entered into a merger agreement with PVR (“PVR Acquisition”), pursuant to which, Regency intends to merge with PVR. This merger will be a unit-for-unit transaction plus a one-time approximately $37 million cash payment to PVR unitholders which represents total consideration of $5.6 billion, including the assumption of net debt of $1.8 billion. The holders of PVR common units, PVR Class B Units and PVR Special Units (“PVR Unit(s)”) will receive 1.02 Regency Common Units in exchange for each PVR Unit held on the applicable record date. In November 2013, Regency received clearance of the PVR Acquisition under the Hart-Scott-Rodino Antitrust Improvements Act. The transaction is subject to the approval of PVR’s unitholders and other customary closing conditions, and is expected to close in late March 2014. The PVR Acquisition is expected to enhance Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region.

Regency’s Pending Acquisition of Eagle Rock Energy Partners, L.P.’s Midstream Business

On December 23, 2013, Regency announced plans to purchase Eagle Rock Energy Partners, L.P.’s midstream business. This acquisition, valued at approximately $1.3 billion, will complement Regency’s core gathering and processing business, and when combined with the proposed acquisition of PVR Resources, will further diversify Regency’s basin exposure in the Texas Panhandle, East Texas and South Texas. The Partnership has agreed to purchase approximately 16.5 million Regency Common Units for approximately $400 million upon the closing of this acquisition. The Eagle Rock Acquisition is expected to close in the second quarter of 2014, and is subject to the approval of Eagle Rock’s unitholders, Hart-Scott-Rodino Antitrust Improvements Act approval and other customary closing conditions.

Regency’s Acquisition of Hoover Energy

On February 3, 2014, Regency completed its previously announced acquisition of the midstream assets of Hoover Energy. The consideration paid by Regency in exchange for the acquired Hoover entities was valued at $282 million (subject to customary post-closing adjustments) and consisted of (i) 4.0 million Regency Common Units issued to Hoover Energy and (ii) $184 million in cash. A portion of the consideration is being held in escrow as security for certain indemnification claims. Regency financed the cash portion of the purchase price through borrowings under its revolving credit facility.

2013 Transactions

Sale of Southern Union’s Distribution Operations

In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.

In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.

The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The assets and liabilities of the LDC Disposal Group were classified as assets and liabilities held for sale at December 31, 2012.

The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012:



	Years Ended December 31,
	2013		2012
Revenue from discontinued operations	$	415	$	324
Net loss of discontinued operations, excluding effect of taxes and overhead allocations	65		43

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

2012 Transactions

Southern Union Merger

On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE until our contribution to Holdco discussed below.

Under the terms of the merger agreement, Southern Union stockholders received a total of approximately 57 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.

Citrus Acquisition

In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.

Sunoco Merger

On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and a total of approximately $2.6 billion in cash.

Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco’s interests in Sunoco Logistics were transferred to ETP.

Prior to the Sunoco Merger, on September 8, 2012, Sunoco completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook facility continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco retained an approximately 33% non-operating noncontrolling interest. The fair value of Sunoco’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase will provide working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.

Holdco Transaction

Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million Class F Units representing limited partner interests in ETP (“ETP Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 8. Pursuant to a stockholders agreement between ETE and ETP, ETP controlled Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in Holdco in 2013) and therefore, ETP consolidated Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

Under the terms of the Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the Southern Union Merger and Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet presented as of December 31, 2012 reflects the purchase price allocations. Certain amounts included in the purchase price allocation as of December 31, 2012 for Southern Union have been changed from amounts reflected as of March 31, 2012 based on management’s review of the valuation.

The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:



	Sunoco⁽¹⁾		Southern Union⁽²⁾
Current assets	$	7,312	$	556
Property, plant and equipment	6,686		6,242
Goodwill	2,641		2,497
Intangible assets	1,361		55
Investments in unconsolidated affiliates	240		2,023
Note receivable	821		—
Other assets	128		163
	19,189		11,536

Current liabilities	4,424		1,348
Long-term debt obligations, less current maturities	2,879		3,120
Deferred income taxes	1,762		1,419
Other non-current liabilities	769		284
Noncontrolling interest	3,580		—
	13,414		6,171
Total consideration	5,775		5,365
Cash received	2,714		37
Total consideration, net of cash received	$	3,061	$	5,328


⁽¹⁾	Includes amounts recorded with respect to Sunoco Logistics.


⁽²⁾	Includes ETP’s acquisition of Citrus.

As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.

Propane Operations

On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 30 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.

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

In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.

Sale of Canyon

In October 2012, ETP sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012. Canyon was previously included in our Investment in ETP segment.

2011 Transaction

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, from Louis Dreyfus Highbridge Energy LLC for approximately $1.98 billion in cash (the “LDH Acquisition”), including working capital adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price, while Regency contributed approximately $593 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.

Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH by Lone Star expanded 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 ETP’s NGL transportation and services operations, while Lone Star’s results are recorded as an equity method investment in our Investment in Regency 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.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the years ended December 31, 2012 and 2011 are presented as if the Sunoco Merger, Holdco Transaction and LDH Acquisition had been completed on January 1, 2011.



	Years Ended December 31,
	2012		2011
Revenues	$	40,398	$	37,560
Net income	868		865
Net income attributable to partners	866		863
Basic net income per Limited Partner unit	$	1.55	$	1.54
Diluted net income per Limited Partner unit	$	1.55	$	1.54

The pro forma consolidated results of operations include adjustments to:


•	include the results of Lone Star beginning January 1, 2010 and Southern Union and Sunoco beginning January 1, 2011;


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

•include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

- 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 Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
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+ Details

Advances to and Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2013

Investment In Affiliates [Abstract]

Investments In Affiliates

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

AmeriGas Partners, L.P.

As discussed in Note 3, on January 12, 2012, ETP received approximately 29.6 million AmeriGas common units in connection with the contribution of its propane operations. On July 12, 2013, ETP sold 7.5 million AmeriGas common units for net proceeds of $346 million, and as of December 31, 2013, ETP owned 22.1 million AmeriGas common units representing an approximate 24% limited partner interest.

The carrying amount of ETP’s investment in AmeriGas was $746 million and $1.02 billion as of December 31, 2013 and 2012, respectively, and was reflected in ETP’s all other operations. As of December 31, 2013, ETP’s investment in AmeriGas reflected $439 million in excess of its proportionate share of AmeriGas’ limited partners’ capital. Of this excess fair value, $184 million is being amortized over a weighted average period of 14 years, and $255 million is being treated as equity method goodwill and non-amortizable intangible assets.

In January 2014, ETP sold 9.2 million AmeriGas common units for net proceeds of $381 million. Net proceeds from this sale were used to repay borrowings under the ETP Credit Facility and general partnership purposes.

Citrus Corp.

On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.

ETP recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of ETP’s investment in Citrus was $1.89 billion and $1.98 billion at December 31, 2013 and 2012, respectively, and was reflected in ETP’s interstate transportation and storage operations.

FEP

ETP has a 50% interest in FEP, a 50/50 joint venture with Kinder Morgan Energy Partners LP. FEP owns the Fayetteville Express pipeline, 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. The carrying amount of ETP’s investment in FEP was $144 million and $159 million as of December 31, 2013 and 2012, respectively, and was reflected in ETP’s interstate transportation and storage operations.

Midcontinent Express Pipeline LLC

Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. The carrying amount of Regency’s investment in MEP was $548 million and $581 million as of December 31, 2013 and 2012, respectively, and was reflected in Regency’s natural gas transportation operations.

RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. The carrying amount of Regency’s investment in HPC was $442 million and $650 million as of December 31, 2013 and 2012, respectively, and was reflected in Regency’s natural gas transportation operations.

Summarized Financial Information

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



	December 31,
	2013		2012
Current assets	$	1,028	$	945
Property, plant and equipment, net	10,778		10,979
Other assets	2,664		2,677
Total assets	$	14,470	$	14,601

Current liabilities	$	1,039	$	1,662
Non-current liabilities	8,139		7,024
Equity	5,292		5,915
Total liabilities and equity	$	14,470	$	14,601



	Years Ended December 31,
	2013		2012		2011
Revenue	$	4,695	$	4,492	$	3,784
Operating income	1,197		863		928
Net income	699		491		536

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2013

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 the years ended December 31, 2012 and 2011 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units were redeemed April 1, 2013 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,
	2013		2012			2011
Income from continuing operations	$	282	$	1,383		$	531
Less: Income from continuing operations attributable to noncontrolling interest	99		1,070			221
Income from continuing operations, net of noncontrolling interest	183		313			310
Less: General Partner’s interest in income from continuing operations	—		1			1
Income from continuing operations available to Limited Partners	$	183	$	312		$	309
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	560.9		533.4			445.9
Basic income from continuing operations per Limited Partner unit	$	0.33	$	0.59		$	0.69
Basic income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.02	)	$	—
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	183	$	312		$	309
Dilutive effect of equity-based compensation of subsidiaries	—		(1		)	(1		)
Diluted income from continuing operations available to Limited Partners	183		311			308
Weighted average limited partner units	560.9		533.4			445.9
Dilutive effect of unconverted unit awards	—		—			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	560.9		533.4			445.9
Diluted income from continuing operations per Limited Partner unit	$	0.33	$	0.59		$	0.69
Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.02	)	$	—

Debt Obligations

12 Months Ended

Dec. 31, 2013

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

Our debt obligations consist of the following:



	December 31,
	2013			2012
Parent Company Indebtedness:
7.50% Senior Notes, due October 15, 2020	$	1,187		$	1,800
5.875% Senior Notes, due January 15, 2024	450			—
ETE Senior Secured Term Loan, due March 26, 2017	—			2,000
ETE Senior Secured Term Loan, due December 2, 2018	171			—
ETE Senior Secured Term Loan, due December 2, 2019	1,000			—
ETE Senior Secured Revolving Credit Facility	—			60
Unamortized premiums, discounts and fair value adjustments, net	(7		)	(34		)
	2,801			3,826
Subsidiary Indebtedness:
ETP Debt
6.0% Senior Notes due July 1, 2013	—			350
8.5% Senior Notes due April 15, 2014	292			292
5.95% Senior Notes due February 1, 2015	750			750
6.125% Senior Notes due February 15, 2017	400			400
6.7% Senior Notes due July 1, 2018	600			600
9.7% Senior Notes due March 15, 2019	400			400
9.0% Senior Notes due April 15, 2019	450			450
4.15% Senior Notes due October 1, 2020	700			—
4.65% Senior Notes due June 1, 2021	800			800
5.20% Senior Notes due February 1, 2022	1,000			1,000
3.60% Senior Notes due February 1, 2023	800			—
4.9% Senior Notes due February 1, 2024	350			—
7.6% Senior Notes due February 1, 2024	277			—
8.25% Senior Notes due November 15, 2029	267			—
6.625% Senior Notes due October 15, 2036	400			400
7.5% Senior Notes due July 1, 2038	550			550
6.05% Senior Notes due June 1, 2041	700			700
6.5% Senior Notes due February 1, 2042	1,000			1,000
5.15% Senior Notes due February 1, 2043	450			—
5.95% Senior Notes due October 1, 2043	450			—
Floating Rate Junior Subordinated Notes due November 1, 2066	546			—
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	65			1,395
Unamortized premiums, discounts and fair value adjustments, net	(34		)	(14		)
	11,213			9,073
Panhandle Debt
6.05% Senior Notes due August 15, 2013	—			250
6.20% Senior Notes due November 1, 2017	300			300
7.00% Senior Notes due June 15, 2018	400			400
8.125% Senior Notes due June 1, 2019	150			150
7.00% Senior Notes due July 15, 2029	66			66
Term Loan due February 23, 2015	—			455
Unamortized premiums, discounts and fair value adjustments, net	107			136
	1,023			1,757
Regency Debt
9.375% Senior Notes due June 1, 2016	—			162
6.875% Senior Notes due December 1, 2018	600			600
5.75% Senior Notes due September 1, 2020	400			—
6.5% Senior Notes due July 15, 2021	500			500
5.5% Senior Notes due April 15, 2023	700			700
4.5% Senior Notes due November 1, 2023	600			—
Regency $1.2 billion Revolving Credit Facility due May 21, 2018	510			192
Unamortized premiums, discounts and fair value adjustments, net	—			3
	3,310			2,157
Southern Union Debt⁽¹⁾
7.60% Senior Notes due February 1, 2024	82			360
8.25% Senior Notes due November 14, 2029	33			300
Floating Rate Junior Subordinated Notes due November 1, 2066	54			600
Southern Union $700 million Revolving Credit Facility due May 20, 2016	—			210
Unamortized premiums, discounts and fair value adjustments, net	48			49
	217			1,519
Sunoco Debt
4.875% Senior Notes due October 15, 2014	250			250
9.625% Senior Notes due April 15, 2015	250			250
5.75% Senior Notes due January 15, 2017	400			400
9.00% Debentures due November 1, 2024	65			65
Unamortized premiums, discounts and fair value adjustments, net	70			104
	1,035			1,069
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014⁽²⁾	175			175
6.125% Senior Notes due May 15, 2016	175			175
5.50% Senior Notes due February 15, 2020	250			250
4.65% Senior Notes due February 15, 2022	300			300
3.45% Senior Notes due January 15, 2023	350			—
6.85% Senior Notes due February 15, 2040	250			250
6.10% Senior Notes due February 15, 2042	300			300
4.95% Senior Notes due January 15, 2043	350			—
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2014	—			26
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35			20
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016	—			93
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 1, 2018	200			—
Unamortized premiums, discounts and fair value adjustments, net	118			143
	2,503			1,732
Transwestern Debt
5.39% Senior Notes due November 17, 2014	88			88
5.54% Senior Notes due November 17, 2016	125			125
5.64% Senior Notes due May 24, 2017	82			82
5.36% Senior Notes due December 9, 2020	175			175
5.89% Senior Notes due May 24, 2022	150			150
5.66% Senior Notes due December 9, 2024	175			175
6.16% Senior Notes due May 24, 2037	75			75
Unamortized premiums, discounts and fair value adjustments, net	(1		)	(1		)
	869			869
Other	228			51
	23,199			22,053
Less: current maturities	637			613
	$	22,562		$	21,440


⁽¹⁾	In connection with the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle.


⁽²⁾	Sunoco Logistics’ 8.75% Senior Notes due February 15, 2014 were classified as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018.

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $301 million in unamortized premiums and fair value adjustments, net:



2014	$	812
2015	1,047
2016	375
2017	1,220
2018	1,976
Thereafter	17,468
Total	$	22,898

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

Notes and Debentures

ETE Senior Notes

On December 2, 2013, the Parent Company completed a public offering of $450 million aggregate principal amount of its 5.875% Senior Notes due 2024. The Parent Company used net proceeds from this offering, together with a portion of the net proceeds from the Revolver Credit Agreement and the ETE Term Loan Facility, discussed below, to fund the Parent Company’s tender offer for a portion of its 7.500% Senior Notes due 2020 (together with the 5.875% Senior Notes due 2024, the “ETE Senior Notes”).

The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.

The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.

ETP as Co-Obligor of Sunoco Debt

In connection with the Sunoco Merger and Holdco Transaction, ETP became a co-obligor on approximately of $965 million aggregate principal amount of Sunoco’s existing senior notes and debentures.

Southern Union Junior Subordinated Notes

The interest rate on the remaining portion of Southern Union’s $600 million Junior Subordinated Notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $600 million at an effective interest rate of 3.32% at December 31, 2013.

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.

In January 2013, ETP completed a public offering of $800 million aggregate principal amount of our 3.6% Senior Notes due February 1, 2023 and $450 million aggregate principal amount of its 5.15% Senior Notes due February 1, 2043. ETP used the net proceeds of $1.24 billion from this offering to repay borrowings outstanding under its revolving credit facility and for general partnership purposes.

In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly-owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

Sunoco Logistics Senior Notes

In January 2013, Sunoco Logistics issued $350 million aggregate principal amount of 3.45% Senior Notes due January 2023 and $350 million aggregate principal amount of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.

Transwestern Senior Notes

The Transwestern notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.

Regency Senior Notes

The Regency Senior Notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency Senior Notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency Senior Notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.

Term Loans and Credit Facilities

ETE Term Loan Facility

On December 2, 2013, the Parent Company entered into a Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”), which has a scheduled maturity date of December 2, 2019, with an option to extend the term subject to the terms and conditions set forth therein. Pursuant to the ETE Term Credit Agreement, the lenders have provided senior secured financing in an aggregate principal amount of $1.0 billion (the “ETE Term Loan Facility”). The Parent Company shall not be required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances, the Partnership is required to repay the term loan in connection with dispositions of (a) incentive distribution rights in ETP or Regency, (b) general partnership interests in Regency or (c) equity interests of any Person which owns, directly or indirectly, incentive distribution rights in ETP or Regency or general partnership interests in Regency, in each case, yielding net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Term Loan Facility initially is not guaranteed by any of the Parent Company’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The applicable margin for LIBOR rate loans is 2.50% and the applicable margin for base rate loans is 1.50%. Proceeds of the borrowings under the Term Credit Agreement were used to partially fund a tender offer for ETE Senior Notes completed in December 2013, to repay amounts outstanding under the Parent Company’s existing term loan credit facility, and to pay transaction fees and expenses related to the tender offer, the ETE Term Loan Facility and other transactions incidental thereto.

ETE Revolving Credit Facility

On December 2, 2013, the Parent Company entered into a credit agreement (the “Revolving Credit Agreement”), which has a scheduled maturity date of December 2, 2018, with an option for the Partnership to extend the term subject to the terms and conditions set forth therein.

Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $600 million at any one time outstanding (the “ETE Revolving Credit Facility”), and the Parent Company has the option to request increases in the aggregate commitments provided that the aggregate commitments never exceed $1.0 billion. In February 2014, the Partnership increased the capacity on the ETE Revolving Credit Facility to $800 million and expects to utilize the additional capacity to fund the purchase of $400 million of Regency common units in connection with Regency’s pending Eagle Rock acquisition.

As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit.

Under the Revolver Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2017. 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. ETP uses the ETP Credit Facility to provide temporary financing for the Partnership’s growth projects, as well as for general partnership purposes.

In November 2013, ETP amended the ETP Credit Facility to, among other things, (i) extend the maturity date for one additional year to October 2017, (ii) remove the restriction prohibiting unrestricted subsidiaries from owning debt or equity interests in ETP or any restricted subsidiaries of ETP, (iii) amend the covenant limiting fundamental changes to remove the restrictions on mergers or other consolidations of restricted subsidiaries of ETP and to permit ETP to merge with another person and not be the surviving entity provided certain requirements are met, and (iv) amend certain other provisions more specifically set forth in the amendment.

As of December 31, 2013, the ETP Credit Facility had $65 million outstanding, and the amount available for future borrowings was $2.34 billion after taking into account letters of credit of $93 million. The weighted average interest rate on the total amount outstanding as of December 31, 2013 was 1.67%.

Regency Credit Facility

In May 2013, Regency entered into an amendment to the Regency Credit Facility to increase the borrowing capacity of the Regency Credit Facility to $1.20 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. Indebtedness under the Regency Credit Facility is secured by all of Regency’s and certain of its subsidiaries’ tangible and intangible assets and guaranteed by certain of Regency’s subsidiaries.

In February 2014, Regency entered into the First Amendment to Sixth Amended and Restated Credit Agreement to, among other things, expressly permit the pending PVR and Eagle Rock acquisitions, and to increase the commitment to $1.5 billion and increase the uncommitted incremental facility to $500 million.

As of December 31, 2013, Regency had a balance of $510 million outstanding under the Regency Credit Facility in revolving credit loans and approximately $14 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2013, which is reduced by any letters of credit, was approximately $676 million. The weighted average interest rate on the total amount outstanding as of December 31, 2013 was 2.17%.

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 0.63% to 1.5% for base rate loans and 1.63% to 2.5% for Eurodollar loans.

Regency pays (i) a commitment fee ranging between 0.3% and 0.45% 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 1.63% and 2.5% 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 0.2% 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.

Panhandle Term Loans

A portion of the proceeds from ETP’s September 2013 Senior Notes offering, as discussed below, were used to repay $455 million of borrowings under the LNG Holdings’ term loan due February 2015.

Bridge Term Loan Facility

Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated a 364-day Bridge Term Loan Facility. For the year ended December 31, 2012, bridge loan related fees reflects the recognition of $62 million of commitment fees upon termination of the facility.

Southern Union Credit Facility

Proceeds from the SUGS Contribution were used to repay borrowings under the Southern Union Credit Facility and the facility was terminated.

Sunoco Logistics Credit Facilities

In November 2013, Sunoco Logistics replaced its existing $350 million and $200 million unsecured credit facilities with a new $1.50 billion unsecured credit facility (the “$1.50 billion Credit Facility”). The $1.50 billion Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions. Outstanding borrowings under the $350 million and $200 million credit facilities of $119 million at December 31, 2012 were repaid during the first quarter of 2013.

The $1.50 billion Credit Facility, which matures in November 2018, is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The $1.50 billion Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. Outstanding borrowings under this credit facility were $200 million at December 31, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Outstanding borrowings under this credit facility were $35 million at December 31, 2013.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The ETE Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.

The ETE Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:


•	Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to EBITDA (as defined in the agreements) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and


•	EBITDA to interest expense of not less than 1.5 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 5.00 to 1.


•	Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 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 3.25 to 1.

The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:


•	incur indebtedness;


•	grant liens;


•	enter into sale and leaseback transactions;


•	make certain investments, loans and advances;


•	dissolve or enter into a merger or consolidation;


•	enter into asset sales or make acquisitions;


•	enter into transactions with affiliates;


•	prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);


•	issue capital stock or create subsidiaries; or


•	engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.

Covenants Related to Southern Union

Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Financial covenants exist in certain of the Southern Union’s debt agreements. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries.

In addition to the above financial covenants, Southern Union and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.

Covenants Related to Sunoco Logistics

Sunoco Logistics’ $1.50 billion credit facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 2.8 to 1 at December 31, 2013, as calculated in accordance with the credit agreements.

The $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2013 shall not be less than 1.00 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.12 to 1 and 0.88 to 1, respectively, at December 31, 2013.

Compliance With Our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2013.

Redeemable Preferred Units

12 Months Ended

Dec. 31, 2013

Preferred Units, Preferred Partners' Capital Account [Abstract]

Redeemable Preferred Units

REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with ETE’s acquisition of Regency’s general partner in 2010, ETE issued 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million, which were reflected as long-term liabilities in our consolidated balance sheet as of December 31, 2012. The Preferred Units were issued in a private placement at a stated price of $100 per unit and were entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit.

On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units. Prior to the Redemption, on March 28, 2013, ETE paid the holder of the Preferred Units $40 million in cash in exchange for the holder relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.

Prior to the April 1, 2013 Redemption, we recorded non-cash charges of approximately $9 million to increase the carrying value of the Preferred Units to the estimated fair value. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million as of December 31, 2012.

Preferred Units of Subsidiary

Holders may elect to convert Regency Preferred Units to Regency Common Units at any time. In July 2013, certain holders of the Regency Preferred Units exercised their right to convert an aggregate 2,459,017 Series A Preferred Units into Regency Common Units. Concurrent with this transaction, a gain of $26 million was recognized in other income, net, related to the embedded derivative and reclassified $41 million from the Regency Preferred Units into Regency Common Units. As of December 31, 2013, the remaining Regency Preferred Units were convertible into 2,050,854 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon. The Regency Preferred Units received fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of Regency’s common unit distributions. Holders can elect to convert Regency Preferred Units into Regency Common Units into common units at any time in accordance with the 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 January 1, 2012	4.4		$	71
Accretion to redemption value	N/A		2
Balance, December 31, 2012	4.4		$	73
Regency Preferred Units converted into Regency Common Units	(2.5	)	(41		)
Balance, December 31, 2013	1.9		$	32		⁽¹	⁾


⁽¹⁾	This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Equity

12 Months Ended

Dec. 31, 2013

Partners' Capital Notes [Abstract]

Equity

EQUITY:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2013, there were issued and outstanding 559.9 million Common Units representing an aggregate 99.48% 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, 2013, 2012 and 2011was as follows:



	Years Ended December 31,
	2013	2012	2011
Number of Common Units, beginning of period	559.9	445.9	445.9
Issuance of restricted Common Units under long-term incentive plan	—	—	—
Issuance of common units in connection with Southern Union Merger (See Note 3)	—	114.0	—
Number of Common Units, end of period	559.9	559.9	445.9

Common Unit Split and Repurchase Program

On December 23, 2013, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “Unit Split”). The Unit Split was completed on January 27, 2014. The Unit Split was effected by a distribution of one ETE Common Unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014.

In December 2013, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 1,695,200 ETE Common Units under this program through February 10, 2014.

Class D Units

On May 1, 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 1,500,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 1,500,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate of 1,540,000 Class D Units of ETE, which number of Class D Units includes an additional 40,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.

Under the terms of the Class D Unit Agreement, 30% of the Class D Units will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date.

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.

Sale of Common Units by ETP

The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):



Date	Number of ETP Common Units	Price per ETP Unit		Net Proceeds
April 2011	14.2	$	50.52	$	695
November 2011	15.2	44.67		660
July 2012	15.5	44.57		671
April 2013	13.8	48.05		657

Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility and/or to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes.

ETP’s Equity Distribution Program

From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.

In January 2013 and May 2013, ETP entered into equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the year ended December 31, 2013, ETP issued approximately 16.9 million ETP Common Units for $846 million, net of commissions of $9 million. Approximately $145 million of ETP Common Units remained available to be issued under the currently effective equity distribution agreement as of December 31, 2013.

ETP’s Equity Incentive Plan Activity

As discussed in Note 9, ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.

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 ETP Common Units. The registration statement covers the issuance of up to 5.8 million ETP Common Units under the DRIP.

During the years ended December 31, 2013, 2012 and 2011, aggregate distributions of approximately $109 million, $43 million and $15 million were reinvested under the DRIP resulting in the issuance in aggregate of approximately 3.7 million ETP Common Units. As of December 31, 2013, a total of 2.1 million ETP Common Units remain available to be issued under the existing registration statement.

ETP Class E Units

There are 8.9 million ETP Class E Units outstanding that are reported by ETP as treasury units. These ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other than the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a subsidiary of Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date.

ETP Class G Units

In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create the ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million ETP Class F Units issued in exchange for cash contributed by Sunoco to ETP immediately prior to or concurrent with the closing of the Sunoco Merger. The ETP Class F Units generally did not have any voting rights. The ETP Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries (other than Holdco) and available for distribution, up to a maximum of $3.75 per ETP Class F Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G Units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million, to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H Units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.

The ETP Class H Units are held by a subsidiary of ETE and therefore are reflected by ETP as treasury units in its consolidated financial statements.

Sale of Common Units by Regency

The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:



Date	Number of Regency Common Units ⁽¹⁾	Price per Regency Unit			Net Proceeds
May 2011	8.5	⁽¹		⁾	$	204
October 2011	11.5	$	20.92		232
March 2012	12.7	24.47			297


⁽¹⁾	Regency Units were issued in a private placement.

Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

In June 2012, Regency entered into an Equity Distribution Agreement with Citi under which Regency may offer and sell Regency Common Units, representing limited partner interests, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. Sales of these units, if any, made under the Regency Equity Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and Citi. Under the terms of this agreement, Regency may also sell Regency Common Units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of Regency Common Units to Citi as principal would be pursuant to the terms of a separate agreement between Regency and Citi. Regency intends to use the net proceeds from the sale of these units for general partnership purposes. As of December 31, 2013, Regency received net proceeds of $149 million from Regency Common Units issued pursuant to this Equity Distribution Agreement.

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. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.

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. As of December 31, 2013, we had no independent operations outside of our direct and indirect interests in ETP and Regency.

Our distributions declared during the years ended December 31, 2013, 2012 and 2011 are summarized as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 18, 2011	$	0.27000
March 31, 2011	May 6, 2011	May 19, 2011	0.28000
June 30, 2011	August 5, 2011	August 19, 2011	0.31250
September 30, 2011	November 4, 2011	November 18, 2011	0.31250
December 31, 2011	February 7, 2012	February 17, 2012	0.31250
March 31, 2012	May 4, 2012	May 18, 2012	0.31250
June 30, 2012	August 6, 2012	August 17, 2012	0.31250
September 30, 2012	November 6, 2012	November 16, 2012	0.31250
December 31, 2012	February 7, 2013	February 19, 2013	0.31750
March 31, 2013	May 6, 2013	May 17, 2013	0.32250
June 30, 2013	August 5, 2013	August 19, 2013	0.32750
September 30, 2013	November 4, 2013	November 19, 2013	0.33625
December 31, 2013	February 7, 2014	February 19, 2014	0.34625

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
December 31, 2010	February 7, 2011	February 14, 2011	$	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
September 30, 2011	November 4, 2011	November 14, 2011	0.89375
December 31, 2011	February 7, 2012	February 14, 2012	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375
June 30, 2012	August 6, 2012	August 14, 2012	0.89375
September 30, 2012	November 6, 2012	November 14, 2012	0.89375
December 31, 2012	February 7, 2013	February 14, 2013	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375
September 30, 2013	November 4, 2013	November 14, 2013	0.90500
December 31, 2013	February 7, 2014	February 14, 2014	0.92000

Following are ETP incentive distributions ETE has agreed to relinquish:


•	In conjunction with ETP’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.


•	In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.


•	As discussed in Note 3, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

In addition, the incremental distributions on the Class H Units, which are referred to in “ETP Class H Units” above, were intended to offset a portion of the incentive distribution relinquishments previously granted by ETE to ETP. In connection with the issuance of the ETP Class H Units, ETE and ETP also agreed to certain adjustments to the incremental distributions on the ETP Class H Units in order to ensure that the net impact of the incentive distribution relinquishments (a portion of which is variable) and the incremental distributions on the ETP Class H Units are fixed amounts for each quarter for which the incentive distribution relinquishments and incremental distributions on the ETP Class H Units are in effect.

In addition to the amounts above, in connection with the transfer of Trunkline LNG in February 2014, ETE agreed to relinquish incentive distributions of $50 million, $50 million, $45 million, and $35 million during the years ended December 31, 2016, 2017, 2018 and 2019, respectively.

Following is a summary of the net amounts by which these incentive distribution relinquishments and incremental distributions on ETP Class H Units would reduce the total distributions that would potentially be made to ETE in future quarters:



	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2014	$	26.50	$	26.50	$	26.50	$	26.50	$	106.00
2015	12.50		12.50		13.00		13.00		51.00
2016	18.00		18.00		18.00		18.00		72.00
2017	12.50		12.50		12.50		12.50		50.00
2018	11.25		11.25		11.25		11.25		45.00
2019	8.75		8.75		8.75		8.75		35.00

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
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	0.445
June 30, 2011	August 5, 2011	August 12, 2011	0.450
September 30, 2011	November 7, 2011	November 14, 2011	0.455
December 31, 2011	February 6, 2012	February 13, 2012	0.460
March 31, 2012	May 7, 2012	May 14, 2012	0.460
June 30, 2012	August 6, 2012	August 14, 2012	0.460
September 30, 2012	November 6, 2012	November 14, 2012	0.460
December 31, 2012	February 7, 2013	February 14, 2013	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465
September 30, 2013	November 4, 2013	November 14, 2013	0.470
December 31, 2013	February 7, 2014	February 14, 2014	0.475

In conjunction with Southern Union’s contributions of SUGS to Regency, ETE agreed to relinquish incentive distributions on the 31.4 million Regency Common Units issued for twenty-four months subsequent to the transaction closing.

Sunoco Logistics Quarterly Distributions of Available Cash

Distributions paid by Sunoco Logistics since the date of acquisition are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per Sunoco Logistics Common Unit
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000
September 30, 2013	November 8, 2013	November 14, 2013	0.6300
December 31, 2013	February 10, 2014	February 14, 2014	0.6625

Accumulated Other Comprehensive Income (Loss)

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



	December 31,
	2013			2012
Net losses on commodity related hedges	$	(4	)	$	(3	)
Available-for-sale securities	2			—
Foreign currency translation adjustment	(1		)	—
Actuarial gain (loss) related to pensions and other postretirement benefits	56			(10		)
Equity investments, net	8			(9		)
Subtotal	61			(22		)
Amounts attributable to noncontrolling interest	(52		)	10
Total AOCI included in partners’ capital, net of tax	$	9		$	(12	)

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):



	December 31,
	2013			2012
Net gains on commodity related hedges	$	—		$	2
Actuarial (gain) loss relating to pension and other postretirement benefits	(39		)	5
Total	$	(39	)	$	7

Unit-Based Compensation Plans

12 Months Ended

Dec. 31, 2013

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

Unit-Based Compensation Plans

UNIT-BASED COMPENSATION PLANS:

We, ETP, Sunoco Logistics and Regency have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 6,000,000 units. As of December 31, 2013, 5,693,789 units remain available to be awarded under the plan.

In December 2013, 1,540,000 Class D Units were granted to an ETE employee, Jaime Welch. Under the terms of the Class D Unit Agreement, 30% of the Class D Units granted to Welch will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. See further discussion at Note 8 to our consolidated financial statements.

During 2013, no awards were granted to ETE employees except the 1,540,000 Class D Units discussed above and 12,084 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.

During 2013, a total of 56,048 ETE Common Units vested, with a total fair value of $2.1 million as of the vesting date. As of December 31, 2013, excluding Class D units, a total of 65,980 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of less than $1 million in compensation over a weighted average period of 1.7 years. As of December 31, 2013, a total of 1,540,000 Class D Units granted to Mr. Welch remain outstanding, for which we expect to recognize a total of $37 million in compensation over a weighted average period of 3.5 years.

ETP Unit-Based Compensation Plans

Unit Grants

ETP has granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.” Under ETP’s equity incentive plans, ETP’s non-employee directors each receive grants with a five-year service vesting requirement.

Award Activity

The following table shows the activity of the ETP awards granted to employees and non-employee directors:



	Number of ETP Units		Weighted Average Grant-Date Fair Value Per ETP Unit
Unvested awards as of December 31, 2012	1.9		$	46.95
Awards granted	2.1		50.54
Awards vested	(0.6	)	45.62
Awards forfeited	(0.2	)	45.72
Unvested awards as of December 31, 2013	3.2		49.65

During the years ended December 31, 2013, 2012 and 2011, the weighted average grant-date fair value per unit award granted was $50.54, $43.93 and $48.35, respectively. The total fair value of awards vested was $26 million, $29 million and $27 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2013, a total of 3.2 million unit awards remain unvested, for which ETP expects to recognize a total of $116 million in compensation expense over a weighted average period of 2.1 years.

Sunoco Logistics Unit-Based Compensation Plan

Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.6 million Sunoco common units. As of December 31, 2013, a total of 0.6 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $21 million of expense over a weighted-average period of 2.8 years.

Related Party Awards

McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by an ETE officer, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such ETE officer. These rights include the economic benefits of ownership of these ETE units based on a five-year vesting schedule whereby the ETP officers vested in the ETE units at a rate of 20% per year. As these ETE units conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards were paid by ETP or ETE. As these units were outstanding prior to these awards, these awards did not represent an increase in the number of outstanding units of either ETP or ETE and were not dilutive to cash distributions per unit with respect to either ETP or ETE.

ETP recognized non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded to the ETP employees assuming no forfeitures. For the years ended December 31, 2013, 2012 and 2011, ETP recognized non-cash compensation expense, net of forfeitures, of less than $1 million, $1 million and $2 million, respectively, as a result of these awards. As of December 31, 2013, no rights related to ETE common units remain outstanding.

Regency Unit-Based Compensation Plans

Regency has the following awards outstanding as of December 31, 2013:


•	142,550 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $22.04 per unit option; and


•	982,242 Regency Phantom Units, with a weighted average grant date fair value of $23.16 per Phantom Unit.

Regency expects to recognize $19 million of compensation expense related to the Regency Phantom Units over a period of 3.3 years.

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:



	Years Ended December 31,
	2013			2012			2011
Current expense (benefit):
Federal	$	51		$	(3	)	$	(1	)
State	(1		)	6			17
Total	50			3			16
Deferred expense:
Federal	(14		)	41			—
State	57			10			1
Total	43			51			1
Total income tax expense from continuing operations	$	93		$	54		$	17

Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2013 and 2012 is as follows:



	December 31, 2013									December 31, 2012
	Corporate Subsidiaries⁽¹⁾			Partnership⁽²⁾			Consolidated			Corporate Subsidiaries⁽¹⁾			Partnership⁽²⁾		Consolidated
Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	(172	)	$	—		$	(172	)	$	(4	)	$	—	$	(4	)
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill	241			—			241			—			—		—
Nondeductible executive compensation	—			—			—			28			—		28
State income taxes (net of federal income tax effects)	31			10			41			9			2		11
Other	(16		)	(1		)	(17		)	19			—		19
Income tax from continuing operations	$	84		$	9		$	93		$	52		$	2	$	54

⁽¹⁾

Includes Holdco, Oasis Pipeline Company, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. The latter three entities were acquired in the Sunoco Merger. Holdco, which was formed via the Sunoco Merger and the Holdco Transaction (see Note 3), includes Sunoco and Southern Union and their subsidiaries. ETE held a 60% interest in Holdco until April 30, 2013. Subsequent to the Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of Holdco.


⁽²⁾	Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes.

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:



	December 31,
	2013			2012
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	217		$	270
Pension and other postretirement benefits	57			127
Long term debt	108			117
Other	104			290
Total deferred income tax assets	486			804
Valuation allowance	(74		)	(94		)
Net deferred income tax assets	412			710

Deferred income tax liabilities:
Properties, plants and equipment	(1,624		)	(2,026		)
Inventory	(302		)	(516		)
Investments in unconsolidated affiliates	(2,245		)	(1,543		)
Trademarks	(180		)	(192		)
Other	(45		)	(129		)
Total deferred income tax liabilities	(4,396		)	(4,406		)
Net deferred income tax liability	(3,984		)	(3,696		)
Less: current portion of deferred income tax assets (liabilities)	(119		)	(130		)
Accumulated deferred income taxes	$	(3,865	)	$	(3,566	)

The completion of the Southern Union Merger, Sunoco Merger and Holdco Transaction (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:



	December 31,
	2013			2012
Net deferred income tax liability, beginning of year	$	(3,696	)	$	(214	)
Southern Union acquisition	—			(1,428		)
Sunoco acquisition	—			(1,989		)
SUGS Contribution to Regency	(115		)	—
Tax provision (including discontinued operations)	(124		)	(62		)
Other	(49		)	(3		)
Net deferred income tax liability	$	(3,984	)	$	(3,696	)

Holdco and other corporate subsidiaries have gross federal net operating loss carryforwards of $216 million, all of which will expire in 2032. Holdco has $40 million of federal alternative minimum tax credits which do not expire. Holdco and other corporate subsidiaries have state net operating loss carryforward benefits of $101 million, net of federal tax, which expire between 2013 and 2032. The valuation allowance of $74 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco pre-acquisition periods.

The following table sets forth the changes in unrecognized tax benefits:



	Years Ended December 31,
	2013			2012			2011
Balance at beginning of year	$	27		$	2		$	2
Additions attributable to acquisitions	—			28			—
Additions attributable to tax positions taken in the current year	—			—			1
Additions attributable to tax positions taken in prior years	406			—			—
Settlements	—			—			—
Lapse of statute	(4		)	(3		)	(1		)
Balance at end of year	$	429		$	27		$	2

As of December 31, 2013, we have $425 million ($418 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $6 million ($5 million, net of federal tax) within the next twelve months due to settlement of certain positions.

Sunoco has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco’s 2004 through 2011 open statute years, Sunoco has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco is fully successful with its claims, it will receive tax refunds of approximately $372 million. However, due to the uncertainty surrounding the claims, a reserve of $372 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2013.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2013, we recognized interest and penalties of less than $1 million. At December 31, 2013, we have interest and penalties accrued of $6 million, net of tax.

In general, ETE and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2009, except Sunoco, Regency and Pueblo which are no longer subject to examination by the IRS for tax years prior to 2007 and Southern Union which is no longer subject to examination by the IRS for tax years prior to and 2004.

Sunoco has been examined by the IRS for the 2007 and 2008 tax years, however, the statutes remain open for both of these tax years due to carryback of net operating losses. Sunoco is currently under examination for the years 2009 through 2011, but due to the aforementioned carryback, such years also impact Sunoco’s tax liability for the years 2004 through 2008. With the exception of the claims regarding government incentive payments discussed above, all issues are resolved. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2013, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We will vigorously defend and believe Southern Union’s tax position will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to this tax position. Regency is also under examination by the IRS for the 2007 and 2008 tax years. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. The proposed adjustments with respect to Regency would not have a material impact upon our financial statements.

ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2013

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Audit

The FERC recently completed an audit of PEPL, a subsidiary of Southern Union, for the period from January 1, 2010 through December 31, 2011, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. An audit report was received in August 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.

Florida Gas Pipeline Relocation Costs

The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.

On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September, 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.

FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.

PEPL Holdings Guarantee of Collection

In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

NGL Pipeline Regulation

Lone Star has interests in NGL pipelines located in Texas and New Mexico. Lone Star commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the ICA and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect 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. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $151 million, $60 million and $29 million for the years ended December 31, 2013, 2012 and 2011, respectively, which include contingent rentals totaling $22 million and $6 million in 2013 and 2012, respectively. During the years ended December 31, 2013, and 2012, approximately $24 million and $4 million, respectively, of rental expense was recovered through related sublease rental income.

Future minimum lease commitments for such leases are:



Years Ending December 31:
2014	$	83
2015	81
2016	72
2017	68
2018	55
Thereafter	454
Future minimum lease commitments	813
Less: Sublease rental income	(57		)
Net future minimum lease commitments	$	756

ETP and Regency’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

Sunoco Litigation

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.

MTBE Litigation

Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of December 31, 2013, Sunoco is a defendant in seven cases, one of which was initiated by the State of New Jersey and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Six of these cases are venued in a multidistrict litigation (“MDL”) proceeding in a New York federal court. The most recently filed Puerto Rico action is expected to be transferred to the MDL. The New Jersey and Puerto Rico cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.

Fact discovery has concluded with respect to an initial set of fewer than 20 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Litigation Relating to the PVR Merger

Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of these cases name PVR, PVR GP and the current directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (iv) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL) in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606) and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB); and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania.

On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, completion of certain confirmatory discovery, class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.

The settlement will not affect any provisions of the merger agreement or the form or amount of consideration to be received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.

Other Litigation and Contingencies

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The parties agreed to settle the matter and executed a memorandum of understanding. On October 4, 2013, the Court approved the settlement and ordered the case dismissed with prejudice.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2013 and 2012, accruals of approximately $46 million and $42 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to 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, 2013 or 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Litigation Related to Incident at JJ’s Restaurant. On February 19, 2013, there was a natural gas explosion at JJ’s Restaurant located at 910 W. 48th Street in Kansas City, Missouri. Effective September 1, 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc. (“Laclede”), assumed any and all liability arising from this incident in ETP’s sale of the assets of MGE to Laclede.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The Attorney General is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the Attorney General requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s Vice Chairman, President and COO, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the Attorney General contends only would qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.

Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until March 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

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

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:


•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.


•	Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.


•	Currently operating Sunoco retail sites.


•	Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

•

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2013, Sunoco had been named as a PRP at 40 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.



	December 31,
	2013		2012
Current	$	47	$	46
Non-current	356		166
Total environmental liabilities	$	403	$	212

In 2013, we have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2013 and 2012, the Partnership recorded $41 million and $12 million, respectively, of expenditures related to environmental cleanup programs.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule was required by October 2013, and the Partnership believes it is in compliance.

On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.

Our pipeline operations are subject to regulation by the DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline operations located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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

Price Risk Management Assets And Liabilities

12 Months Ended

Dec. 31, 2013

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Price Risk Management Assets And Liabilities

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by segment.

ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, 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 we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales on its interstate transportation and storage 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 statement of operations.

ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in its midstream operations whereby its subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP may use derivatives in ETP’s NGL transportation and services operations to manage ETP’s storage facilities and the purchase and sale of purity NGLs.

Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to its transportation and storage operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading activities related to power and natural gas in its other operations which are also netted in cost of products sold. As a result of its trading activities and the use of derivative financial instruments in its 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 our 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 other 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.

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



	December 31, 2013			December 31, 2012
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,457,500		2014-2019	—		—
Basis Swaps IFERC/NYMEX ⁽¹⁾	(487,500	)	2014-2017	(30,980,000	)	2013-2014
Swing Swaps	1,937,500		2014-2016	—		—
Power (Megawatt):
Forwards	351,050		2014	19,650		2013
Futures	(772,476	)	2014	(1,509,300	)	2013
Options — Puts	(52,800	)	2014	—		—
Options — Calls	103,200		2014	1,656,400		2013
Crude (Bbls) – Futures	103,000		2014	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	570,000		2014	150,000		2013
Swing Swaps IFERC	(9,690,000	)	2014-2016	(83,292,500	)	2013
Fixed Swaps/Futures	(8,195,000	)	2014-2015	27,077,500		2013
Forward Physical Contracts	5,668,559		2014-2015	11,689,855		2013-2014
Natural Gas Liquid (Bbls) – Forwards/Swaps	(280,000	)	2014	(30,000	)	2013
Refined Products (Bbls) – Futures	(1,133,600	)	2014	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,352,500	)	2014	(18,655,000	)	2013
Fixed Swaps/Futures	(50,530,000	)	2014	(44,272,500	)	2013
Hedged Item — Inventory	50,530,000		2014	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,825,000	)	2014	—		—
Fixed Swaps/Futures	(12,775,000	)	2014	(8,212,500	)	2013
Natural Gas Liquid (Bbls) – Forwards/Swaps	(780,000	)	2014	(930,000	)	2013
Refined Products (Bbls) – Futures	—		—	(98,000	)	2013
Crude (Bbls) – Futures	(30,000	)	2014	—		—


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

We expect gains of $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.

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, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	24,455,000	2014-2015	8,395,000	2013-2014
Propane (Gallons) — Forwards/Swaps	52,122,000	2014-2015	3,318,000	2013
NGLs (Barrels) — Forwards/Swaps	438,000	2014	243,000	2013-2014
WTI Crude Oil (Barrels) — Forwards/Swaps	521,000	2014	356,000	2014

As of December 31, 2013, Regency has less than $1 million in net hedging gains in AOCI, all of which will be amortized to earnings over the next 3 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, 2013, none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

December 31,
2013

December 31,
2012

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

—

500

ETP

July 2013⁽²⁾

Forward starting to pay a fixed rate of 4.03% and receive a floating rate

—

400

ETP

July 2014⁽²⁾

Forward starting to pay a fixed rate of 4.25% and receive a floating rate

400

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

ETP

June 2021

Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%

400

—

ETP

February 2023

Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%

400

—

Southern Union⁽³⁾

November 2016

Pay a fixed rate of 2.97% and receive a floating rate

—

Southern Union⁽³⁾

November 2021

Pay a fixed rate of 3.801% and receive a floating rate

275

450


⁽¹⁾	Floating rates are based on 3-month LIBOR.


⁽²⁾	Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory terminate date the same as the effective date. During the year ended December 31, 2013, ETP settled $400 million of ETP’s forward-starting interest rate swaps that had an effective date of July 2013.


⁽³⁾	In connection with the Panhandle Merger, Southern Union’s interest rate swaps outstanding were assumed by Panhandle.

Credit Risk

Credit Risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implement the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure with a single counterparty or affiliated group of counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

ETP has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds 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.

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of December 31, 2013 would be $4 million, which would be reduced by less than $1 million, due to the netting feature.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2013 and 2012:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2013		December 31, 2012		December 31, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	3	$	8	$	(18	)	$	(10	)
	3		8		(18		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	227	$	110	$	(209	)	$	(116	)
Commodity derivatives	43		40		(48		)	(44		)
Current assets held for sale	—		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		—			(9		)
Interest rate derivatives	47		55		(95		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(19		)	(25		)
	317		207		(371		)	(429		)
Total derivatives	$	320	$	215	$	(389	)	$	(439	)

In addition to the above derivatives, $7 million of option premiums were included in price risk management liabilities as of December 31, 2012.

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2013			December 31, 2012			December 31, 2013			December 31, 2012
Derivatives in offsetting agreements:
OTC contracts	Price risk management assets (liabilities)	$	42		$	28		$	(38	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	264			149			(318		)	(228		)
		306			177			(356		)	(255		)
Offsetting agreements:
Collateral paid to OTC counterparties	Other current assets	—			—			—			2
Counterparty netting	Price risk management assets (liabilities)	(36		)	(25		)	36			25
Payments on margin deposit	Other current assets	(1		)	—			55			59
		(37		)	(25		)	91			86
Net derivatives with offsetting agreements		269			152			(265		)	(169		)
Derivatives without offsetting agreements		51			63			(124		)	(270		)
Total derivatives		$	320		$	215		$	(389	)	$	(439	)

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Years Ended December 31,
	2013			2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(1	)	$	8	$	6
Total	$	(1	)	$	8	$	6



	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,
		2013		2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	4	$	14	$	19
Total		$	4	$	14	$	19



	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,
		2013		2012		2011
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	8	$	54	$	34
Total		$	8	$	54	$	34



	Location of Gain/ (Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2013			2012			2011
Derivatives in cash flow hedging relationships:
Commodity derivatives – Trading	Cost of products sold	$	(11	)	$	(7	)	$	(30	)
Commodity derivatives – Non-trading	Cost of products sold	(21		)	26			9
Commodity derivatives – Non-trading	Deferred gas purchases	(3		)	(26		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	53			(19		)	(78		)
Embedded derivatives	Other income (expense)	6			14			18
Total		$	24		$	(12	)	$	(81	)

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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

Retirement Benefits

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Retirement Benefits

RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all employees, including those of ETP and Regency. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $47 million, $30 million and $17 million to the 401(k) savings plan for the years ended December 31, 2013, 2012 and 2011, respectively.

Pension and Other Postretirement Benefit Plans

Southern Union

Southern Union postretirement benefits expense for the year ended December 31, 2013 reflected the impact of changes Southern Union adopted as of September 30, 2013 to change its retiree medical benefits program effective January 1, 2014 which placed all retirees on a common 75% employer/25% retiree cost sharing platform, subject to caps on annual average per capita expenditures by Southern Union. Postretirement benefits expense for the year ended December 31, 2012 reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated. Southern Union previously had postretirement health care and life insurance plans (“other postretirement plans”) that covered substantially all employees.

In 2012, Southern Union had funded non-contributory defined benefit pension plans that covered substantially all employees of Southern Union’s distribution operations. These operations were sold in 2013, see Note 3. Normal retirement age is 65, but certain plan provisions allowed for earlier retirement. Pension benefits were calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

Sunoco

Sunoco has both funded and unfunded noncontributory defined benefit pension plans. Sunoco also has plans which provide health care benefits for substantially all of its current retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are shared by Sunoco and its retirees. Prior to the Sunoco Merger on October 5, 2012, pension benefits under Sunoco’s defined benefit plans were frozen for most of the participants in these plans at which time Sunoco instituted a discretionary profit-sharing contribution on behalf of these employees in its defined contribution plan. Postretirement medical benefits were also phased down or eliminated for all employees retiring after July 1, 2010. Sunoco has established a trust for its postretirement benefit liabilities by making a tax-deductible contribution of approximately $200 million and restructuring the retiree medical plan to eliminate Sunoco’s liability beyond this funded amount. The retiree medical plan change eliminated substantially all of Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:



	December 31, 2013									December 31, 2012
	Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	1,117		$	78		$	296		$	1,257		$	359
Service cost	3			—			—			3			1
Interest cost	33			2			6			15			3
Amendments	—			—			2			—			17
Benefits paid, net	(99		)	(16		)	(26		)	(71		)	(8		)
Curtailments	—			—			—			—			(80		)
Actuarial (gain) loss and other	(74		)	(3		)	(14		)	(9		)	4
Settlements	(95		)	—			—			—			—
Dispositions	(253		)	—			(41		)	—			—
Benefit obligation at end of period	$	632		$	61		$	223		$	1,195		$	296

Change in plan assets:
Fair value of plan assets at beginning of period	906			—			312			941			306
Return on plan assets and other	43			—			17			22			5
Employer contributions	—			—			8			14			9
Benefits paid, net	(99		)	—			(26		)	(71		)	(8		)
Settlements	(95		)	—			—			—			—
Dispositions	(155		)	—			(27		)	—			—
Fair value of plan assets at end of period	$	600		$	—		$	284		$	906		$	312

Amount underfunded (overfunded) at end of period	$	32		$	61		$	(61	)	$	289		$	(16	)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	86		$	—		$	59
Current liabilities	—			(9		)	(2		)	(15		)	(2		)
Non-current liabilities	(32		)	(52		)	(23		)	(274		)	(41		)
	$	(32	)	$	(61	)	$	61		$	(289	)	$	16

Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain	$	(86	)	$	(4	)	$	(25	)	$	(1	)	$	(1	)
Prior service cost	—			—			18			—			16
	$	(86	)	$	(4	)	$	(7	)	$	(1	)	$	15

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:



	December 31, 2013					December 31, 2012
	Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Projected benefit obligation	$	632	$	61	N/A	$	1,195	N/A
Accumulated benefit obligation	632		61		223	1,179		$	225
Fair value of plan assets	600		—		284	906		185

Components of Net Periodic Benefit Cost



	December 31, 2013						December 31, 2012
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	3		$	—		$	3		$	1
Interest cost	35			6			15			3
Expected return on plan assets	(54		)	(9		)	(21		)	(5		)
Prior service cost amortization	—			1			—			—
Actuarial loss amortization	2			—			—			—
Special termination benefits charge	—			—			2			—
Curtailment recognition ⁽¹⁾	—			—			—			(15		)
Settlements	(2		)	—			—			—
	(16		)	(2		)	(1		)	(16		)
Regulatory adjustment ⁽²⁾	5			—			9			2
Net periodic benefit cost	$	(11	)	$	(2	)	$	8		$	(14	)

⁽¹⁾

Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

⁽²⁾

Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operation. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:



	December 31, 2013				December 31, 2012
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	4.65	%	2.33	%	3.41	%	2.39	%
Rate of compensation increase	N/A		N/A		3.17	%	N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:



	December 31, 2013				December 31, 2012
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.50	%	2.68	%	2.37	%	2.43	%
Expected return on assets:
Tax exempt accounts	7.50	%	6.95	%	7.63	%	7.00	%
Taxable accounts	N/A		4.42	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		3.02	%	N/A

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union’s and Sunoco’s other postretirement benefit plans are shown in the table below:



	December 31,
	2013		2012
Health care cost trend rate assumed for next year	7.57	%	7.78	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.42	%	5.32	%
Year that the rate reaches the ultimate trend rate	2018		2018

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Southern Union plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its pension plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 70%, fixed income of 15% to 35%, alternative assets of 10% to 35% and cash of 0% to 10%. To achieve diversity within its other postretirement plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of 0% to 10%.

The investment strategy of Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns, maintain a sufficient funded status of the plans and limit required contributions. Sunoco has targeted the following asset allocations: equity of 35%, fixed income of 55%, and private equity investments of 10%. Sunoco anticipates future shifts in targeted asset allocations from equity securities to fixed income securities if funding levels improve due to asset performance or Sunoco contributions.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:



	Fair Value as of		Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	December 31, 2013		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	12	$	12	$	—	$	—
Mutual funds ⁽¹⁾	368		—		281		87
Fixed income securities	220		—		220		—
Total	$	600	$	12	$	501	$	87


⁽¹⁾	Primarily comprised of approximately 66% equities, 10% fixed income securities, and 24% in other investments as of December 31, 2013.



	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	25	$	25	$	—	$	—
Mutual funds ⁽¹⁾	516		—		433		83
Fixed income securities	354		—		354		—
Multi-strategy hedge funds ⁽²⁾	11		—		11		—
Total	$	906	$	25	$	798	$	83


⁽¹⁾	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.

⁽²⁾

Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets. These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:



	Fair Value as of		Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	December 31, 2013		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	10	$	10	$	—	$	—
Mutual funds ⁽¹⁾	130		112		18		—
Fixed income securities	144		—		144		—
Total	$	284	$	122	$	162	$	—


⁽¹⁾	Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013.

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.



	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	7	$	7	$	—	$	—
Mutual funds ⁽¹⁾	147		126		21		—
Fixed income securities	158		—		158		—
Total	$	312	$	133	$	179	$	—


⁽¹⁾	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.

Contributions

We expect to contribute approximately $23 million to pension plans and approximately $18 million to other postretirement plans in 2014. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Southern Union’s and Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:



	Pension Benefits
Years	Funded Plans		Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2014	$	82	$	9	$	31
2015	77		9		29
2016	67		8		28
2017	61		7		26
2018	56		7		24
2019 – 2023	220		23		87

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Southern Union does not expect to receive any Medicare Part D subsidies in any future periods.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2013
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS: The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements. In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15). In addition, subsidiaries of ETE recorded sales with affiliates of $1.44 billion, $189 million and $1.05 billion during the years ended December 31, 2013, 2012 and 2011, respectively.

- Definition

The entire disclosure for related party transactions. 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 + Details

Reportable Segments

12 Months Ended

Dec. 31, 2013

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the acquisition of Trunkline LNG in February 2014, our reportable segments were re-evaluated and currently reflect the following reportable segments, which conduct their business exclusively in the United States of America, as follows:


•	Investment in ETP, including the consolidated operations of ETP;


•	Investment in Regency, including the consolidated operations of Regency;


•	Investment in Trunkline LNG, including the consolidated operations of Trunkline LNG; and


•	Corporate and Other, including the following:


◦	activities of the Parent Company; and


◦	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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

We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership. Based on the change in our segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.

Eliminations in the tables below include the following:


•	ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.


•	ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Because the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.

•

ETP’s Segment Adjusted EBITDA reflected the results of Trunkline LNG prior to the Trunkline LNG Transaction, which was effective January 1, 2014. The Investment in Trunkline LNG segment reflected the results of operations of Trunkline LNG. Consequently, the results of operations of Trunkline LNG were reflected in two segments beginning March 26, 2012. Therefore, the results of Trunkline LNG were included in eliminations beginning March 26, 2012.



	Years Ended December 31,
	2013			2012			2011
Revenues:
Investment in ETP:
Revenues from external customers	$	46,210		$	15,671		$	6,761
Intersegment revenues	129			31			38
	46,339			15,702			6,799
Investment in Regency:
Revenues from external customers	2,404			1,986			1,426
Intersegment revenues	117			14			8
	2,521			2,000			1,434
Investment in Trunkline LNG:
Revenues from external customers	216			166			—
Intersegment revenues	—			—			—
	216			166			—
Adjustments and Eliminations:	(741		)	(904		)	(43		)
Total revenues	$	48,335		$	16,964		$	8,190
Costs of products sold:
Investment in ETP	$	41,204		$	12,266		$	4,175
Investment in Regency	1,793			1,387			1,013
Investment in Trunkline LNG	—			—			—
Adjustments and Eliminations	(443		)	(565		)	(19		)
Total costs of products sold	$	42,554		$	13,088		$	5,169
Depreciation and amortization:
Investment in ETP	1,032			656			405
Investment in Regency	287			252			169
Investment in Trunkline LNG	39			30			—
Corporate and Other	16			14			12
Adjustments and Eliminations	(61		)	(81		)	—
Total depreciation and amortization	$	1,313		$	871		$	586



	Years Ended December 31,
	2013			2012			2011
Equity in earnings of unconsolidated affiliates:
Investment in ETP	$	172		$	142		$	26
Investment in Regency	135			105			120
Adjustments and Eliminations	(71		)	(35		)	(29		)
Total equity in earnings of unconsolidated affiliates	$	236		$	212		$	117



	Years Ended December 31,
	2013			2012			2011
Segment Adjusted EBITDA:
Investment in ETP	$	3,953		$	2,744		$	1,781
Investment in Regency	608			517			420
Investment in Trunkline LNG	187			135			—
Corporate and Other	(43		)	(52		)	(29		)
Adjustments and Eliminations	(338		)	(239		)	(41		)
Total Segment Adjusted EBITDA	4,367			3,105			2,131
Depreciation and amortization	(1,313		)	(871		)	(586		)
Interest expense, net of interest capitalized	(1,221		)	(1,018		)	(740		)
Bridge loan related fees	—			(62		)	—
Gain on deconsolidation of Propane Business	—			1,057			—
Gain on sale of AmeriGas common units	87			—			—
Goodwill impairment	(689		)	—			—
Gains (losses) on interest rate derivatives	53			(19		)	(78		)
Non-cash unit-based compensation expense	(61		)	(47		)	(42		)
Unrealized gains on commodity risk management activities	48			10			7
Losses on extinguishments of debt	(162		)	(123		)	—
LIFO valuation adjustments	3			(75		)	—
Adjusted EBITDA related to discontinued operations	(76		)	(99		)	(23		)
Adjusted EBITDA related to unconsolidated affiliates	(727		)	(647		)	(231		)
Equity in earnings of unconsolidated affiliates	236			212			117
Non-operating environmental remediation	(168		)	—			—
Other, net	(2		)	14			(7		)
Income from continuing operations before income tax expense	$	375		$	1,437		$	548



	December 31,
	2013			2012			2011
Total assets:
Investment in ETP	$	43,702		$	43,230		$	15,519
Investment in Regency	8,782			8,123			5,568
Investment in Trunkline LNG	1,338			1,917			—
Corporate and Other	720			707			470
Adjustments and Eliminations	(4,212		)	(5,073		)	(660		)
Total	$	50,330		$	48,904		$	20,897



	Years Ended December 31,
	2013			2012			2011
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	2,455		$	3,049		$	1,484
Investment in Regency	1,034			560			406
Investment in Trunkline LNG	2			4			—
Adjustments and Eliminations	(2		)	(128		)	—
Total	$	3,489		$	3,485		$	1,890



	December 31,
	2013			2012			2011
Advances to and investments in affiliates:
Investment in ETP	$	4,436		$	3,502		$	201
Investment in Regency	2,097			2,214			1,925
Adjustments and Eliminations	(2,519		)	(979		)	(629		)
Total	$	4,014		$	4,737		$	1,497

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

Investment in ETP



	Years Ended December 31,
	2013		2012		2011
Intrastate Transportation and Storage	$	2,250	$	2,012	$	2,398
Interstate Transportation and Storage	1,270		1,109		447
Midstream	1,307		1,757		1,082
NGL Transportation and Services	2,063		619		363
Investment in Sunoco Logistics	16,480		3,109		—
Retail Marketing	21,004		5,926		—
All Other	1,965		1,170		2,509
Total revenues	46,339		15,702		6,799
Less: Intersegment revenues	129		31		38
Revenues from external customers	$	46,210	$	15,671	$	6,761

Investment in Regency



	Years Ended December 31,
	2013		2012		2011
Gathering and Processing	$	2,287	$	1,797	$	1,226
Natural Gas Transportation	1		1		1
Contract Services	215		183		190
Corporate and others	18		19		17
Total revenues	2,521		2,000		1,434
Less: Intersegment revenues	117		14		8
Revenues from external customers	$	2,404	$	1,986	$	1,426

Investment in Trunkline LNG

Trunkline LNG’s revenues of $216 million for the year ended December 31, 2013 and $166 million for the period from March 26, 2012 to December 31, 2012 were related to LNG terminalling.

- 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 Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-Paragraph 41
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9031-108599

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

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 ETC OLP business is seasonal due to the operations of ET Fuel System and the HPL System. We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.



	Quarters Ended
	March 31		June 30		September 30		December 31			Total Year
2013:
Revenues	$	11,179	$	12,063	$	12,486	$	12,607		$	48,335
Gross margin	1,372		1,498		1,422		1,489			5,781
Operating income (loss)	531		644		529		(153		)	1,551
Net income (loss)	322		338		356		(701		)	315
Limited Partners’ interest in net income (loss)	90		127		150		(171		)	196
Basic net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
Diluted net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35

The three months ended December 31, 2013 was impacted by ETP’s recognition of a goodwill impairment of $689 million.



	Quarters Ended
	March 31		June 30		September 30			December 31		Total Year
2012:
Revenues	$	1,669	$	1,875	$	2,107		$	11,313	$	16,964
Gross margin	654		916		876			1,430		3,876
Operating income	183		367		358			452		1,360
Net income (loss)	961		75		(34		)	272		1,274
Limited Partners’ interest in net income	166		53		35			48		302
Basic net income per limited partner unit	$	0.37	$	0.10	$	0.06		$	0.09	$	0.57
Diluted net income per limited partner unit	$	0.36	$	0.10	$	0.06		$	0.09	$	0.57

Supplemental Financial Statement Information

12 Months Ended

Dec. 31, 2013

Supplemental Financial Statement Information

Supplemental Financial Statement Information

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS



	December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8		$	9
Accounts receivable from related companies	5			11
Other current assets	—			3
Total current assets	13			23
ADVANCES TO AND INVESTMENTS IN AFFILIATES	3,841			6,094
INTANGIBLE ASSETS, net	14			19
NOTE RECEIVABLE FROM AFFILIATE	—			166
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	41			56
Total assets	$	3,918		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	11			15
Interest payable	24			48
Price risk management liabilities	—			5
Accrued and other current liabilities	3			1
Current maturities of long-term debt	—			4
Total current liabilities	38			74
LONG-TERM DEBT, less current maturities	2,801			3,840
PREFERRED UNITS	—			331
OTHER NON-CURRENT LIABILITIES	1			9

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner	(3		)	—
Limited Partners – Common Unitholders (559,923,300 and 559,911,216 units authorized, issued and outstanding at December 31, 2013 and 2012, respectively)	1,066			2,125
Class D Units (1,540,000 units authorized, issued and outstanding at December 31, 2013)	6			—
Accumulated other comprehensive income (loss)	9			(12		)
Total partners’ capital	1,078			2,113
Total liabilities and partners’ capital	$	3,918		$	6,367

STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2013			2012			2011
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(56	)	$	(53	)	$	(30	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(210		)	(235		)	(164		)
Bridge loan related fees	—			(62		)	—
Equity in earnings of unconsolidated affiliates	617			666			509
Gains (losses) on interest rate derivatives	9			(15		)	—
Loss on extinguishment of debt	(157		)	—			—
Other, net	(8		)	(4		)	(5		)
INCOME BEFORE INCOME TAXES	195			297			310
Income tax benefit	(1		)	(7		)	—
NET INCOME	196			304			310
GENERAL PARTNER’S INTEREST IN NET INCOME	—			2			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	196		$	302		$	309

STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2013			2012			2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	768		$	555		$	469
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	—			(1,113		)	—
Proceeds from Holdco Transaction	1,332			—			—
Contributions to affiliates	(8		)	(487		)	—
Note receivable from affiliate	—			(221		)	—
Payments received on note receivable from affiliate	166			55			—
Net cash provided by (used in) investing activities	1,490			(1,766		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,080			2,108			92
Principal payments on debt	(3,235		)	(162		)	(20		)
Distributions to partners	(733		)	(666		)	(526		)
Redemption of Preferred Units	(340		)	—			—
Debt issuance costs	(31		)	(78		)	(24		)
Net cash provided by (used in) financing activities	(2,259		)	1,202			(478		)
DECREASE IN CASH AND CASH EQUIVALENTS	(1		)	(9		)	(9		)
CASH AND CASH EQUIVALENTS, beginning of period	9			18			27
CASH AND CASH EQUIVALENTS, end of period	$	8		$	9		$	18

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

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Contributions In Aid Of Construction Costs Policy Text Block

Contributions in Aid of Construction Cost

Accrued and Other Current Liabilities Policy [Text Block]

Environmental Costs, Policy [Policy Text Block]

Environmental Remediation

Equity and Cost Method Investments, Policy [Policy Text Block]

Advances to and Investments in Affiliates

Use of Estimates

Revenue Recognition

Investment in ETP

Investment in Regency

Regulatory Accounting - Regulatory Assets and Liabilities

Regulatory Accounting – Regulatory Assets and Liabilities

Cash, Cash Equivalents and Supplemental Cash Flow Information

Accounts Receivable

Inventories

Exchanges

Property, Plant and Equipment

Goodwill

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

Intangible Assets

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization.

Asset Retirement Obligation

Below is a schedule of AROs by entity recorded as other non-current liabilities in ETP’s consolidated balance sheet:



	December 31,
	2013		2012
Southern Union	$	55	$	46
Sunoco	84		53
Sunoco Logistics	41		41
	$	180	$	140

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.

Shipping and Handling Costs

Costs and Expenses

Issuances of Subsidiary Units

Income Taxes

Accounting for Derivative Instruments and Hedging Activities

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.

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Pensions and Other Postretirement Benefit Plans

Allocation of Income (Loss)

Allocation of Income

Operations And Organization (Tables)

12 Months Ended

Dec. 31, 2013

Operations And Organization [Abstract]

Schedule Of Equity Interests

At December 31, 2013, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:



	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	49.6	26.3
ETP Class H units	50.2	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

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

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Schedule of Shipping and Handling Cost [Text Block]

Shipping and Handling Costs



	Years Ended December 31,
	2013		2012		2011
Shipping and handling costs – recorded in operating expenses	$	28	$	25	$	40

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill

Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities

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



	Years Ended December 31,
	2013			2012			2011
Accounts receivable	$	(556	)	$	267		$	6
Accounts receivable from related companies	64			(9		)	(24		)
Inventories	(254		)	(258		)	51
Exchanges receivable	(8		)	14			1
Other current assets	(81		)	597			(51		)
Other non-current assets, net	(23		)	(129		)	7
Accounts payable	541			(989		)	21
Accounts payable to related companies	(140		)	92			6
Exchanges payable	128			—			2
Accrued and other current liabilities	192			(159		)	84
Other non-current liabilities	147			26			—
Price risk management assets and liabilities, net	(159		)	(3		)	55
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(149	)	$	(551	)	$	158

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,
	2013			2012		2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	226		$	420	$	226
Net gains (losses) from subsidiary common unit transactions	$	(384	)	$	80	$	153
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	—		$	1,123	$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with Southern Union Merger (see Note 3)	$	—		$	2,354	$	—
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—		$	6,658	$	4
Subsidiary issuance of Common Units in connection with certain acquisitions	$	—		$	2,295	$	3
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,256		$	997	$	728
Cash paid for income taxes	$	58		$	23	$	27

Schedule of Inventory

Inventories consisted of the following:



	December 31,
	2013		2012
Natural gas and NGLs	$	523	$	338
Crude oil	488		418
Refined products	597		572
Appliances, parts and fittings and other	199		194
Total inventories	$	1,807	$	1,522

Other Current Assets

Other current assets consisted of the following:



	December 31,
	2013		2012
Deposits paid to vendors	$	49	$	41
Prepaid and other	263		270
Total other current assets	$	312	$	311

Property, Plant and Equipment

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



	December 31,
	2013			2012
Land and improvements	$	881		$	553
Buildings and improvements (5 to 45 years)	939			692
Pipelines and equipment (5 to 83 years)	21,494			19,505
Natural gas and NGL storage facilities (5 to 46 years)	1,083			1,057
Bulk storage, equipment and facilities (2 to 83 years)	1,933			1,745
Tanks and other equipment (5 to 40 years)	1,697			1,194
Retail equipment (3 to 99 years)	450			258
Vehicles (1 to 25 years)	156			154
Right of way (20 to 83 years)	2,190			2,134
Furniture and fixtures (2 to 25 years)	51			67
Linepack	118			118
Pad gas	52			58
Other (1 to 48 years)	708			880
Construction work-in-process	2,165			1,973
	33,917			30,388
Less – Accumulated depreciation	(3,235		)	(2,104		)
Property, plant and equipment, net	$	30,682		$	28,284

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,
	2013		2012		2011
Depreciation expense ⁽¹⁾	$	1,128	$	801	$	531
Capitalized interest, excluding AFUDC	$	43	$	99	$	13

Schedule of Goodwill

Changes in the carrying amount of goodwill were as follows:



	Investment in ETP			Investment in Regency		Corporate, Other and Eliminations			Total
Balance, December 31, 2011	$	1,220		$	790	$	29		$	2,039
Goodwill acquired ⁽¹⁾	5,138			337		(328		)	5,147
Goodwill sold in deconsolidation of ETP Propane Business	(619		)	—		—			(619		)
Goodwill allocated to the disposal group	(133		)	—		—			(133		)
Balance, December 31, 2012	5,606			1,127		(299		)	6,434
Goodwill acquired	156			—		—			156
Deconsolidation of SUGS ⁽¹⁾	(337		)	—		337			—
Goodwill impairment	(689		)	—		—			(689		)
Other	(7		)	—		—			(7		)
Balance, December 31, 2013	$	4,729		$	1,127	$	38		$	5,894

Components And Useful Lives Of Intangibles And Other Assets

Components and useful lives of intangible assets were as follows:



	December 31, 2013					December 31, 2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	2,135	$	(264	)	$	2,032	$	(150	)
Trade names (20 years)	66		(12		)	66		(8		)
Patents (9 years)	48		(6		)	48		(1		)
Other (10 to 15 years)	7		(4		)	4		(1		)
Total amortizable intangible assets	2,256		(286		)	2,150		(160		)
Non-amortizable intangible assets:
Trademarks	294		—			301		—
Total intangible assets	$	2,550	$	(286	)	$	2,451	$	(160	)

Aggregate Amortization Expense Of Intangibles And Other Assets

Aggregate amortization expense of intangibles assets was as follows:



	Years Ended December 31,
	2013		2012		2011
Reported in depreciation and amortization	$	120	$	70	$	55

Estimated Aggregate Amortization Expense

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



Years Ending December 31:
2014	$	123
2015	123
2016	123
2017	123
2018	122

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,
	2013		2012
Unamortized financing costs (3 to 30 years)	$	167	$	152
Regulatory assets	86		93
Deferred charges	144		140
Restricted funds	378		—
Other	147		148
Total other non-current assets, net	$	922	$	533

Schedule of Asset Retirement Obligations [Table Text Block]



	December 31,
	2013		2012
Southern Union	$	55	$	46
Sunoco	84		53
Sunoco Logistics	41		41
	$	180	$	140

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	December 31,
	2013		2012
Interest payable	$	357	$	334
Customer advances and deposits	142		61
Accrued capital expenditures	260		427
Accrued wages and benefits	173		250
Taxes payable other than income taxes	211		208
Income taxes payable	4		41
Deferred income taxes	119		130
Other	412		303
Total accrued and other current liabilities	$	1,678	$	1,754

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis



	Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	47		$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	8			1			7			—
Fixed Swaps/Futures	203			201			2			—
NGLs — Forwards/Swaps	7			5			2			—
Power — Forwards	3			—			3			—
Refined Products — Futures	5			5			—			—
Total commodity derivatives	231			217			14			—
Total assets	$	278		$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)	—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—			—
Swing Swaps IFERC	(6		)	—			(6		)	—
Fixed Swaps/Futures	(206		)	(201		)	(5		)	—
Forward Physical Contracts	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(9		)	(5		)	(4		)	—
Power — Forwards	(1		)	—			(1		)	—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(233		)	(215		)	(18		)	—
Total liabilities	$	(347	)	$	(215	)	$	(113	)	$	(19	)



	Fair Value Measurements at December 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	55		$	—		$	55		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	98			94			4			—
Options — Calls	3			—			3			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Swaps	2			1			1			—
Power:
Forwards	27			—			27			—
Futures	1			1			—			—
Options — Calls	2			—			2			—
Refined Products – Futures	5			1			4			—
Total commodity derivatives	156			108			48			—
Total assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products – Futures	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)

Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block]

The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:



	Unobservable Input	December 31, 2013
Embedded derivatives in the Regency Preferred Units	Credit Spread	4.16	%
	Volatility	23.71	%

Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis



Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Redemption of Preferred Units	340
Net unrealized gains included in other income (expense)	6
Balance, December 31, 2013	$	(19	)

Acquisitions and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]



	Years Ended December 31,
	2013		2012
Revenue from discontinued operations	$	415	$	324
Net loss of discontinued operations, excluding effect of taxes and overhead allocations	65		43

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:



	Sunoco⁽¹⁾		Southern Union⁽²⁾
Current assets	$	7,312	$	556
Property, plant and equipment	6,686		6,242
Goodwill	2,641		2,497
Intangible assets	1,361		55
Investments in unconsolidated affiliates	240		2,023
Note receivable	821		—
Other assets	128		163
	19,189		11,536

Current liabilities	4,424		1,348
Long-term debt obligations, less current maturities	2,879		3,120
Deferred income taxes	1,762		1,419
Other non-current liabilities	769		284
Noncontrolling interest	3,580		—
	13,414		6,171
Total consideration	5,775		5,365
Cash received	2,714		37
Total consideration, net of cash received	$	3,061	$	5,328


⁽¹⁾	Includes amounts recorded with respect to Sunoco Logistics.


⁽²⁾	Includes ETP’s acquisition of Citrus.

Pro Forma Results Of Operations

Pro Forma Results of Operations



	Years Ended December 31,
	2012		2011
Revenues	$	40,398	$	37,560
Net income	868		865
Net income attributable to partners	866		863
Basic net income per Limited Partner unit	$	1.55	$	1.54
Diluted net income per Limited Partner unit	$	1.55	$	1.54

The pro forma consolidated results of operations include adjustments to:


•	include the results of Lone Star beginning January 1, 2010 and Southern Union and Sunoco beginning January 1, 2011;


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

•include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price.

- Definition

Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

+ References + Details

Advances to and Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2013

Investment In Affiliates [Abstract]

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

Summarized Financial Information



	December 31,
	2013		2012
Current assets	$	1,028	$	945
Property, plant and equipment, net	10,778		10,979
Other assets	2,664		2,677
Total assets	$	14,470	$	14,601

Current liabilities	$	1,039	$	1,662
Non-current liabilities	8,139		7,024
Equity	5,292		5,915
Total liabilities and equity	$	14,470	$	14,601



	Years Ended December 31,
	2013		2012		2011
Revenue	$	4,695	$	4,492	$	3,784
Operating income	1,197		863		928
Net income	699		491		536

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2013

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,
	2013		2012			2011
Income from continuing operations	$	282	$	1,383		$	531
Less: Income from continuing operations attributable to noncontrolling interest	99		1,070			221
Income from continuing operations, net of noncontrolling interest	183		313			310
Less: General Partner’s interest in income from continuing operations	—		1			1
Income from continuing operations available to Limited Partners	$	183	$	312		$	309
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	560.9		533.4			445.9
Basic income from continuing operations per Limited Partner unit	$	0.33	$	0.59		$	0.69
Basic income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.02	)	$	—
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	183	$	312		$	309
Dilutive effect of equity-based compensation of subsidiaries	—		(1		)	(1		)
Diluted income from continuing operations available to Limited Partners	183		311			308
Weighted average limited partner units	560.9		533.4			445.9
Dilutive effect of unconverted unit awards	—		—			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	560.9		533.4			445.9
Diluted income from continuing operations per Limited Partner unit	$	0.33	$	0.59		$	0.69
Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.02	)	$	—

Debt Obligations Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Debt Obligations [Abstract]

Schedule of debt obligations

Our debt obligations consist of the following:



	December 31,
	2013			2012
Parent Company Indebtedness:
7.50% Senior Notes, due October 15, 2020	$	1,187		$	1,800
5.875% Senior Notes, due January 15, 2024	450			—
ETE Senior Secured Term Loan, due March 26, 2017	—			2,000
ETE Senior Secured Term Loan, due December 2, 2018	171			—
ETE Senior Secured Term Loan, due December 2, 2019	1,000			—
ETE Senior Secured Revolving Credit Facility	—			60
Unamortized premiums, discounts and fair value adjustments, net	(7		)	(34		)
	2,801			3,826
Subsidiary Indebtedness:
ETP Debt
6.0% Senior Notes due July 1, 2013	—			350
8.5% Senior Notes due April 15, 2014	292			292
5.95% Senior Notes due February 1, 2015	750			750
6.125% Senior Notes due February 15, 2017	400			400
6.7% Senior Notes due July 1, 2018	600			600
9.7% Senior Notes due March 15, 2019	400			400
9.0% Senior Notes due April 15, 2019	450			450
4.15% Senior Notes due October 1, 2020	700			—
4.65% Senior Notes due June 1, 2021	800			800
5.20% Senior Notes due February 1, 2022	1,000			1,000
3.60% Senior Notes due February 1, 2023	800			—
4.9% Senior Notes due February 1, 2024	350			—
7.6% Senior Notes due February 1, 2024	277			—
8.25% Senior Notes due November 15, 2029	267			—
6.625% Senior Notes due October 15, 2036	400			400
7.5% Senior Notes due July 1, 2038	550			550
6.05% Senior Notes due June 1, 2041	700			700
6.5% Senior Notes due February 1, 2042	1,000			1,000
5.15% Senior Notes due February 1, 2043	450			—
5.95% Senior Notes due October 1, 2043	450			—
Floating Rate Junior Subordinated Notes due November 1, 2066	546			—
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	65			1,395
Unamortized premiums, discounts and fair value adjustments, net	(34		)	(14		)
	11,213			9,073
Panhandle Debt
6.05% Senior Notes due August 15, 2013	—			250
6.20% Senior Notes due November 1, 2017	300			300
7.00% Senior Notes due June 15, 2018	400			400
8.125% Senior Notes due June 1, 2019	150			150
7.00% Senior Notes due July 15, 2029	66			66
Term Loan due February 23, 2015	—			455
Unamortized premiums, discounts and fair value adjustments, net	107			136
	1,023			1,757
Regency Debt
9.375% Senior Notes due June 1, 2016	—			162
6.875% Senior Notes due December 1, 2018	600			600
5.75% Senior Notes due September 1, 2020	400			—
6.5% Senior Notes due July 15, 2021	500			500
5.5% Senior Notes due April 15, 2023	700			700
4.5% Senior Notes due November 1, 2023	600			—
Regency $1.2 billion Revolving Credit Facility due May 21, 2018	510			192
Unamortized premiums, discounts and fair value adjustments, net	—			3
	3,310			2,157
Southern Union Debt⁽¹⁾
7.60% Senior Notes due February 1, 2024	82			360
8.25% Senior Notes due November 14, 2029	33			300
Floating Rate Junior Subordinated Notes due November 1, 2066	54			600
Southern Union $700 million Revolving Credit Facility due May 20, 2016	—			210
Unamortized premiums, discounts and fair value adjustments, net	48			49
	217			1,519
Sunoco Debt
4.875% Senior Notes due October 15, 2014	250			250
9.625% Senior Notes due April 15, 2015	250			250
5.75% Senior Notes due January 15, 2017	400			400
9.00% Debentures due November 1, 2024	65			65
Unamortized premiums, discounts and fair value adjustments, net	70			104
	1,035			1,069
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014⁽²⁾	175			175
6.125% Senior Notes due May 15, 2016	175			175
5.50% Senior Notes due February 15, 2020	250			250
4.65% Senior Notes due February 15, 2022	300			300
3.45% Senior Notes due January 15, 2023	350			—
6.85% Senior Notes due February 15, 2040	250			250
6.10% Senior Notes due February 15, 2042	300			300
4.95% Senior Notes due January 15, 2043	350			—
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2014	—			26
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35			20
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016	—			93
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 1, 2018	200			—
Unamortized premiums, discounts and fair value adjustments, net	118			143
	2,503			1,732
Transwestern Debt
5.39% Senior Notes due November 17, 2014	88			88
5.54% Senior Notes due November 17, 2016	125			125
5.64% Senior Notes due May 24, 2017	82			82
5.36% Senior Notes due December 9, 2020	175			175
5.89% Senior Notes due May 24, 2022	150			150
5.66% Senior Notes due December 9, 2024	175			175
6.16% Senior Notes due May 24, 2037	75			75
Unamortized premiums, discounts and fair value adjustments, net	(1		)	(1		)
	869			869
Other	228			51
	23,199			22,053
Less: current maturities	637			613
	$	22,562		$	21,440

Future maturities of long-term debt



2014	$	812
2015	1,047
2016	375
2017	1,220
2018	1,976
Thereafter	17,468
Total	$	22,898

- 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 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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: 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 4: 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=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Redeemable Preferred Units (Tables)

12 Months Ended

Dec. 31, 2013

Preferred Units, Preferred Partners' Capital Accounts [Abstract]

Schedule of Redeemable Preferred Units

The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:



	Regency Preferred Units		Amount
Balance at January 1, 2012	4.4		$	71
Accretion to redemption value	N/A		2
Balance, December 31, 2012	4.4		$	73
Regency Preferred Units converted into Regency Common Units	(2.5	)	(41		)
Balance, December 31, 2013	1.9		$	32		⁽¹	⁾


⁽¹⁾	This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Equity (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]



	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2014	$	26.50	$	26.50	$	26.50	$	26.50	$	106.00
2015	12.50		12.50		13.00		13.00		51.00
2016	18.00		18.00		18.00		18.00		72.00
2017	12.50		12.50		12.50		12.50		50.00
2018	11.25		11.25		11.25		11.25		45.00
2019	8.75		8.75		8.75		8.75		35.00

Schedule Of Common Units Sold In Public Offering

The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:



Date	Number of Regency Common Units ⁽¹⁾	Price per Regency Unit			Net Proceeds
May 2011	8.5	⁽¹		⁾	$	204
October 2011	11.5	$	20.92		232
March 2012	12.7	24.47			297


⁽¹⁾	Regency Units were issued in a private placement.

The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):



Date	Number of ETP Common Units	Price per ETP Unit		Net Proceeds
April 2011	14.2	$	50.52	$	695
November 2011	15.2	44.67		660
July 2012	15.5	44.57		671
April 2013	13.8	48.05		657

Change In ETE Common Units

The change in ETE Common Units during the years ended December 31, 2013, 2012 and 2011was as follows:



	Years Ended December 31,
	2013	2012	2011
Number of Common Units, beginning of period	559.9	445.9	445.9
Issuance of restricted Common Units under long-term incentive plan	—	—	—
Issuance of common units in connection with Southern Union Merger (See Note 3)	—	114.0	—
Number of Common Units, end of period	559.9	559.9	445.9

Accumulated Other Comprehensive Income (Loss)

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



	December 31,
	2013			2012
Net losses on commodity related hedges	$	(4	)	$	(3	)
Available-for-sale securities	2			—
Foreign currency translation adjustment	(1		)	—
Actuarial gain (loss) related to pensions and other postretirement benefits	56			(10		)
Equity investments, net	8			(9		)
Subtotal	61			(22		)
Amounts attributable to noncontrolling interest	(52		)	10
Total AOCI included in partners’ capital, net of tax	$	9		$	(12	)

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):



	December 31,
	2013			2012
Net gains on commodity related hedges	$	—		$	2
Actuarial (gain) loss relating to pension and other postretirement benefits	(39		)	5
Total	$	(39	)	$	7

Parent Company [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Our distributions declared during the years ended December 31, 2013, 2012 and 2011 are summarized as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 18, 2011	$	0.27000
March 31, 2011	May 6, 2011	May 19, 2011	0.28000
June 30, 2011	August 5, 2011	August 19, 2011	0.31250
September 30, 2011	November 4, 2011	November 18, 2011	0.31250
December 31, 2011	February 7, 2012	February 17, 2012	0.31250
March 31, 2012	May 4, 2012	May 18, 2012	0.31250
June 30, 2012	August 6, 2012	August 17, 2012	0.31250
September 30, 2012	November 6, 2012	November 16, 2012	0.31250
December 31, 2012	February 7, 2013	February 19, 2013	0.31750
March 31, 2013	May 6, 2013	May 17, 2013	0.32250
June 30, 2013	August 5, 2013	August 19, 2013	0.32750
September 30, 2013	November 4, 2013	November 19, 2013	0.33625
December 31, 2013	February 7, 2014	February 19, 2014	0.34625

ETP [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

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



Quarter Ended	Record Date	Payment Date	Distribution per ETP Common Unit
December 31, 2010	February 7, 2011	February 14, 2011	$	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
September 30, 2011	November 4, 2011	November 14, 2011	0.89375
December 31, 2011	February 7, 2012	February 14, 2012	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375
June 30, 2012	August 6, 2012	August 14, 2012	0.89375
September 30, 2012	November 6, 2012	November 14, 2012	0.89375
December 31, 2012	February 7, 2013	February 14, 2013	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375
September 30, 2013	November 4, 2013	November 14, 2013	0.90500
December 31, 2013	February 7, 2014	February 14, 2014	0.92000

Regency [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions paid by Regency since the date of acquisition are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per Regency Common Unit
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	0.445
June 30, 2011	August 5, 2011	August 12, 2011	0.450
September 30, 2011	November 7, 2011	November 14, 2011	0.455
December 31, 2011	February 6, 2012	February 13, 2012	0.460
March 31, 2012	May 7, 2012	May 14, 2012	0.460
June 30, 2012	August 6, 2012	August 14, 2012	0.460
September 30, 2012	November 6, 2012	November 14, 2012	0.460
December 31, 2012	February 7, 2013	February 14, 2013	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465
September 30, 2013	November 4, 2013	November 14, 2013	0.470
December 31, 2013	February 7, 2014	February 14, 2014	0.475

Sunoco Logistics [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Sunoco Logistics Quarterly Distributions of Available Cash

Distributions paid by Sunoco Logistics since the date of acquisition are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per Sunoco Logistics Common Unit
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000
September 30, 2013	November 8, 2013	November 14, 2013	0.6300
December 31, 2013	February 10, 2014	February 14, 2014	0.6625

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

12 Months Ended

Dec. 31, 2013

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

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

The following table shows the activity of the ETP awards granted to employees and non-employee directors:



	Number of ETP Units		Weighted Average Grant-Date Fair Value Per ETP Unit
Unvested awards as of December 31, 2012	1.9		$	46.95
Awards granted	2.1		50.54
Awards vested	(0.6	)	45.62
Awards forfeited	(0.2	)	45.72
Unvested awards as of December 31, 2013	3.2		49.65

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Federal and State Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

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



	Years Ended December 31,
	2013			2012			2011
Current expense (benefit):
Federal	$	51		$	(3	)	$	(1	)
State	(1		)	6			17
Total	50			3			16
Deferred expense:
Federal	(14		)	41			—
State	57			10			1
Total	43			51			1
Total income tax expense from continuing operations	$	93		$	54		$	17

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]



	December 31, 2013									December 31, 2012
	Corporate Subsidiaries⁽¹⁾			Partnership⁽²⁾			Consolidated			Corporate Subsidiaries⁽¹⁾			Partnership⁽²⁾		Consolidated
Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	(172	)	$	—		$	(172	)	$	(4	)	$	—	$	(4	)
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill	241			—			241			—			—		—
Nondeductible executive compensation	—			—			—			28			—		28
State income taxes (net of federal income tax effects)	31			10			41			9			2		11
Other	(16		)	(1		)	(17		)	19			—		19
Income tax from continuing operations	$	84		$	9		$	93		$	52		$	2	$	54

⁽¹⁾


⁽²⁾	Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes.

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]



	December 31,
	2013			2012
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	217		$	270
Pension and other postretirement benefits	57			127
Long term debt	108			117
Other	104			290
Total deferred income tax assets	486			804
Valuation allowance	(74		)	(94		)
Net deferred income tax assets	412			710

Deferred income tax liabilities:
Properties, plants and equipment	(1,624		)	(2,026		)
Inventory	(302		)	(516		)
Investments in unconsolidated affiliates	(2,245		)	(1,543		)
Trademarks	(180		)	(192		)
Other	(45		)	(129		)
Total deferred income tax liabilities	(4,396		)	(4,406		)
Net deferred income tax liability	(3,984		)	(3,696		)
Less: current portion of deferred income tax assets (liabilities)	(119		)	(130		)
Accumulated deferred income taxes	$	(3,865	)	$	(3,566	)

ScheduleOfUnrecognizedTaxBenefits [Table Text Block]

The following table sets forth the changes in unrecognized tax benefits:



	Years Ended December 31,
	2013			2012			2011
Balance at beginning of year	$	27		$	2		$	2
Additions attributable to acquisitions	—			28			—
Additions attributable to tax positions taken in the current year	—			—			1
Additions attributable to tax positions taken in prior years	406			—			—
Settlements	—			—			—
Lapse of statute	(4		)	(3		)	(1		)
Balance at end of year	$	429		$	27		$	2

Summary of Deferred Tax Liability Not Recognized [Table Text Block]



	December 31,
	2013			2012
Net deferred income tax liability, beginning of year	$	(3,696	)	$	(214	)
Southern Union acquisition	—			(1,428		)
Sunoco acquisition	—			(1,989		)
SUGS Contribution to Regency	(115		)	—
Tax provision (including discontinued operations)	(124		)	(62		)
Other	(49		)	(3		)
Net deferred income tax liability	$	(3,984	)	$	(3,696	)

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

12 Months Ended

Dec. 31, 2013

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

Environmental Exit Costs by Cost [Table Text Block]



	December 31,
	2013		2012
Current	$	47	$	46
Non-current	356		166
Total environmental liabilities	$	403	$	212

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease commitments for such leases are:



Years Ending December 31:
2014	$	83
2015	81
2016	72
2017	68
2018	55
Thereafter	454
Future minimum lease commitments	813
Less: Sublease rental income	(57		)
Net future minimum lease commitments	$	756

Price Risk Management Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Offsetting Assets [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2013			December 31, 2012			December 31, 2013			December 31, 2012
Derivatives in offsetting agreements:
OTC contracts	Price risk management assets (liabilities)	$	42		$	28		$	(38	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	264			149			(318		)	(228		)
		306			177			(356		)	(255		)
Offsetting agreements:
Collateral paid to OTC counterparties	Other current assets	—			—			—			2
Counterparty netting	Price risk management assets (liabilities)	(36		)	(25		)	36			25
Payments on margin deposit	Other current assets	(1		)	—			55			59
		(37		)	(25		)	91			86
Net derivatives with offsetting agreements		269			152			(265		)	(169		)
Derivatives without offsetting agreements		51			63			(124		)	(270		)
Total derivatives		$	320		$	215		$	(389	)	$	(439	)

Interest Rate Swaps Outstanding

The following is a summary of interest rate swaps outstanding as of December 31, 2013, none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

December 31,
2013

December 31,
2012

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

—

500

ETP

July 2013⁽²⁾

Forward starting to pay a fixed rate of 4.03% and receive a floating rate

—

400

ETP

July 2014⁽²⁾

Forward starting to pay a fixed rate of 4.25% and receive a floating rate

400

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

ETP

June 2021

Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%

400

—

ETP

February 2023

Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%

400

—

Southern Union⁽³⁾

November 2016

Pay a fixed rate of 2.97% and receive a floating rate

—

Southern Union⁽³⁾

November 2021

Pay a fixed rate of 3.801% and receive a floating rate

275

450


⁽¹⁾	Floating rates are based on 3-month LIBOR.

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, 2013 and 2012:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2013		December 31, 2012		December 31, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	3	$	8	$	(18	)	$	(10	)
	3		8		(18		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	227	$	110	$	(209	)	$	(116	)
Commodity derivatives	43		40		(48		)	(44		)
Current assets held for sale	—		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		—			(9		)
Interest rate derivatives	47		55		(95		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(19		)	(25		)
	317		207		(371		)	(429		)
Total derivatives	$	320	$	215	$	(389	)	$	(439	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

The following tables summarize the amounts recognized with respect to our derivative financial instruments:



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Years Ended December 31,
	2013			2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(1	)	$	8	$	6
Total	$	(1	)	$	8	$	6

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,
		2013		2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	4	$	14	$	19
Total		$	4	$	14	$	19



	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,
		2013		2012		2011
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	8	$	54	$	34
Total		$	8	$	54	$	34



	Location of Gain/ (Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2013			2012			2011
Derivatives in cash flow hedging relationships:
Commodity derivatives – Trading	Cost of products sold	$	(11	)	$	(7	)	$	(30	)
Commodity derivatives – Non-trading	Cost of products sold	(21		)	26			9
Commodity derivatives – Non-trading	Deferred gas purchases	(3		)	(26		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	53			(19		)	(78		)
Embedded derivatives	Other income (expense)	6			14			18
Total		$	24		$	(12	)	$	(81	)

ETP [Member]

Outstanding Commodity-Related Derivatives

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



	December 31, 2013			December 31, 2012
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,457,500		2014-2019	—		—
Basis Swaps IFERC/NYMEX ⁽¹⁾	(487,500	)	2014-2017	(30,980,000	)	2013-2014
Swing Swaps	1,937,500		2014-2016	—		—
Power (Megawatt):
Forwards	351,050		2014	19,650		2013
Futures	(772,476	)	2014	(1,509,300	)	2013
Options — Puts	(52,800	)	2014	—		—
Options — Calls	103,200		2014	1,656,400		2013
Crude (Bbls) – Futures	103,000		2014	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	570,000		2014	150,000		2013
Swing Swaps IFERC	(9,690,000	)	2014-2016	(83,292,500	)	2013
Fixed Swaps/Futures	(8,195,000	)	2014-2015	27,077,500		2013
Forward Physical Contracts	5,668,559		2014-2015	11,689,855		2013-2014
Natural Gas Liquid (Bbls) – Forwards/Swaps	(280,000	)	2014	(30,000	)	2013
Refined Products (Bbls) – Futures	(1,133,600	)	2014	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,352,500	)	2014	(18,655,000	)	2013
Fixed Swaps/Futures	(50,530,000	)	2014	(44,272,500	)	2013
Hedged Item — Inventory	50,530,000		2014	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,825,000	)	2014	—		—
Fixed Swaps/Futures	(12,775,000	)	2014	(8,212,500	)	2013
Natural Gas Liquid (Bbls) – Forwards/Swaps	(780,000	)	2014	(930,000	)	2013
Refined Products (Bbls) – Futures	—		—	(98,000	)	2013
Crude (Bbls) – Futures	(30,000	)	2014	—		—


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

Regency [Member]

Outstanding Commodity-Related Derivatives

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



	December 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	24,455,000	2014-2015	8,395,000	2013-2014
Propane (Gallons) — Forwards/Swaps	52,122,000	2014-2015	3,318,000	2013
NGLs (Barrels) — Forwards/Swaps	438,000	2014	243,000	2013-2014
WTI Crude Oil (Barrels) — Forwards/Swaps	521,000	2014	356,000	2014

- 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 5
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41641-113959

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=7476318&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 8
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41678-113959

Reference 4: 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=7476318&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 6: 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=7476318&loc=SL5579245-113959

Reference 7: 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=7476318&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41620-113959

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.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Retirement Benefits Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Obligations and Funded Status



	December 31, 2013									December 31, 2012
	Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	1,117		$	78		$	296		$	1,257		$	359
Service cost	3			—			—			3			1
Interest cost	33			2			6			15			3
Amendments	—			—			2			—			17
Benefits paid, net	(99		)	(16		)	(26		)	(71		)	(8		)
Curtailments	—			—			—			—			(80		)
Actuarial (gain) loss and other	(74		)	(3		)	(14		)	(9		)	4
Settlements	(95		)	—			—			—			—
Dispositions	(253		)	—			(41		)	—			—
Benefit obligation at end of period	$	632		$	61		$	223		$	1,195		$	296

Change in plan assets:
Fair value of plan assets at beginning of period	906			—			312			941			306
Return on plan assets and other	43			—			17			22			5
Employer contributions	—			—			8			14			9
Benefits paid, net	(99		)	—			(26		)	(71		)	(8		)
Settlements	(95		)	—			—			—			—
Dispositions	(155		)	—			(27		)	—			—
Fair value of plan assets at end of period	$	600		$	—		$	284		$	906		$	312

Amount underfunded (overfunded) at end of period	$	32		$	61		$	(61	)	$	289		$	(16	)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	86		$	—		$	59
Current liabilities	—			(9		)	(2		)	(15		)	(2		)
Non-current liabilities	(32		)	(52		)	(23		)	(274		)	(41		)
	$	(32	)	$	(61	)	$	61		$	(289	)	$	16

Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain	$	(86	)	$	(4	)	$	(25	)	$	(1	)	$	(1	)
Prior service cost	—			—			18			—			16
	$	(86	)	$	(4	)	$	(7	)	$	(1	)	$	15

Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:



	December 31, 2013					December 31, 2012
	Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Projected benefit obligation	$	632	$	61	N/A	$	1,195	N/A
Accumulated benefit obligation	632		61		223	1,179		$	225
Fair value of plan assets	600		—		284	906		185

Schedule of Benefit Obligations Assumptions [Table Text Block]

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:



	December 31, 2013				December 31, 2012
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	4.65	%	2.33	%	3.41	%	2.39	%
Rate of compensation increase	N/A		N/A		3.17	%	N/A

Schedule or Description of Weighted Average Discount Rate [Table Text Block]

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:



	December 31, 2013				December 31, 2012
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.50	%	2.68	%	2.37	%	2.43	%
Expected return on assets:
Tax exempt accounts	7.50	%	6.95	%	7.63	%	7.00	%
Taxable accounts	N/A		4.42	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		3.02	%	N/A

Schedule of Health Care Cost Trend Rates [Table Text Block]

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union’s and Sunoco’s other postretirement benefit plans are shown in the table below:



	December 31,
	2013		2012
Health care cost trend rate assumed for next year	7.57	%	7.78	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.42	%	5.32	%
Year that the rate reaches the ultimate trend rate	2018		2018

Fair Value of Plan Assets [Table Text Block]

The fair value of the pension plan assets by asset category at the dates indicated is as follows:



	Fair Value as of		Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	December 31, 2013		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	12	$	12	$	—	$	—
Mutual funds ⁽¹⁾	368		—		281		87
Fixed income securities	220		—		220		—
Total	$	600	$	12	$	501	$	87


⁽¹⁾	Primarily comprised of approximately 66% equities, 10% fixed income securities, and 24% in other investments as of December 31, 2013.



	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	25	$	25	$	—	$	—
Mutual funds ⁽¹⁾	516		—		433		83
Fixed income securities	354		—		354		—
Multi-strategy hedge funds ⁽²⁾	11		—		11		—
Total	$	906	$	25	$	798	$	83


⁽¹⁾	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.

⁽²⁾

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:



	Fair Value as of		Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	December 31, 2013		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	10	$	10	$	—	$	—
Mutual funds ⁽¹⁾	130		112		18		—
Fixed income securities	144		—		144		—
Total	$	284	$	122	$	162	$	—


⁽¹⁾	Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013.



	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	7	$	7	$	—	$	—
Mutual funds ⁽¹⁾	147		126		21		—
Fixed income securities	158		—		158		—
Total	$	312	$	133	$	179	$	—


⁽¹⁾	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments



	Pension Benefits
Years	Funded Plans		Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2014	$	82	$	9	$	31
2015	77		9		29
2016	67		8		28
2017	61		7		26
2018	56		7		24
2019 – 2023	220		23		87

Schedule of Net Benefit Costs [Table Text Block]

Components of Net Periodic Benefit Cost



	December 31, 2013						December 31, 2012
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	3		$	—		$	3		$	1
Interest cost	35			6			15			3
Expected return on plan assets	(54		)	(9		)	(21		)	(5		)
Prior service cost amortization	—			1			—			—
Actuarial loss amortization	2			—			—			—
Special termination benefits charge	—			—			2			—
Curtailment recognition ⁽¹⁾	—			—			—			(15		)
Settlements	(2		)	—			—			—
	(16		)	(2		)	(1		)	(16		)
Regulatory adjustment ⁽²⁾	5			—			9			2
Net periodic benefit cost	$	(11	)	$	(2	)	$	8		$	(14	)

⁽¹⁾

⁽²⁾

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2013

Financial Information By Segment



	Years Ended December 31,
	2013			2012			2011
Revenues:
Investment in ETP:
Revenues from external customers	$	46,210		$	15,671		$	6,761
Intersegment revenues	129			31			38
	46,339			15,702			6,799
Investment in Regency:
Revenues from external customers	2,404			1,986			1,426
Intersegment revenues	117			14			8
	2,521			2,000			1,434
Investment in Trunkline LNG:
Revenues from external customers	216			166			—
Intersegment revenues	—			—			—
	216			166			—
Adjustments and Eliminations:	(741		)	(904		)	(43		)
Total revenues	$	48,335		$	16,964		$	8,190
Costs of products sold:
Investment in ETP	$	41,204		$	12,266		$	4,175
Investment in Regency	1,793			1,387			1,013
Investment in Trunkline LNG	—			—			—
Adjustments and Eliminations	(443		)	(565		)	(19		)
Total costs of products sold	$	42,554		$	13,088		$	5,169
Depreciation and amortization:
Investment in ETP	1,032			656			405
Investment in Regency	287			252			169
Investment in Trunkline LNG	39			30			—
Corporate and Other	16			14			12
Adjustments and Eliminations	(61		)	(81		)	—
Total depreciation and amortization	$	1,313		$	871		$	586



	Years Ended December 31,
	2013			2012			2011
Equity in earnings of unconsolidated affiliates:
Investment in ETP	$	172		$	142		$	26
Investment in Regency	135			105			120
Adjustments and Eliminations	(71		)	(35		)	(29		)
Total equity in earnings of unconsolidated affiliates	$	236		$	212		$	117



	Years Ended December 31,
	2013			2012			2011
Segment Adjusted EBITDA:
Investment in ETP	$	3,953		$	2,744		$	1,781
Investment in Regency	608			517			420
Investment in Trunkline LNG	187			135			—
Corporate and Other	(43		)	(52		)	(29		)
Adjustments and Eliminations	(338		)	(239		)	(41		)
Total Segment Adjusted EBITDA	4,367			3,105			2,131
Depreciation and amortization	(1,313		)	(871		)	(586		)
Interest expense, net of interest capitalized	(1,221		)	(1,018		)	(740		)
Bridge loan related fees	—			(62		)	—
Gain on deconsolidation of Propane Business	—			1,057			—
Gain on sale of AmeriGas common units	87			—			—
Goodwill impairment	(689		)	—			—
Gains (losses) on interest rate derivatives	53			(19		)	(78		)
Non-cash unit-based compensation expense	(61		)	(47		)	(42		)
Unrealized gains on commodity risk management activities	48			10			7
Losses on extinguishments of debt	(162		)	(123		)	—
LIFO valuation adjustments	3			(75		)	—
Adjusted EBITDA related to discontinued operations	(76		)	(99		)	(23		)
Adjusted EBITDA related to unconsolidated affiliates	(727		)	(647		)	(231		)
Equity in earnings of unconsolidated affiliates	236			212			117
Non-operating environmental remediation	(168		)	—			—
Other, net	(2		)	14			(7		)
Income from continuing operations before income tax expense	$	375		$	1,437		$	548



	December 31,
	2013			2012			2011
Total assets:
Investment in ETP	$	43,702		$	43,230		$	15,519
Investment in Regency	8,782			8,123			5,568
Investment in Trunkline LNG	1,338			1,917			—
Corporate and Other	720			707			470
Adjustments and Eliminations	(4,212		)	(5,073		)	(660		)
Total	$	50,330		$	48,904		$	20,897



	Years Ended December 31,
	2013			2012			2011
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	2,455		$	3,049		$	1,484
Investment in Regency	1,034			560			406
Investment in Trunkline LNG	2			4			—
Adjustments and Eliminations	(2		)	(128		)	—
Total	$	3,489		$	3,485		$	1,890



	December 31,
	2013			2012			2011
Advances to and investments in affiliates:
Investment in ETP	$	4,436		$	3,502		$	201
Investment in Regency	2,097			2,214			1,925
Adjustments and Eliminations	(2,519		)	(979		)	(629		)
Total	$	4,014		$	4,737		$	1,497

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

Investment in ETP



	Years Ended December 31,
	2013		2012		2011
Intrastate Transportation and Storage	$	2,250	$	2,012	$	2,398
Interstate Transportation and Storage	1,270		1,109		447
Midstream	1,307		1,757		1,082
NGL Transportation and Services	2,063		619		363
Investment in Sunoco Logistics	16,480		3,109		—
Retail Marketing	21,004		5,926		—
All Other	1,965		1,170		2,509
Total revenues	46,339		15,702		6,799
Less: Intersegment revenues	129		31		38
Revenues from external customers	$	46,210	$	15,671	$	6,761

Investment in Regency



	Years Ended December 31,
	2013		2012		2011
Gathering and Processing	$	2,287	$	1,797	$	1,226
Natural Gas Transportation	1		1		1
Contract Services	215		183		190
Corporate and others	18		19		17
Total revenues	2,521		2,000		1,434
Less: Intersegment revenues	117		14		8
Revenues from external customers	$	2,404	$	1,986	$	1,426

Investment in Trunkline LNG

Trunkline LNG’s revenues of $216 million for the year ended December 31, 2013 and $166 million for the period from March 26, 2012 to December 31, 2012 were related to LNG terminalling.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information



	Quarters Ended
	March 31		June 30		September 30		December 31			Total Year
2013:
Revenues	$	11,179	$	12,063	$	12,486	$	12,607		$	48,335
Gross margin	1,372		1,498		1,422		1,489			5,781
Operating income (loss)	531		644		529		(153		)	1,551
Net income (loss)	322		338		356		(701		)	315
Limited Partners’ interest in net income (loss)	90		127		150		(171		)	196
Basic net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
Diluted net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35

The three months ended December 31, 2013 was impacted by ETP’s recognition of a goodwill impairment of $689 million.



	Quarters Ended
	March 31		June 30		September 30			December 31		Total Year
2012:
Revenues	$	1,669	$	1,875	$	2,107		$	11,313	$	16,964
Gross margin	654		916		876			1,430		3,876
Operating income	183		367		358			452		1,360
Net income (loss)	961		75		(34		)	272		1,274
Limited Partners’ interest in net income	166		53		35			48		302
Basic net income per limited partner unit	$	0.37	$	0.10	$	0.06		$	0.09	$	0.57
Diluted net income per limited partner unit	$	0.36	$	0.10	$	0.06		$	0.09	$	0.57

Supplemental Financial Statement Information (Tables)

12 Months Ended

Dec. 31, 2013

Schedule Of Statements Of Cash Flows

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



	Years Ended December 31,
	2013			2012		2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	226		$	420	$	226
Net gains (losses) from subsidiary common unit transactions	$	(384	)	$	80	$	153
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	—		$	1,123	$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with Southern Union Merger (see Note 3)	$	—		$	2,354	$	—
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—		$	6,658	$	4
Subsidiary issuance of Common Units in connection with certain acquisitions	$	—		$	2,295	$	3
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,256		$	997	$	728
Cash paid for income taxes	$	58		$	23	$	27

Parent Company [Member]

Schedule Of Balance Sheets

BALANCE SHEETS



	December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8		$	9
Accounts receivable from related companies	5			11
Other current assets	—			3
Total current assets	13			23
ADVANCES TO AND INVESTMENTS IN AFFILIATES	3,841			6,094
INTANGIBLE ASSETS, net	14			19
NOTE RECEIVABLE FROM AFFILIATE	—			166
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	41			56
Total assets	$	3,918		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	11			15
Interest payable	24			48
Price risk management liabilities	—			5
Accrued and other current liabilities	3			1
Current maturities of long-term debt	—			4
Total current liabilities	38			74
LONG-TERM DEBT, less current maturities	2,801			3,840
PREFERRED UNITS	—			331
OTHER NON-CURRENT LIABILITIES	1			9

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner	(3		)	—
Limited Partners – Common Unitholders (559,923,300 and 559,911,216 units authorized, issued and outstanding at December 31, 2013 and 2012, respectively)	1,066			2,125
Class D Units (1,540,000 units authorized, issued and outstanding at December 31, 2013)	6			—
Accumulated other comprehensive income (loss)	9			(12		)
Total partners’ capital	1,078			2,113
Total liabilities and partners’ capital	$	3,918		$	6,367

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2013			2012			2011
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(56	)	$	(53	)	$	(30	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(210		)	(235		)	(164		)
Bridge loan related fees	—			(62		)	—
Equity in earnings of unconsolidated affiliates	617			666			509
Gains (losses) on interest rate derivatives	9			(15		)	—
Loss on extinguishment of debt	(157		)	—			—
Other, net	(8		)	(4		)	(5		)
INCOME BEFORE INCOME TAXES	195			297			310
Income tax benefit	(1		)	(7		)	—
NET INCOME	196			304			310
GENERAL PARTNER’S INTEREST IN NET INCOME	—			2			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	196		$	302		$	309

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2013			2012			2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	768		$	555		$	469
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	—			(1,113		)	—
Proceeds from Holdco Transaction	1,332			—			—
Contributions to affiliates	(8		)	(487		)	—
Note receivable from affiliate	—			(221		)	—
Payments received on note receivable from affiliate	166			55			—
Net cash provided by (used in) investing activities	1,490			(1,766		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,080			2,108			92
Principal payments on debt	(3,235		)	(162		)	(20		)
Distributions to partners	(733		)	(666		)	(526		)
Redemption of Preferred Units	(340		)	—			—
Debt issuance costs	(31		)	(78		)	(24		)
Net cash provided by (used in) financing activities	(2,259		)	1,202			(478		)
DECREASE IN CASH AND CASH EQUIVALENTS	(1		)	(9		)	(9		)
CASH AND CASH EQUIVALENTS, beginning of period	9			18			27
CASH AND CASH EQUIVALENTS, end of period	$	8		$	9		$	18

Operations And Organization (Schedule Of Equity Interests (Details) - shares shares in Millions	Dec. 31, 2013	Oct. 05, 2012
Incentive Distribution Rights		100.00%
General Partner Interest		2.00%
ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	49.6
Regency [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	26.3
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.	31.4
Class H Units [Member] \| ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	50.2
Class F Units [Member] \| Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.	6.3

Operations And Organization (Narrative) (Details)	9 Months Ended	12 Months Ended
Operations And Organization (Narrative) (Details)	Sep. 30, 2013	Dec. 31, 2013	Apr. 30, 2013	Mar. 25, 2012
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		50.00%
FEP [Member] \| Fayetteville Express Pipeline, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
FEP [Member] \| FGT [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		70.00%
Interest ownership		30.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		50.00%
Interest ownership		50.00%
ETE [Member]
Equity interest in Holdco			60.00%
Citrus Merger [Member]
Interest ownership				50.00%

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 05, 2012

Mar. 25, 2012

Long-term Debt, Fair Value

$ 23,970

$ 24,150

Goodwill, Period Increase (Decrease)

(540)

4,400

Goodwill impairment

689

$ 0

Goodwill acquired

156

5,147

GOODWILL

5,894

6,434

$ 2,039

Long-term Debt

23,199

22,053

Interstate Transportation and Storage [Member]

Goodwill impairment

689

Retail Marketing [Member]

Goodwill acquired

156

Excise Taxes Collected

2,220

573

Trunkline LNG [Member]

GOODWILL

$ 873

184

Sunoco Merger [Member]

Goodwill

^[1]

$ 2,641

Southern Union Merger [Member]

Goodwill

^[2]

$ 2,497

PP&E [Member]

Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down

$ 128

[1]	(1)Includes amounts recorded with respect to Sunoco Logistics.
[2]	(2)Includes ETP’s acquisition of Citrus.

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Regulatory Assets) (Details) $ in Millions	Dec. 31, 2012 USD ($)
Net Regulatory Assets [Abstract]
Regulatory Assets	$ 123

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Accounts receivable	$ (556)	$ 267	$ 6
Accounts receivable from related companies	64	(9)	(24)
Inventories	(254)	(258)	51
Exchanges receivable	(8)	14	1
Increase (Decrease) in Other Current Assets	81	(597)	51
Other non-current assets, net	(23)	(129)	7
Accounts payable	541	(989)	21
Accounts payable to related companies	(140)	92	6
Exchanges payable	128	0	2
Accrued and other current liabilities	192	(159)	84
Other non-current liabilities	147	26	0
Price risk management assets and liabilities, net	(159)	(3)	55
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (149)	$ (551)	$ 158

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 226	$ 420	$ 226
Net gains (losses) from subsidiary common unit transactions	(384)	80	153
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	0	1,123	0
NON-CASH FINANCING ACTIVITIES:
Units issued in Southern Union Merger (See Note 3)	0	2,354	0
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	0	6,658	4
Subsidiary issuance of Common Units in connection with certain acquisitions	0	2,295	3
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,256	997	728
Cash paid for income taxes	$ 58	$ 23	$ 27

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Inventory, Net [Abstract]
Natural gas and NGLs	$ 523	$ 338
Energy Related Inventory, Crude Oil, Products and Merchandise	488	418
Inventory, refined products	597	572
Appliances, parts and fittings and other	199	194
Total inventories	$ 1,807	$ 1,522

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Other Information [Abstract]
Deposits paid to vendors	$ 49	$ 41
Prepaid and other	263	270
Total other current assets	$ 312	$ 311

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 33,917	$ 30,388
Less - Accumulated depreciation	(3,235)	(2,104)
PROPERTY, PLANT AND EQUIPMENT, net	30,682	28,284
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	881	553
Building and Building Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	939	692
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	21,494	19,505
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,083	1,057
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,933	1,745
Tanks and other equipment (5 to 40 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,697	1,194
Retail Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	450	258
Vehicles [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	156	154
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,190	2,134
Furniture and fixtures (2 to 25 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	51	67
Linepack [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	118	118
Pad gas [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	52	58
Other (1 to 48 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	708	880
Construction work-in-process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 2,165	$ 1,973

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Property, Plant and Equipment [Line Items]

Depreciation expense (1)

$ 1,128

$ 801

$ 531

^[1]

Capitalized interest, excluding AFUDC

$ 43

$ 99

Canyon [Member]

Property, Plant and Equipment [Line Items]

Depreciation and Amortization, Discontinued Operations

$ 26

[1]	(1) Depreciation expense amounts have been adjusted by $26 million for the year ended December 31, 2011 to present Canyon’s operations as discontinued operations.

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Roll Forward]
Goodwill	$ 6,434	$ 2,039
Goodwill acquired	156	5,147
Goodwill	5,894	6,434	$ 2,039
Goodwill impairment	(689)	0	0
Goodwill, Other Changes	(7)	(133)
Goodwill, Written off Related to Sale of Business Unit	0	(619)
Investment In ETP [Member]
Goodwill [Roll Forward]
Goodwill	5,606	1,220
Goodwill acquired	156	5,138
Goodwill	4,729	5,606	1,220
Goodwill impairment	(689)
Goodwill, Other Changes	(7)	(133)
Goodwill, Written off Related to Sale of Business Unit	(337)	(619)
Investment In Regency [Member]
Goodwill [Roll Forward]
Goodwill	1,127	790
Goodwill acquired	0	337
Goodwill	1,127	1,127	790
Goodwill impairment	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Investment in Trunkline LNG [Member]
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill acquired	0
Goodwill	0	0	0
Goodwill impairment	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Corporate And Others [Member]
Goodwill [Roll Forward]
Goodwill	(299)	29
Goodwill acquired	0	(328)
Goodwill	38	(299)	$ 29
Goodwill impairment	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	$ 337	$ 0

Estimates (Components And Useful Lives Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Total Intangible Assets [Member]
Gross Carrying Amount	$ 2,550	$ 2,451
Accumulated Amortization	286	160
Customer Contracts [Member]
Gross Carrying Amount	2,135	2,032
Accumulated Amortization	264	150
Trade names [Member]
Gross Carrying Amount	66	66
Accumulated Amortization	12	8
Patents [Member]
Gross Carrying Amount	48	48
Accumulated Amortization	6	1
Other [Member]
Gross Carrying Amount	7	4
Accumulated Amortization	4	1
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	2,256	2,150
Accumulated Amortization	286	160
Trademarks [Member]
Gross Carrying Amount	294	301
Accumulated Amortization	$ 0	$ 0

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2013
Trade names [Member]
Intangible assets, useful life, minimum (years)	20 years
Patents [Member]
Intangible assets, useful life, minimum (years)	9 years
Minimum [Member] \| Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] \| Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] \| Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] \| Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	2 years
Minimum [Member] \| Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] \| Retail Equipment [Member]
Property, plant and equipment, useful life, minimum (years)	3 years
Minimum [Member] \| Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Minimum [Member] \| Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	20 years
Minimum [Member] \| Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Minimum [Member] \| Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Minimum [Member] \| Customer relationships, contracts and agreements [Member]
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] \| Other [Member]
Intangible assets, useful life, minimum (years)	10 years
Maximum [Member] \| Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Maximum [Member] \| Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] \| Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	46 years
Maximum [Member] \| Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] \| Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	40 years
Maximum [Member] \| Retail Equipment [Member]
Property, plant and equipment, useful life, minimum (years)	99 years
Maximum [Member] \| Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Maximum [Member] \| Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] \| Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Maximum [Member] \| Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	48 years
Maximum [Member] \| Customer relationships, contracts and agreements [Member]
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] \| Other [Member]
Intangible assets, useful life, minimum (years)	15 years

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 120	$ 70	$ 55

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2013 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2014	$ 123
2015	123
2016	123
2017	123
2018	$ 122

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Unamortized financing costs (3 to 30 years)	$ 167	$ 152
Regulatory assets	86	93
Deferred Costs, Noncurrent	144	140
Restricted Cash and Cash Equivalents, Current	378	0
Other	147	148
Total other non-current assets, net	$ 922	$ 533

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Asset Retirement Obligations) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation	$ 180	$ 140
Southern Union [Member]
Asset Retirement Obligation	55	46
Sunoco [Member]
Asset Retirement Obligation	84	53
Sunoco Logistics [Member]
Asset Retirement Obligation	$ 41	$ 41

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Other Information [Abstract]
Interest payable	$ 357	$ 334
Customer advances and deposits	142	61
Accrued Capital Expenditures	260	427
Accrued wages and benefits	173	250
Taxes payable other than income taxes	211	208
Income taxes payable	4	41
Deferred Tax Liabilities, Net, Current	119	130
Other Accrued Liabilities, Current	412	303
Total accrued and other current liabilities	$ 1,678	$ 1,754

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Long-term Debt, Fair Value	$ 23,970	$ 24,150
Preferred Units	0	(331)
Total liabilities	(347)
Long-term Debt	23,199	22,053
Level 1 [Member]
Total liabilities	(215)
Level 2 [Member]
Total liabilities	(113)
Level 3 [Member]
Total liabilities	(19)
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives	47	55
Commodity derivatives:	231	156
Total assets	278	211
Interest rate derivatives	(95)	(235)
Preferred Units		(331)
Embedded derivatives in the Regency Preferred Units	(19)	(25)
Commodity derivatives:	(233)	(168)
Total liabilities		(759)
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Interest rate derivatives	0	0
Commodity derivatives:	217	108
Total assets	217	108
Interest rate derivatives	0	0
Preferred Units		0
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	(215)	(118)
Total liabilities		(118)
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Interest rate derivatives	47	55
Commodity derivatives:	14	48
Total assets	61	103
Interest rate derivatives	(95)	(235)
Preferred Units		0
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	(18)	(50)
Total liabilities		(285)
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Interest rate derivatives	0	0
Commodity derivatives:	0	0
Total assets	0	0
Interest rate derivatives	0	0
Preferred Units		(331)
Embedded derivatives in the Regency Preferred Units	(19)	(25)
Commodity derivatives:	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		356
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Condensate [Member] \| Forward Swaps [Member]
Commodity derivatives:		2
Commodity derivatives:	(1)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Condensate [Member] \| Level 1 [Member] \| Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Condensate [Member] \| Level 2 [Member] \| Forward Swaps [Member]
Commodity derivatives:		2
Commodity derivatives:	(1)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Condensate [Member] \| Level 3 [Member] \| Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Options - Calls [Member]
Commodity derivatives:		2
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Forward Swaps [Member]
Commodity derivatives:	3	27
Commodity derivatives:	1	27
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Future [Member]
Commodity derivatives:		1
Commodity derivatives:		2
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Options - Calls [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:		1
Commodity derivatives:		2
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Options - Calls [Member]
Commodity derivatives:		2
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Forward Swaps [Member]
Commodity derivatives:	3	27
Commodity derivatives:	1	27
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Future [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 3 [Member] \| Options - Calls [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 3 [Member] \| Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Power [Member] \| Level 3 [Member] \| Future [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Forward Swaps [Member]
Commodity derivatives:		5
Commodity derivatives:	5	8
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Future [Member]
Commodity derivatives:	5
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 1 [Member] \| Forward Swaps [Member]
Commodity derivatives:		1
Commodity derivatives:	5	1
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:	5
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 2 [Member] \| Forward Swaps [Member]
Commodity derivatives:		4
Commodity derivatives:	0	7
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 2 [Member] \| Future [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 3 [Member] \| Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Refined Products [Member] \| Level 3 [Member] \| Future [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	5	11
Commodity derivatives:	(4)	(18)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	8	3
Commodity derivatives:	(6)	(2)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	203	98
Commodity derivatives:	(206)	(103)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Options - Puts [Member]
Commodity derivatives:		1
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Options - Calls [Member]
Commodity derivatives:		3
Commodity derivatives:		(3)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:		1
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	5	11
Commodity derivatives:	(4)	(18)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	1	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	201	94
Commodity derivatives:	(201)	(94)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Options - Puts [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Options - Calls [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	7	3
Commodity derivatives:	(6)	(2)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	2	4
Commodity derivatives:	(5)	(9)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Options - Puts [Member]
Commodity derivatives:		1
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Options - Calls [Member]
Commodity derivatives:		3
Commodity derivatives:		(3)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:		1
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Options - Puts [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Options - Calls [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member] \| Level 3 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member]
Commodity derivatives:	7	2
Commodity derivatives:	(9)	(4)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - NGLs [Member] \| Level 1 [Member] \| Forward Swaps [Member]
Commodity derivatives:	5	1
Commodity derivatives:	(5)	(3)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - NGLs [Member] \| Level 2 [Member] \| Forward Swaps [Member]
Commodity derivatives:	2	1
Commodity derivatives:	(4)	(1)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives - NGLs [Member] \| Level 3 [Member] \| Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	$ 0

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Fair Value Schedule of Unobservable Inputs) (Details)	Dec. 31, 2013
Unobservable Inputs [Abstract]
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	4.16%
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	23.71%

Estimates (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net unrealized gains included in other income (expense)	$ 6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	(9)
Payments for Repurchase of Preferred Stock and Preference Stock	$ 340	$ 0	$ 0
Level 3 [Member] \| Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		$ 356

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule of Shipping and Handling Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shipping, Handling and Transportation [Abstract]
Shipping, Handling and Transportation Costs	$ 28	$ 25	$ 40

Acquisitions and Related Transactions Acquisitions (2013 Narrative) (Details) - USD ($) $ in Millions		1 Months Ended				9 Months Ended	12 Months Ended
	Mar. 31, 2012	Feb. 28, 2014	Dec. 31, 2013	Sep. 30, 2013	Apr. 30, 2013	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.50%				4.50%
Guarantor Obligations, Current Carrying Value			$ 600				$ 600
Proceeds from the sale of other assets							89	$ 251	$ 33
Proceeds from divestiture of business							$ 0	$ 1,123	$ 0
Number of Regency Common Units to be Issued in Acquisition Per Share							1.02
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2,200,000
SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred					$ 463
Cash Acquired from Acquisition					$ 30
Holdco Transaction [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					49,500,000
Payments to Acquire Businesses, Gross					$ 1,400
Estimated Closing Adjustments					$ 68
Regency [Member]
Business Acquisition [Line Items]
Number of Shares Agreed to Purchase							16,500,000
Amount of Shares Agreed to Purchase							$ 400
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.			31,400,000				31,400,000
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			26,300,000				26,300,000
Regency [Member] \| PVR Acquisition [Member]
Business Acquisition [Line Items]
Proceeds from divestiture of business							$ 1,800
Business Combination, Consideration Transferred							5,600
Payments to Acquire Businesses, Gross							37
Regency [Member] \| Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred							$ 1,300
Regency [Member] \| Hoover Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		$ 282
Payments to Acquire Businesses, Gross		$ 184
Regency [Member] \| Common Units [Member] \| SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					31,400,000
Regency [Member] \| Common Units [Member] \| Hoover Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		4,000,000
Regency [Member] \| Class F Units [Member] \| SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					6,300,000
ETP [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			49,600,000				49,600,000
Panhandle [Member] \| Regency [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.			31,400,000				31,400,000
Panhandle [Member] \| Regency [Member] \| Class F Units [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.			6,300,000				6,300,000
Panhandle [Member] \| ETP [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			2,200,000				2,200,000
ETE [Member] \| Holdco [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						60.00%
ETP [Member] \| Holdco [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						40.00%	100.00%
Trunkline LNG Transaction [Member]
Business Acquisition [Line Items]
Partners' Capital Account, Units, Redeemed		18,700,000
General administrative expenses reimbursed		$ 75
New England Gas Company [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets			$ 40
Proceeds from divestiture of business			$ 20
Missouri Gas Energy [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets				$ 975

Acquisitions and Related Transactions Acquisitions (2012 Narrative) (Details) $ in Thousands, shares in Millions			1 Months Ended			3 Months Ended																																9 Months Ended		12 Months Ended
	Mar. 31, 2012 USD ($) shares	Jan. 12, 2012 USD ($) shares	Sep. 30, 2013 USD ($)	Apr. 30, 2013 USD ($) shares	Oct. 31, 2012 USD ($) shares	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Sep. 30, 2012 USD ($)	Jun. 30, 2012 USD ($)	Mar. 31, 2012 USD ($)	Sep. 30, 2013 USD ($) shares	Sep. 30, 2012 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Oct. 05, 2012 quarters	Mar. 25, 2012
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares	2.2
General Partner Interest																																																	2.00%
Incentive Distribution Rights																																																	100.00%
Revenues																														$ 12,607,000	$ 12,486,000	$ 12,063,000	$ 11,179,000	$ 11,313,000	$ 2,107,000	$ 1,875,000	$ 1,669,000									$ 48,335,000	$ 16,964,000	$ 8,190,000
Net Income (Loss) Attributable to Parent																																														196,000	304,000	310,000
Relinquishment Of Rights Of Incentive Distributions						$ 8,750	$ 8,750	$ 8,750	$ 8,750	$ 11,250	$ 11,250	$ 11,250	$ 11,250	$ 12,500	$ 12,500	$ 12,500	$ 12,500	$ 18,000	$ 18,000	$ 18,000	$ 18,000	$ 13,000	$ 13,000	$ 12,500	$ 12,500	$ 26,500	$ 26,500	$ 26,500	$ 26,500											$ 35,000	$ 45,000	$ 50,000	$ 72,000	$ 51,000	$ 106,000	329,000
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions																																														0	6,658,000	4,000
Proceeds from the sale of other assets																																														89,000	251,000	$ 33,000
Southern Union Merger [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 3,010,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares	57.0
Business Combination, Acquisition Related Costs																																															38,000
Citrus Merger [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 2,000,000
Interest ownership																																																		50.00%
Payments to Acquire Businesses, Gross	1,900,000
Relinquishment Of Rights Of Incentive Distributions	$ 220,000
Sunoco Merger [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross					$ 2,600,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares					55.0
Business Combination, Acquisition Related Costs																																														28,000
Revenues																																														5,930,000
Net Income (Loss) Attributable to Parent																																														14,000
Holdco Transaction [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 1,400,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares				49.5
Relinquishment Of Rights Of Incentive Distributions					$ 210,000
Number of periods of incentive distributions to be relinquished in future periods upon closing of transaction. \| quarters																																																	12
Canyon Disposal [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred																																														$ 207,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax																																							$ 132,000
ETP's Propane Operations [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets		$ 1,460,000
Sunoco [Member] \| Holdco Transaction [Member]
Business Acquisition [Line Items]
Cash Acquired from Acquisition																																						$ 2,000,000
Southern Union [Member]
Business Acquisition [Line Items]
Revenues																																															1,260,000
Net Income (Loss) Attributable to Parent																																															$ 39,000
Holdco [Member] \| ETE [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest																																						60.00%
Holdco [Member] \| ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest																																						40.00%								100.00%
PES Joint Venture [Member] \| Carlyle Group [Member]
Business Acquisition [Line Items]
Interest ownership																														67.00%																67.00%
PES Joint Venture [Member] \| Sunoco [Member]
Business Acquisition [Line Items]
Interest ownership																														33.00%																33.00%
Retained Interest, Fair Value Disclosure																														$ 75,000																$ 75,000
Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					32.00%
Sunoco Logistics [Member] \| Sunoco Merger [Member]
Business Acquisition [Line Items]
Revenues																																														3,110,000
Net Income (Loss) Attributable to Parent																																														145,000
AmeriGas [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares		30.0
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions		$ 71,000
Contingent Residual Support Agreement Obligation		$ 1,500,000																												$ 1,550,000																$ 1,550,000
AmeriGas [Member] \| Propane Cylinder Exchange Business [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets																																				$ 43,000
Class F Units [Member] \| ETP [Member] \| Holdco Transaction [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares																																						90.7
Missouri Gas Energy [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets			$ 975,000

Acquisitions and Related Transactions Acquisitions (2011 Narrative) (Details) - Lone Star L.L.C. [Member] - USD ($) $ in Millions	1 Months Ended
	May 31, 2011	Dec. 31, 2013	Sep. 30, 2011
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,980
ETP [Member]
Business Acquisition [Line Items]
Subsidiary Interest in Joint Venture		70.00%	70.00%
Payments to Acquire Businesses, Gross	1,380
Regency [Member]
Business Acquisition [Line Items]
Subsidiary Interest in Joint Venture		30.00%	30.00%
Payments to Acquire Businesses, Gross	$ 593

Acquisitions and Related Transactions Acquisitions (Discontinued Operations Table) (Details) - Distribution Operations [Member] - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Revenue from discontinued operations	$ 324	$ 415
Net loss of discontinued operations, excluding effect of taxes and overhead allocations	$ 43	$ 65

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($)
$ in Millions

Oct. 05, 2012

Mar. 25, 2012

Sunoco Merger [Member]

Business Acquisition [Line Items]

Current assets

^[1]

$ 7,312

Property, plant and equipment

^[1]

6,686

Goodwill

^[1]

2,641

Intangible assets

^[1]

1,361

Investments in unconsolidated affiliates

^[1]

240

Note receivable

^[1]

821

Other assets

^[1]

128

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

^[1]

19,189

Current liabilities

^[1]

4,424

Long-term debt obligations, less current maturities

^[1]

2,879

Deferred income taxes

^[1]

1,762

Other non-current liabilities

^[1]

769

Noncontrolling interest

^[1]

3,580

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

^[1]

13,414

Total consideration

^[1]

5,775

Cash received

^[1]

2,714

Total consideration, net of cash received

^[1]

$ 3,061

Southern Union Merger [Member]

Business Acquisition [Line Items]

Current assets

^[2]

$ 556

Property, plant and equipment

^[2]

6,242

Goodwill

^[2]

2,497

Intangible assets

^[2]

Investments in unconsolidated affiliates

^[2]

2,023

Note receivable

^[2]

Other assets

^[2]

163

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

^[2]

11,536

Current liabilities

^[2]

1,348

Long-term debt obligations, less current maturities

^[2]

3,120

Deferred income taxes

^[2]

1,419

Other non-current liabilities

^[2]

284

Noncontrolling interest

^[2]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

^[2]

6,171

Total consideration

^[2]

5,365

Cash received

^[2]

Total consideration, net of cash received

^[2]

$ 5,328

[1]	(1)Includes amounts recorded with respect to Sunoco Logistics.
[2]	(2)Includes ETP’s acquisition of Citrus.

Acquisitions (Pro Forma Results Of Operations Table) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Revenues	$ 40,398	$ 37,560
Net income	868	865
Net income attributable to partners	$ 866	$ 863
Basic net income (loss) per Limited Partner unit	$ 1.55	$ 1.54
Diluted net income (loss) per Limited Partner unit	$ 1.55	$ 1.54

Advances to and Investments in Unconsolidated Affiliates (Details) shares in Millions, $ in Millions		1 Months Ended	12 Months Ended
	Mar. 31, 2012 USD ($)	Jan. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($) years shares	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Mar. 25, 2012
Proceeds from the sale of other assets			$ 89	$ 251	$ 33
AmeriGas common units sold by ETP \| shares		9.2	7.5
Cash proceeds from the sale of AmeriGas common units			$ 346	0	0
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			4,014	4,737	1,497
Proceeds from divestiture of business			0	1,123	0
Gain on deconsolidation of Propane Business			0	1,057	0
Equity in earnings of unconsolidated affiliates			$ 236	212	$ 117
SUG [Member]
Interest ownership			50.00%
Payments to Acquire Businesses, Gross	$ 1,900
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable	105
Citrus [Member]
Interest ownership			50.00%
FGT [Member]
Percentage Ownership Operating Facility			100.00%
Fayetteville Express Pipeline, LLC [Member]
Interest ownership			50.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership			50.00%
RIGS Haynesville Partnership Co. [Member]
Interest ownership			49.99%
AmeriGas [Member]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity			$ 439
Cash proceeds from the sale of AmeriGas common units		$ 381	$ 346
Investments in and Advances to Affiliates, Balance, Shares \| shares			22.1
Common Units Representing An Aggregate Limited Partner Interest			24.00%
Business Acquisition Units Acquired \| shares			29.6
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity, Amortizable Amount			$ 184
Weighted average years of amortizable portion of excess investment in AmeriGas \| years			14
Excess of investment in AmeriGas treated as goodwill			$ 255
Citrus Corp [Member]
Business Acquisition, Percentage of Voting Interests Acquired			50.00%
Citrus Merger [Member]
Interest ownership						50.00%
Payments to Acquire Businesses, Gross	$ 1,900
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity			$ 1,030
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			2,000
FEP [Member] \| ETP [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			144	159
Citrus [Member] \| ETP [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			1,890	1,980
RIGS Haynesville Partnership Co. [Member] \| Regency [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			442	650
MEP [Member] \| Regency [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			548	581
AmeriGas [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			$ 746	$ 1,020

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Investment In Affiliates [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 1,028	$ 945
Property, plant and equipment, net	10,778	10,979
Other assets	2,664	2,677
Total assets	14,470	14,601
Current Liabilities	1,039	1,662
Non-current liabilities	8,139	7,024
Equity	5,292	5,915
Total liabilities and equity	$ 14,470	$ 14,601

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Investment In Affiliates [Abstract]
Revenues	$ 4,695	$ 4,492	$ 3,784
Operating Income	1,197	863	928
Net income	$ 699	$ 491	$ 536

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]
Income (loss) from continuing operations	$ 282	$ 1,383	$ 531
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	99	1,070	221
Income from continuing operations, net of noncontrolling interest	183	313	310
General Partner’s interest in income from continuing operations	0	1	1
Income from continuing operations available to Limited Partners	183	312	309
Dilutive effect of equity-based compensation of subsidiaries	0	1	1
Net Income (Loss) Available to Common Stockholders, Diluted	$ 183	$ 311	$ 308
Weighted average Limited Partner units	560.9	533.4	445.9
Basic	$ 0.33	$ 0.59	$ 0.69
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share	$ 0.02	$ (0.02)	$ 0.00
Earnings Per Share, Diluted [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0.0	0.0	0.0
Weighted average Limited Partner units	560.9	533.4	445.9
Diluted	$ 0.33	$ 0.59	$ 0.69
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share	$ 0.02	$ (0.02)	$ 0.00

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Other Long-term Debt	$ 228	$ 51
Debt Instrument, Unamortized Discount (Premium), Net	301
Long-term Debt	23,199	22,053
Current maturities of long-term debt	637	613
LONG-TERM DEBT, less current maturities	22,562	21,440
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	(7)	(34)
Long-term Debt	2,801	3,826
Current maturities of long-term debt	0	4
LONG-TERM DEBT, less current maturities	2,801	3,840
Parent Company [Member] \| ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	(1,187)	(1,800)
Parent Company [Member] \| 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	(450)	0
Parent Company [Member] \| ETE Senior Secured Term Loan due March 26, 2017 [Member]
Debt Instrument [Line Items]
Secured Debt	0	2,000
Parent Company [Member] \| ETE Senior Secured Term Loan due December 2, 2018 [Member]
Debt Instrument [Line Items]
Secured Debt	171	0
Parent Company [Member] \| ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt	1,000	0
Parent Company [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt Instrument [Line Items]
Outstanding borrowings	0	60
ETP [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	(34)	(14)
Long-term Debt	11,213	9,073
ETP [Member] \| 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	(277)	0
ETP [Member] \| 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes	(267)	0
ETP [Member] \| 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes	546	0
ETP [Member] \| 6.0% Senior Notes, due July 1, 2013 [Member]
Debt Instrument [Line Items]
Senior Notes	0	(350)
ETP [Member] \| 8.5% Senior Notes, due April 15, 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	(292)	(292)
ETP [Member] \| 5.95% Senior Notes, due February 1, 2015 [Member]
Debt Instrument [Line Items]
Senior Notes	(750)	(750)
ETP [Member] \| 6.125% Senior Notes, due February 15, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	(400)
ETP [Member] \| 6.7% Senior Notes, due July 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	(600)	(600)
ETP [Member] \| 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	(400)
ETP [Member] \| 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	(450)	(450)
ETP [Member] \| 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	(700)	0
ETP [Member] \| Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	(800)	(800)
ETP [Member] \| Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	(1,000)	(1,000)
ETP [Member] \| 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes	(800)	0
ETP [Member] \| 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	(350)	0
ETP [Member] \| 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Senior Notes	(550)	(550)
ETP [Member] \| Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Senior Notes	(700)	(700)
ETP [Member] \| Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes	(1,000)	(1,000)
ETP [Member] \| 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes	(450)	0
ETP [Member] \| 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes	(450)	0
ETP [Member] \| 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	(400)
ETP [Member] \| ETP Revolving Credit Facility, due October 27, 2016 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	65	1,395
Regency [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	0	3
Long-term Debt	3,310	2,157
Regency [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	510	192
Regency [Member] \| 9.375% Senior Notes due June 1, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	0	(162)
Regency [Member] \| 6.875% Senior Notes, due December 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	(600)	(600)
Regency [Member] \| 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	0
Regency [Member] \| 6.5% Senior Notes, due July 15, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	(500)	(500)
Regency [Member] \| 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes	(700)	(700)
Regency [Member] \| 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes	(600)	0
Southern Union [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	48	49
Long-term Debt	217	1,519
Southern Union [Member] \| 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	(82)	(360)
Southern Union [Member] \| 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes	(33)	(300)
Southern Union [Member] \| 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes	54	600
Southern Union [Member] \| Southern Union Revolving Credit Facility, due May 20, 2016 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	0	210
Sunoco [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	70	104
Long-term Debt	1,035	1,069
Sunoco [Member] \| 4.875% Senior Notes, due 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	(250)	(250)
Sunoco [Member] \| 9.625% Senior Notes, due 2015 [Member]
Debt Instrument [Line Items]
Senior Notes	(250)	(250)
Sunoco [Member] \| 5.75% Senior Notes, due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	(400)
Sunoco [Member] \| 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Subordinated Debt	65	65
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Outstanding borrowings		119
Debt Instrument, Unamortized Discount (Premium), Net	118	143
Long-term Debt	2,503	1,732
Sunoco Logistics [Member] \| 8.75% Senior Notes, due February 15, 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	(175)	(175)
Sunoco Logistics [Member] \| 6.125% Senior Notes, due May 15, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	(175)	(175)
Sunoco Logistics [Member] \| 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	(250)	(250)
Sunoco Logistics [Member] \| Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	(300)	(300)
Sunoco Logistics [Member] \| 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Senior Notes	(350)	0
Sunoco Logistics [Member] \| 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Senior Notes	250	250
Sunoco Logistics [Member] \| Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes	(300)	(300)
Sunoco Logistics [Member] \| 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Senior Notes	(350)	0
Sunoco Logistics [Member] \| Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	0	26
Sunoco Logistics [Member] \| Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	35	20
Sunoco Logistics [Member] \| Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	0	93
Sunoco Logistics [Member] \| Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	200	0
Transwestern [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	(1)	(1)
Long-term Debt	869	869
Transwestern [Member] \| 5.39% Senior Unsecured Notes, due November 17, 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	(88)	(88)
Transwestern [Member] \| 5.54% Senior Unsecured Notes, due November 17, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	(125)	(125)
Transwestern [Member] \| 5.64% Senior Unsecured Notes, due May 24, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	(82)	(82)
Transwestern [Member] \| 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	(175)	(175)
Transwestern [Member] \| 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	(150)	(150)
Transwestern [Member] \| 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	(175)	(175)
Transwestern [Member] \| 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes	(75)	(75)
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	107	136
Long-term Debt	1,023	1,757
Panhandle [Member] \| 6.05% Senior Notes, due August 15, 2013 [Member]
Debt Instrument [Line Items]
Senior Notes	0	(250)
Panhandle [Member] \| 6.20% Senior Notes, due November 1, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	(300)	(300)
Panhandle [Member] \| 7.00% Senior Notes, due June 15, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	(400)	(400)
Panhandle [Member] \| 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	(150)	(150)
Panhandle [Member] \| 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes	(66)	(66)
Panhandle [Member] \| Term Loan due February 23, 2015 [Member]
Debt Instrument [Line Items]
Subordinated Debt	$ 0	$ 455

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
2014	$ 812
2015	1,047
2016	375
2017	1,220
2018	1,976
Thereafter	17,468
Long-term Debt	23,199	$ 22,053
Excluding unamortized premiums and fair value adjustments [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 22,898

Debt Obligations (Senior Notes and Term Loans Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Sep. 30, 2013	Jan. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 28, 2014	Jun. 24, 2013
Required repayment of term loan			$ 50
Repayments of Long-term Debt	$ 455		11,951	$ 8,848	$ 6,264
Write off of Deferred Debt Issuance Cost					0
Long-term Debt			$ 23,199	22,053
Debt instrument, interest rate, stated percentage			4.50%
ETP Note Exchange							$ 1,090
8.25% Senior Notes, due November 14, 2029 [Member]
Debt instrument, interest rate, stated percentage							8.25%
Percent of SUG Notes Exchanged for ETP Notes							89.00%
ETE Credit Facility [Member]
Letters Of Credit Availablity			$ 150
Line of Credit Facility, Current Borrowing Capacity			600			$ 800
Line of Credit Facility, Maximum Borrowing Capacity			1,000
3.45% Senior Notes due January 2023 [Member]
Senior Notes		$ 350
Debt instrument, interest rate, stated percentage		3.45%
Junior Subordinated Debt [Member]
Percent of SUG Notes Exchanged for ETP Notes							91.00%
3.6% Senior Notes due February 1, 2023 [Member]
Senior Notes		$ 800
Debt instrument, interest rate, stated percentage		3.60%
Sunoco Merger [Member]
Senior Notes			$ 965
5.15% Senior Notes due February 1, 2043 [Member]
Senior Notes		$ 450
Debt instrument, interest rate, stated percentage		5.15%
4.15% Senior Notes due October 1, 2020 [Member]
Senior Notes	$ 700
Debt instrument, interest rate, stated percentage	4.15%
4.9% Senior Notes due February 1, 2024 [Member]
Senior Notes	$ 350
Debt instrument, interest rate, stated percentage	4.90%
5.95% Senior Notes due October 1, 2043 [Member]
Senior Notes	$ 450
7.60% Senior Notes, due February 1, 2024 [Member]
Debt instrument, interest rate, stated percentage							7.60%
Percent of SUG Notes Exchanged for ETP Notes							77.00%
4.95% Senior Notes due January 2043 [Member]
Senior Notes		$ 350
Debt instrument, interest rate, stated percentage		4.95%
SUG [Member] \| Junior Subordinated Debt [Member]
Debt Instrument, Interest Rate, Effective Percentage			3.32%
Debt Instrument, Description of Variable Rate Basis			three-month LIBOR rate plus 3.0175%
SUG [Member] \| Variable Rate Portion of Debt [Member] \| Junior Subordinated Debt [Member]
Senior Notes			$ 600
Parent Company [Member]
Repayments of Long-term Debt			3,235	162	20
Write off of Deferred Debt Issuance Cost			0	62
Long-term Debt			2,801	3,826
Repayments of Related Party Debt			0	221	$ 0
Parent Company [Member] \| 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes			$ 450	0
Debt instrument, interest rate, stated percentage			5.875%
Debt instrument, maturity date			Jan. 15, 2024
Panhandle [Member]
Long-term Debt			$ 1,023	1,757
ETP [Member]
Long-term Debt			11,213	9,073
Proceeds from Issuance of Senior Long-term Debt	$ 1,470	$ 1,240
Sunoco Logistics [Member]
Long-term Debt			$ 2,503	1,732
Outstanding borrowings				$ 119
Proceeds from Issuance of Senior Long-term Debt		$ 691
Base Rate Loans [Member] \| Maximum [Member] \| ETE Credit Facility [Member]
Debt Instrument, Basis Spread on Variable Rate			1.50%
ETE Senior Secured Term Loan due December 2, 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity			$ 1,000

Debt Obligations (Credit Facilities Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 28, 2014	Sep. 30, 2013	Jun. 24, 2013
Bridge loan related fees	$ 0	$ 62	$ 0
ETP Note Exchange						$ 1,090
Long-term Debt	$ 23,199	22,053
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Parent Company [Member]
Long-term Debt	$ 2,801	3,826
Repayments of Related Party Debt	0	221	$ 0
ETP [Member]
Long-term Debt	11,213	9,073
Sunoco Logistics [Member]
Amount Outstanding		119
Long-term Debt	2,503	1,732
Regency [Member]
Amount of Shares Agreed to Purchase	400
Long-term Debt	3,310	2,157
ETE Credit Facility [Member]
Revolving credit facility	600			$ 800
Letters Of Credit Availablity	150
Line of Credit Facility, Maximum Borrowing Capacity	1,000
Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member] \| Sunoco Logistics [Member]
Line of Credit Facility, Maximum Borrowing Capacity	200
ETE Senior Secured Revolving Credit Facilities [Member] \| Parent Company [Member]
Amount Outstanding	0	60
Regency Credit Facility [Member]
Revolving credit facility	1,200
Letters Of Credit Availablity	$ 300
Debt instrument, maturity date	May 21, 2018
Amount Outstanding	$ 510
Amount available for future borrowings	676
Letters of credit outstanding, amount	$ 14
Weighted average interest rate on amount outstanding	2.17%
Line Of Credit Facility Fronting Fee Percentage	0.20%
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] \| Sunoco Logistics [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 350
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Revolving credit facility	35
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] \| Sunoco Logistics [Member]
Revolving credit facility	1,500
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,250
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Nov. 01, 2018
Amount Outstanding	$ 200	0
ETP Revolving Credit Facility, due October 27, 2016 [Member] \| ETP [Member]
Debt instrument, maturity date	Oct. 27, 2016
Amount Outstanding	$ 65	1,395
Debt Instrument, Interest Rate, Stated Percentage
Revolving Credit Facility [Member] \| Regency [Member]
Debt instrument, maturity date	May 01, 2018
Amount Outstanding	$ 510	192
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Aug. 22, 2016
Amount Outstanding	$ 0	$ 93
Federal Funds Effective Rate [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.50%
LIBOR [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.00%
Increase in Credit Facility [Member] \| Regency Credit Facility [Member]
Revolving credit facility				1,500
Letters Of Credit Availablity				$ 500
Maximum [Member] \| Regency Credit Facility [Member]
Line of credit facility, unused capacity, commitment fee percentage	0.45%
Line Of Credit Participation Fee	2.50%
Maximum [Member] \| Letter of Credit [Member] \| ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	2.50%
Maximum [Member] \| Base Rate Loans [Member] \| ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.50%
Maximum [Member] \| Base Rate Loans [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.50%
Maximum [Member] \| Eurodollar Loans [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	2.50%
Minimum [Member] \| Regency Credit Facility [Member]
Line of credit facility, unused capacity, commitment fee percentage	0.30%
Line Of Credit Participation Fee	1.625%
Minimum [Member] \| Letter of Credit [Member] \| ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.75%
Minimum [Member] \| Base Rate Loans [Member] \| ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.75%
Minimum [Member] \| Base Rate Loans [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.625%
Minimum [Member] \| Eurodollar Loans [Member] \| Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.63%
Line Of Credit Maturity October 27, 2016 [Member]
Letters of credit outstanding, amount	$ 93
Line of Credit Facility, Interest Rate at Period End	1.67%
ETP Revolving Credit Facility, due October 27, 2016 [Member]
Revolving credit facility					$ 2,500
ETP Revolving Credit Facility, due October 27, 2016 [Member] \| ETP [Member]
Amount available for future borrowings	$ 2,340

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013
Debt Instrument [Line Items]
Debt instrument covenant maximum leverage ratio		6.0
Debt instrument covenant maximum leverage ratio, permitted during specific acquisition period		7
Debt instrument covenant minimum fixed charge coverage ratio		1.5
West Texas Gulf [Member]
Debt Instrument [Line Items]
Fixed Charge Coverage Ratio	1.12	1.12
Debt instrument covenant maximum leverage ratio		2.00
Debt instrument covenant minimum fixed charge coverage ratio	1.00
Leverage Ratio	0.88	0.88
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		5.00
Maximum consolidated EBITA to consolidated interest expense		2.50
Maximum consolidated senior secured leverage ratio		3
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio		5.00
Adjusted EBITDA Ratio		2.80
Acquisition Period [Member] \| Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio		5.50
Minimum [Member] \| West Texas Gulf [Member]
Debt Instrument [Line Items]
Debt instrument covenant minimum fixed charge coverage ratio	0.80
Maximum [Member] \| West Texas Gulf [Member]
Debt Instrument [Line Items]
Debt instrument covenant minimum fixed charge coverage ratio	1.00

Debt Obligations Debt Obligations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Debt Instrument, Interest Rate, Stated Percentage	4.50%
ETE 7.5% Senior Notes due 2020 [Member] \| Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt instrument, maturity date	Oct. 15, 2020
5.875% Senior Notes due January 15, 2024 [Member] \| Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.875%
Debt instrument, maturity date	Jan. 15, 2024
ETE Senior Secured Term Loan due March 26, 2017 [Member] \| Parent Company [Member]
Debt instrument, maturity date	Mar. 26, 2017
ETE Senior Secured Term Loan due December 2, 2018 [Member] \| Parent Company [Member]
Debt instrument, maturity date	Dec. 02, 2018
ETE Senior Secured Term Loan due December 2, 2019 [Member] \| Parent Company [Member]
Debt instrument, maturity date	Dec. 02, 2019
6.0% Senior Notes, due July 1, 2013 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt instrument, maturity date	Jul. 01, 2013
8.5% Senior Notes, due April 15, 2014 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.50%
Debt instrument, maturity date	Apr. 15, 2014
5.95% Senior Notes, due February 1, 2015 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt instrument, maturity date	Feb. 01, 2015
6.125% Senior Notes, due February 15, 2017 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt instrument, maturity date	Feb. 15, 2017
6.7% Senior Notes, due July 1, 2018 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.70%
Debt instrument, maturity date	Jul. 01, 2018
9.7% Senior Notes, due March 15, 2019 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%
Debt instrument, maturity date	Mar. 15, 2019
9.0% Senior Notes due April 15, 2019 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt instrument, maturity date	Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt instrument, maturity date	Oct. 01, 2020
Senior Notes 4.65% Due June 1, 2021 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt instrument, maturity date	Jun. 01, 2021
Senior Notes 5.20% Due February 1, 2022 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt instrument, maturity date	Feb. 01, 2022
3.6% Senior Notes due February 1, 2023 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt instrument, maturity date	Feb. 01, 2023
4.9% Senior Notes due February 1, 2024 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt instrument, maturity date	Feb. 01, 2024
6.625% Senior Notes, due October 15, 2036 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Debt instrument, maturity date	Oct. 15, 2036
7.5% Senior Notes, due July 1, 2038 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt instrument, maturity date	Jul. 01, 2038
Senior Notes 6.05% Due June 1, 2041 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt instrument, maturity date	Jun. 01, 2041
Senior Notes 6.50% Due February 1, 2042 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt instrument, maturity date	Feb. 01, 2042
5.15% Senior Notes due February 1, 2043 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt instrument, maturity date	Feb. 01, 2043
5.95% Senior Notes due October 1, 2043 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt instrument, maturity date	Oct. 01, 2043
ETP Revolving Credit Facility, due October 27, 2016 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage
Debt instrument, maturity date	Oct. 27, 2016
6.05% Senior Notes, due August 15, 2013 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt instrument, maturity date	Aug. 15, 2013
6.20% Senior Notes, due November 1, 2017 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Debt instrument, maturity date	Nov. 01, 2017
7.00% Senior Notes, due June 15, 2018 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt instrument, maturity date	Jun. 15, 2018
8.125% Senior Notes, due June 1, 2019 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Debt instrument, maturity date	Jun. 01, 2019
7.00% Senior Notes, due July 15, 2029 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt instrument, maturity date	Jul. 15, 2029
Term Loan due February 23, 2015 [Member] \| Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.84%
Debt instrument, maturity date	Feb. 23, 2015
9.375% Senior Notes due June 1, 2016 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.375%
Debt instrument, maturity date	Jun. 01, 2016
6.875% Senior Notes, due December 1, 2018 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Debt instrument, maturity date	Dec. 01, 2018
5.75% Senior Notes due September 1, 2020 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt instrument, maturity date	Sep. 01, 2020
6.5% Senior Notes, due July 15, 2021 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt instrument, maturity date	Jul. 15, 2021
5.5% Senior Notes, due April 15, 2023 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt instrument, maturity date	Apr. 15, 2023
4.5% Senior Notes due November 1, 2023 [Member] \| Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt instrument, maturity date	Nov. 01, 2023
Revolving Credit Facility [Member] \| Regency [Member]
Debt instrument, maturity date	May 01, 2018
7.60% Senior Notes, due February 1, 2024 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt instrument, maturity date	Feb. 01, 2024
7.60% Senior Notes, due February 1, 2024 [Member] \| Southern Union [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt instrument, maturity date	Feb. 01, 2024
8.25% Senior Notes, due November 14, 2029 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt instrument, maturity date	Nov. 15, 2029
8.25% Senior Notes, due November 14, 2029 [Member] \| Southern Union [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt instrument, maturity date	Nov. 14, 2029
7.2% Junior Subordinated Notes due November 21, 2066 [Member] \| ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt instrument, maturity date	Nov. 01, 2066
7.2% Junior Subordinated Notes due November 21, 2066 [Member] \| Southern Union [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt instrument, maturity date	Nov. 01, 2066
Southern Union Revolving Credit Facility, due May 20, 2016 [Member] \| Southern Union [Member]
Debt Instrument, Interest Rate, Stated Percentage
Debt instrument, maturity date	May 20, 2016
4.875% Senior Notes, due 2014 [Member] \| Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt instrument, maturity date	Oct. 15, 2014
9.625% Senior Notes, due 2015 [Member] \| Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.625%
Debt instrument, maturity date	Apr. 15, 2015
5.75% Senior Notes, due 2017 [Member] \| Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt instrument, maturity date	Jan. 15, 2017
9.00% Debentures, due 2024 [Member] \| Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt instrument, maturity date	Nov. 01, 2024
8.75% Senior Notes, due February 15, 2014 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.75%
Debt instrument, maturity date	Feb. 15, 2014
6.125% Senior Notes, due May 15, 2016 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt instrument, maturity date	May 15, 2016
5.50% Senior Notes, due February 15, 2020 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt instrument, maturity date	Feb. 15, 2020
Senior Note 4.65% Due February 15, 2022 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt instrument, maturity date	Feb. 15, 2022
3.45% Senior Notes due January 2023 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt instrument, maturity date	Jan. 15, 2023
6.85% Senior Notes, due February 15, 2040 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt instrument, maturity date	Feb. 15, 2040
Senior Note 6.10%, due February 15, 2042 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt instrument, maturity date	Feb. 15, 2042
4.95% Senior Notes due January 2043 [Member] \| Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt instrument, maturity date	Jan. 15, 2043
Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Aug. 21, 2014
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Apr. 30, 2015
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Aug. 22, 2016
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] \| Sunoco Logistics [Member]
Debt instrument, maturity date	Nov. 01, 2018
5.39% Senior Unsecured Notes, due November 17, 2014 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.39%
Debt instrument, maturity date	Nov. 17, 2014
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.54%
Debt instrument, maturity date	Nov. 17, 2016
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.64%
Debt instrument, maturity date	May 24, 2017
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt instrument, maturity date	Dec. 09, 2020
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt instrument, maturity date	May 24, 2022
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt instrument, maturity date	Dec. 09, 2024
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] \| Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt instrument, maturity date	May 24, 2037

Redeemable Preferred Units (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

May 25, 2010

Preferrred Units Issued Stated Price

$ 100

Proceeds from Issuance of Preferred Stock and Preference Stock

$ 300,000

Preferred Stock Redemption Premium

40,000

Gain Recognized from Conversion of Series A Preferred Units

26,000

Conversion of Stock, Amount Converted

$ (41,000)

ETE Preferred Units [Member]

Preferred units, issued

3,000,000

Aggregate liquidation preference

$ 300,000

Quarterly cash distribution, per preferred unit

$ 2.0

Preferred units outstanding

3,000,000

Preferred units carrying value non-cash adjustment

$ 9,000

$ 8,000

Preferred units, fair value

$ 331,000

Regency Preferred Units [Member]

Preferred units outstanding

4,371,586

1,900,000

4,371,586

Mandatory redeemable price of units outstanding

$ 71

$ 32,000

$ 73,000

Conversion of Stock, Shares Converted

(2,459,017)

Conversion of Stock, Amount Converted

^[1]

$ (41,000)

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

2,050,854

Regency Mandatorily Redeemable Amount At Expiration [Member]

Mandatory redeemable price of units outstanding

$ 35,000

[1]	(1) This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Redeemable Preferred Units Schedule Of Redeemable Preferred Units (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Preferred Units [Line Items]

Conversion of Stock, Amount Converted

$ (41,000)

Regency Preferred Units [Member]

Preferred Units [Line Items]

Preferred Units, Outstanding

1,900,000

4,371,586

Preferred Units Redemption Amount

$ 32,000

$ 73,000

$ 71

Conversion of Stock, Shares Converted

(2,459,017)

Conversion of Stock, Amount Converted

^[1]

$ (41,000)

Accretion to Redemption Value, Adjustment

$ 2

[1]	(1) This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Equity (Narrative) (Details) - USD ($)
$ / shares in Units, $ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

36 Months Ended

Mar. 31, 2012

Apr. 30, 2013

Oct. 31, 2012

Jul. 31, 2012

Nov. 30, 2011

Oct. 31, 2011

May 31, 2011

^[4]

Apr. 30, 2011

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Oct. 05, 2012

Dec. 31, 2008

Stock Repurchase Program, Authorized Amount

$ 1,000,000

Stock Repurchased and Retired During Period, Shares

1,695,200

Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted

1,500,000

Common Units Issued Inconnection With The Equity Distribution Agreement

16,900,000

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

559,923,300

559,911,216

445,900,000

559,923,300

445,900,000

Limited Partner interest in the Partnership, percentage

99.48%

Gain from subsidiary issuances of common units

$ (384,000)

$ 80,000

$ 153,000

Class E Unit Distribution Rate

11.10%

Class E Unit Maximum Distribution

$ 1.41

Class F Unit Distribution Rate

35.00%

Class F Unit Maximum Distribution

$ 3.75

Relinquishment Of Rights Of Incentive Distributions

$ 8,750

$ 11,250

$ 12,500

$ 18,000

$ 13,000

$ 12,500

$ 26,500

$ 35,000

$ 45,000

$ 50,000

$ 72,000

$ 51,000

$ 106,000

$ 329,000

ETP [Member]

Common units issued through public offering

^[1]

13,800,000

15,500,000

15,200,000

14,200,000

Stock Issued During Period, Shares, Dividend Reinvestment Plan

3,700,000

Proceeds from issuance of common units

^[2]

$ 657,000

^[3]

$ 671,000

^[3]

$ 660,000

^[3]

$ 695,000

Equity Distribution Agreements, Value of Units Available to be Issued

$ 145,000

Common Units to be Issued Under Distribution Reinvestment Plan

5,800,000

Stock Issued During Period, Value, Dividend Reinvestment Plan

$ 109,000

$ 43,000

$ 15,000

Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan

2,100,000

Regency [Member]

Common units issued through public offering

^[1]

12,650,000

11,500,000

8,500,001

Proceeds from issuance of common units

$ 297,000

^[2],[3]

$ 232,000

^[3]

$ 204,000

^[2]

Equity Distribution Agreement, maximum aggregate value of common units sold

$ 200,000

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

$ 149,000

Class D Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted

1,540,000

Limited Partners' Capital Account, Units Outstanding

1,540,000

Class E Units [Member]

Partners' Capital Account, Units

8,900,000

Class F Units [Member] | Sunoco [Member]

Partners' Capital Account, Units

40,000,000

Class H Units [Member]

Partners' Capital Account, Units

50,200,000

Allocation of Profits, Losses and Other by Sunoco, Percent

50.05%

Holdco Transaction [Member]

Relinquishment Of Rights Of Incentive Distributions

$ 210,000

Holdco Transaction [Member] | Class G Units [Member]

Partners' Capital Account, Units

90,700,000

Additional Units [Member] | Class D Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted

40,000

January 2013 [Member]

Equity Distribution Agreement, maximum aggregate value of common units sold

$ 200,000

May 2013 [Member]

Equity Distribution Agreement, maximum aggregate value of common units sold

800,000

Equity Distribution Agreement [Member] | ETP [Member]

Proceeds from Issuance of Common Stock

846,000

Fees and Commissions

9,000

December 2016 [Member]

Relinquishment Of Rights Of Incentive Distributions

50,000

December 2017 [Member]

Relinquishment Of Rights Of Incentive Distributions

50,000

December 2018 [Member]

Relinquishment Of Rights Of Incentive Distributions

45,000

December 2019 [Member]

Relinquishment Of Rights Of Incentive Distributions

$ 35,000

[1]	Date Number ofETP CommonUnits Price per ETPUnit Net ProceedsApril 2011 14.2 $50.52 $695November 2011 15.2 44.67 660July 2012 15.5 44.57 671April 2013 13.8 48.05 657
[2]	.
[3]	Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility
[4]	.

Equity (Change In ETE Common Units) (Details) - shares	12 Months Ended
Equity (Change In ETE Common Units) (Details) - shares	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2011	Dec. 31, 2008
Outstanding	559,923,300	559,911,216	445,900,000	559,911,216		445,900,000	445,900,000
Issuance of restricted Common Units under long-term incentive plans	0	0	0
Number of Common Units, end of period	559,923,300	559,911,216	445,900,000
SUG Merger [Member]
Business Acquisition Units Acquired						0
Units Acquired for Equity [Member] \| SUG Merger [Member]
Business Acquisition Units Acquired				114,000,000	0

Equity Equity (Schedule Of Common Units Sold In Public Offering) (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

12 Months Ended

Mar. 31, 2012

Apr. 30, 2013

Jul. 31, 2012

Nov. 30, 2011

Oct. 31, 2011

May 31, 2011

^[4]

Apr. 30, 2011

Dec. 31, 2013

ETP [Member]

Capital Unit [Line Items]

Common Units to be Issued Under Distribution Reinvestment Plan

5,800,000

Number of ETP Common Units

^[1]

13,800,000

15,500,000

15,200,000

14,200,000

Price per ETP Unit

$ 48.05

$ 44.57

$ 44.67

$ 50.52

Net Proceeds

^[2]

$ 657

^[3]

$ 671

^[3]

$ 660

^[3]

$ 695

Regency [Member]

Capital Unit [Line Items]

Number of ETP Common Units

^[1]

12,650,000

11,500,000

8,500,001

Price per ETP Unit

$ 24.47

$ 20.92

Net Proceeds

$ 297

^[2],[3]

$ 232

^[3]

$ 204

^[2]

[1]	Date Number ofETP CommonUnits Price per ETPUnit Net ProceedsApril 2011 14.2 $50.52 $695November 2011 15.2 44.67 660July 2012 15.5 44.57 671April 2013 13.8 48.05 657
[2]	.
[3]	Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility
[4]	.

Equity (Quarterly Distributions Of Available Cash) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended													12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Partners' Capital Account, Distributions														$ 733	$ 666	$ 526
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 10, 2014	Nov. 08, 2013	Aug. 08, 2013	May 09, 2013	Feb. 08, 2013
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	May 15, 2013	Feb. 14, 2013
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.66250	$ 0.63000	$ 0.60000	$ 0.57250	$ 0.54500
Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 07, 2014	Nov. 04, 2013	Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Nov. 06, 2012	Aug. 06, 2012	May 04, 2012	Feb. 07, 2012	Nov. 04, 2011	Aug. 05, 2011	May 06, 2011	Feb. 07, 2011
Distribution Made to Limited Partner, Distribution Date	Feb. 19, 2014	Nov. 19, 2013	Aug. 19, 2013	May 17, 2013	Feb. 19, 2013	Nov. 16, 2012	Aug. 17, 2012	May 18, 2012	Feb. 17, 2012	Nov. 18, 2011	Aug. 19, 2011	May 19, 2011	Feb. 18, 2011
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.3463	$ 0.3363	$ 0.3275	$ 0.3225	$ 0.3175	$ 0.3125	$ 0.3125	$ 0.3125	$ 0.3125	$ 0.3125	$ 0.3125	$ 0.2800	$ 0.2700
ETP [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 07, 2014	Nov. 04, 2013	Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Nov. 06, 2012	Aug. 06, 2012	May 04, 2012	Feb. 07, 2012	Nov. 04, 2011	Aug. 05, 2011	May 06, 2011	Feb. 07, 2011
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	May 15, 2013	Feb. 14, 2013	Nov. 14, 2012	Aug. 14, 2012	May 15, 2012	Feb. 14, 2012	Nov. 14, 2011	Aug. 15, 2011	May 16, 2011	Feb. 14, 2011
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.92000	$ 0.90500	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375
Regency [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 07, 2014	Nov. 04, 2013	Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Nov. 06, 2012	Aug. 06, 2012	May 07, 2012	Feb. 06, 2012	Nov. 07, 2011	Aug. 05, 2011	May 06, 2011	Feb. 07, 2011
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	May 13, 2013	Feb. 14, 2013	Nov. 14, 2012	Aug. 14, 2012	May 14, 2012	Feb. 13, 2012	Nov. 14, 2011	Aug. 12, 2011	May 13, 2011	Feb. 14, 2011
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.48	$ 0.470	$ 0.465	$ 0.460	$ 0.460	$ 0.460	$ 0.460	$ 0.460	$ 0.460	$ 0.455	$ 0.450	$ 0.445	$ 0.445

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Partners' Capital Notes [Abstract]
Net gains on commodity related hedges	$ (4)	$ (3)
Unrealized gains on available-for-sale securities	2	0
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	(1)	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	56	(10)
AOCI attributable to equity method investments	8	(9)
Subtotal	61	(22)
Amounts attributable to noncontrolling interest	(52)	10
Total AOCI included in partners' capital, net of tax	$ 9	$ (12)

- 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 + Details

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Other Comprehensive Income Loss Commodity Hedges Tax	$ 0	$ 2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	(39)	5
Other Comprehensive Income (Loss), Tax	$ (39)	$ 7

Equity (Relinquishments of Incentive Distribution Rights) (Details) - USD ($) $ in Thousands	3 Months Ended																								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Relinquishment Of Rights Of Incentive Distributions	$ 8,750	$ 8,750	$ 8,750	$ 8,750	$ 11,250	$ 11,250	$ 11,250	$ 11,250	$ 12,500	$ 12,500	$ 12,500	$ 12,500	$ 18,000	$ 18,000	$ 18,000	$ 18,000	$ 13,000	$ 13,000	$ 12,500	$ 12,500	$ 26,500	$ 26,500	$ 26,500	$ 26,500	$ 35,000	$ 45,000	$ 50,000	$ 72,000	$ 51,000	$ 106,000	$ 329,000

Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Affiliated Entity [Member]
Vesting Period	5 years
Percentage Of Units Vesting In Current Year	20.00%
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	6,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	5,693,789
Unvested awards	65,980
Units Vested In Period	56,048
Fair Value Of Units As Of The Vesting Date	$ 2.1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1.0
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	1 year 8 months
ETP Unit-Based Compensation Plans [Member]
Awards granted	2,100,000
Unvested awards	3,200,000	1,900,000
Grant Date Fair Value Per Unit	$ 49.65	$ 46.95
Vesting Period	5 years
Units Vested In Period	600,000
Fair Value Of Units As Of The Vesting Date	$ 26.0	$ 29.0	$ 27.0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 116.0
Granted unvested awards	$ 50.54	$ 43.93	$ 48.35
Preferred units carrying value non-cash adjustment	$ 1.0	$ 1.0	$ 2.0
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 22 days
Sunoco Logistics Unit-Based Compensation Plans [Member]
Units Remaining To Be Awarded	600,000
Unvested awards	600,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 21.0
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 9 months 25 days
Regency Common Unit Options [Member]
Exercisable at the end of the period, Units	142,550
Options, Outstanding, Weighted Average Exercise Price	$ 22.04
Regency Phantom Units [Member]
Unvested awards	982,242
Grant Date Fair Value Per Unit	$ 23.16
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 19.0
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	3 years 4 months
Employee [Member] \| ETE Long-Term Incentive Plan [Member]
Awards granted	0
Director [Member]
Vesting Period	5 years
Director [Member] \| ETE Long-Term Incentive Plan [Member]
Awards granted	12,084
Class D Units [Member] \| ETE Long-Term Incentive Plan [Member]
Awards granted	1,540,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 37.0
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		3 years 5 months 18 days

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 shares in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	3.2	1.9
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 49.65	$ 46.95
Awards granted	2.1
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 50.54	$ 43.93	$ 48.35
Awards vested	(0.6)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 45.62
Awards forfeited	(0.2)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 45.72

Income Taxes Narrative (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Income Taxes Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		$ 425
Operating Loss Carryforwards		216
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax		217	$ 270
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects		(74)	$ (94)
Amount of Deferred Gain Challenged by IRS		545
Deferred Gain Associated with Like Kind Exchange		690
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax		418
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit		$ 6
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information		5
Proceeds from Income Tax Refunds		$ 372
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts		372
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense		1
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		6
Expiring 2013 to 2032 [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards		101
Holdco [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax		$ 40
ETE [Member] \| Holdco [Member]
Operating Loss Carryforwards [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
ETP [Member] \| Holdco [Member]
Operating Loss Carryforwards [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	40.00%	100.00%

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current expense (benefit):
Federal	$ 51	$ (3)	$ (1)
State	(1)	6	17
Total	50	3	16
Deferred expense:
Federal	(14)	41	0
State	57	10	1
Total	43	51	1
Total income tax expense from continuing operations	$ 93	$ 54	$ 17

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate

35.00%

Income tax expense (benefit) at U.S. statutory rate of 35 percent

$ (172)

$ (4)

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount

241

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount

Increase (reduction) in income taxes resulting from:

State income taxes (net of federal income tax effects)

Other

(17)

Total income tax expense from continuing operations

$ 17

Corporate Subsidiaries [Member]

Income tax expense (benefit) at U.S. statutory rate of 35 percent

^[1]

(172)

(4)

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount

241

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount

^[1]

Increase (reduction) in income taxes resulting from:

State income taxes (net of federal income tax effects)

^[1]

Other

^[1]

(16)

Total income tax expense from continuing operations

^[2]

Partnership [Member]

Income tax expense (benefit) at U.S. statutory rate of 35 percent

^[2]

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount

Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount

^[2]

Increase (reduction) in income taxes resulting from:

State income taxes (net of federal income tax effects)

^[2]

Other

^[2]

(1)

Total income tax expense from continuing operations

^[2]

$ 9

$ 2

[1]

December 31, 2013 December 31, 2012 Corporate Subsidiaries(1) Partnership(2) Consolidated Corporate Subsidiaries(1) Partnership(2) ConsolidatedIncome tax expense (benefit) at U.S. statutory rate of 35 percent$(172) $— $(172) $(4) $— $(4)Increase (reduction) in income taxes resulting from: Nondeductible goodwill241 — 241 — — —Nondeductible executive compensation— — — 28 — 28State income taxes (net of federal income tax effects)31 10 41 9 2 11Other(16) (1) (17) 19 — 19Income tax from continuing operations$84 $9 $93 $52 $2 $54

[2]

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effects of Temporary Differences that Comprise Net Deferred Income Tax Liability [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	$ 0	$ 0	$ 0
Deferred income tax assets:
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	217	270
Pension and other postretirement benefits	57	127
Long term debt	108	117
Other	104	290
Deferred Tax Assets, Gross	486	804
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	(74)	(94)
Net deferred income tax assets	412	710
Deferred income tax liabilities:
Properties, plants and equipment	(1,624)	(2,026)
Inventory	(302)	(516)
Investments in unconsolidated affiliates	(2,245)	(1,543)
Deferred Tax Liabilities, Intangible Assets	(180)	(192)
Other	(45)	(129)
Deferred Tax Liabilities, Gross	4,396	4,406
Deferred Tax Liabilities	(3,984)	(3,696)	$ (214)
Deferred Tax Liabilities, Net, Current	(119)	(130)
DEFERRED INCOME TAXES	$ 3,865	$ 3,566

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of Net Deferred Income Tax [Abstract]
Deferred Tax Liabilities, Net	$ (3,984)	$ (3,696)	$ (214)
Valuation allowance	74	94
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	217	270
Increase in Tax Liability Attributable to Southern Union	0	(1,428)
Increase in Tax Liability Attributable to Sunoco Acquisition	0	(1,989)
Deferred Income Tax Liability as a Result of SUGS Contribution to Regency	(115)	0
Noncurrent asset	(124)	(62)
Deferred Tax Liabilities, Other	$ (49)	$ (3)

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in Unrecognized Tax Benefits [Abstract]
Unrecognized Tax Benefits, Increase Resulting from Acquisition	$ 0	$ 28	$ 0
Balance at beginning of year	27	2	2
Additions attributable to tax positions taken in the current year	0	0	1
Additions attributable to tax positions taken in prior years	406	0	0
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	4	3	1
Balance at end of year	429	$ 27	$ 2
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 425

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2012 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Jan. 12, 2012 USD ($)
Payments for Environmental Liabilities		$ 41,000,000	$ 12,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Lease Expiration Date		Dec. 31, 2056
Operating leases rent expense		$ 151,000,000	60,000,000	$ 29,000,000
Environmental Costs Recognized, Recovery Credited to Expense		19,000,000
Total environmental liabilities		403,000,000	212,000,000
Guarantor Obligations, Current Carrying Value		600,000,000
Operating Leases, Rent Expense, Contingent Rentals		22,000,000	6,000,000
Operating Leases, Income Statement, Sublease Revenue		24,000,000	$ 4,000,000
Site Contingency, Number of Sites Needing Remediation			40
FGT [Member]
Proceeds from Legal Settlements	$ 100,000,000
Interest Awarded	$ 19,000,000	1,000,000
AmeriGas [Member]
Contingent Residual Support Agreement Obligation		$ 1,550,000,000			$ 1,500,000,000
Southern Union [Member]
Percentage Of Recovery		50.00%
Loss Contingency, Estimated Recovery from Third Party		150000
Related To Deductibles [Member]
Accrual for loss contingency		$ 46,000,000	$ 42,000,000
State and Local Jurisdiction [Member]
Litigation Settlement, Amount		950,000
U.S Federal [Member]
Litigation Settlement, Amount		$ 250,000

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 Millions	Dec. 31, 2013 USD ($)
Operating Leased Assets [Line Items]
2014	$ 83
2015	81
2016	72
2017	68
2018	55
Thereafter	454
Total Future Rent Payments	813
Future Rental Income	(57)
Net Future Rental Payments	$ 756

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Environmental Remediation Obligations [Abstract]
Current	$ 47	$ 46
Non-current	356	166
Total environmental liabilities	$ 403	$ 212

Price Risk Management Assets And Liabilities (Narrative) (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2012
Option Premiums		$ (7,000,000)
ETP [Member]
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI	$ 4,000,000
Regency [Member]
Loss Contingency, Range of Possible Loss, Maximum	4,000,000
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI	1,000,000
Netting [Member] \| Regency [Member]
Derivative Asset, Fair Value, Gross Liability	$ 1,000,000

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

March 2017 | Parent Company [Member]

Notional Amount

$ 0

$ 500

Type

^[1]

Pay a fixed rate of 1.25% and receive a floating rate

July 2013 [Member] | ETP [Member]

Notional Amount

^[2]

$ 0

400

Type

^[1],[2]

Forward starting to pay a fixed rate of 4.03% and receive a floating rate

July 2018 [Member] | ETP [Member]

Notional Amount

$ 600

600

Type

^[1]

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

June 2021 [Member] | ETP [Member]

Notional Amount

$ 400

Type

^[1]

Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%

February 2023 [Member] | ETP [Member]

Notional Amount

$ 400

Type

^[1]

Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%

July 2014 [Member] | ETP [Member]

Notional Amount

^[2]

$ 400

400

Type

^[1],[2]

Forward starting to pay a fixed rate of 4.25% and receive a floating rate

November 2016 [Member] | Southern Union [Member]

Notional Amount

^[3]

$ 0

Type

^[1],[3]

Pay a fixed rate of 2.97% and receive a floating rate

November 2021 [Member] | Southern Union [Member]

Notional Amount

^[3]

$ 275

$ 450

Type

^[1],[3]

Pay a fixed rate of 3.801% and receive a floating rate

[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(2) Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory terminate date the same as the effective date.
[3]	(3) In connection with the Panhandle Merger, Southern Union’s interest rate swaps outstanding were assumed by Panhandle.

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Asset Derivatives	$ 320	$ 215
Liability Derivatives	389	439
Designated as Hedging Instrument [Member]
Asset Derivatives	3	8
Liability Derivatives	(18)	(10)
Designated as Hedging Instrument [Member] \| Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	3	8
Liability Derivatives	(18)	(10)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	317	207
Liability Derivatives	(371)	(429)
Not Designated as Hedging Instrument [Member] \| Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	227	110
Liability Derivatives	(209)	(116)
Not Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Asset Derivatives	43	40
Liability Derivatives	(48)	(44)
Not Designated as Hedging Instrument [Member] \| Interest Rate Derivatives [Member]
Asset Derivatives	47	55
Liability Derivatives	(95)	(235)
Not Designated as Hedging Instrument [Member] \| Embedded Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	(19)	(25)
Current Assets Held For Sale [Member] \| Not Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Asset Derivatives	0	1
Liability Derivatives	0	0
Non-Current Assets Held For Sale [Member] \| Not Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Asset Derivatives	0	1
Liability Derivatives	0	0
Current Liabilities Held For Sale [Member] \| Not Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	0	(9)
Netting [Member]
Asset Derivatives	306	177
Liability Derivatives	356	255
Bi-lateral contracts [Member] \| Netting [Member]
Asset Derivatives	42	28
Liability Derivatives	38	27
Broker cleared derivative contracts [Member] \| Netting [Member]
Asset Derivatives	264	149
Liability Derivatives	$ 318	$ 228

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ (1)	$ 8	$ 6
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ (1)	$ 8	$ 6

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 4	$ 14	$ 19
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	8	54	34
Amount of Gain/(Loss) Recognized in Income on Derivatives	24	(12)	(81)
Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	4	14	19
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	8	54	34
Interest Rate Derivatives [Member] \| Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	53	(19)	(78)
Embedded Derivatives [Member] \| Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	6	14	18
Non Trading [Member] \| Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(21)	26	9
Non Trading [Member] \| Commodity Derivatives [Member] \| Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(3)	(26)	0
Trading [Member] \| Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (11)	$ (7)	$ (30)

Price Risk Management Assets And Liabilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Asset Derivatives	$ 320	$ 215
Derivative Liability, Fair Value, Gross Liability	(389)	(439)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(37)	(25)
Derivative Liability, Fair Value, Amount Offset Against Collateral	91	86
Netting [Member]
Asset Derivatives	306	177
Derivative Liability, Fair Value, Gross Liability	(356)	(255)
Derivative Asset, Fair Value, Gross Liability	(36)	(25)
Derivative Liability, Fair Value, Gross Asset	36	25
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	269	152
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(265)	(169)
Netting [Member] \| Bi-lateral contracts [Member]
Asset Derivatives	42	28
Derivative Liability, Fair Value, Gross Liability	(38)	(27)
Netting [Member] \| Asset Fair Value, Netting Offset [Member]
Collateral Paid To OTC Counterparties	0	0
Payments on Margin Deposits	(1)	0
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	51	63
Netting [Member] \| Liability Fair Value, Netting Offset [Member]
Collateral Paid To OTC Counterparties	0	2
Payments on Margin Deposits	55	59
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	$ (124)	$ (270)

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Retirement Benefits [Line Items]
Gain on curtailment of other postretirement benefit plans		$ 0	$ 15	$ 0
ETP [Member]
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost Recognized		47	$ 30	$ 17
Sunoco [Member]
Retirement Benefits [Line Items]
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent		200
Southern Union [Member]
Retirement Benefits [Line Items]
Pretax curtailment gain	$ 75
Noncurrent refund liability	$ 60
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months		$ 18

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	$ 0	$ 0
Change in Benefit Obligations, Dispositions	(41)	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in Plan Assets, Dispositions	(27)	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	1,195	1,257
Defined Benefit Plan, Service Cost	3	3
Defined Benefit Plan, Interest Cost	35	15
Defined Benefit Plan, Plan Amendments		0
Defined Benefit Plan, Benefits Paid		(71)
Defined Benefit Plan, Curtailments		0
Defined Benefit Plan, Actuarial Gain (Loss)		(9)
Defined Benefit Plan, Benefit Obligation		1,195
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	906	941
Defined Benefit Plan, Actual Return on Plan Assets		22
Defined Benefit Plan, Contributions by Employer		14
Defined Benefit Plan, Benefits Paid		(71)
Defined Benefit Plan, Fair Value of Plan Assets	600	906
Defined Benefit Plan, Funded Status of Plan		289
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent		0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities		(15)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent		(274)
Defined Benefit Plan, Amounts Recognized in Balance Sheet		(289)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax		1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax		0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		(1)
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	296	359
Defined Benefit Plan, Service Cost	0	1
Defined Benefit Plan, Interest Cost	6	3
Defined Benefit Plan, Plan Amendments	2	17
Defined Benefit Plan, Benefits Paid	(26)	(8)
Defined Benefit Plan, Curtailments	0	(80)
Defined Benefit Plan, Actuarial Gain (Loss)	(14)	4
Defined Benefit Plan, Benefit Obligation	223	296
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	312	306
Defined Benefit Plan, Actual Return on Plan Assets	17	5
Defined Benefit Plan, Contributions by Employer	8	9
Defined Benefit Plan, Benefits Paid	(26)	(8)
Defined Benefit Plan, Fair Value of Plan Assets	284	312
Defined Benefit Plan, Funded Status of Plan	(61)	(16)
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	86	59
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(2)	(2)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(23)	(41)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	61	16
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	25	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	18	16
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ (7)	$ 15

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation		$ 1,195
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation		1,179
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets		906
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation		225
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets		$ 185
Southern Union [Member] \| Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	$ 223
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	284
Funded Plans [Member] \| Southern Union [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	632
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	632
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	600
Unfunded Plans [Member] \| Southern Union [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	61
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	61
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$ 0

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Gain on curtailment of other postretirement benefit plans	$ 0	$ (15)	$ 0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	3	3
Defined Benefit Plan, Interest Cost	35	15
Defined Benefit Plan, Expected Return on Plan Assets	(54)	(21)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Amortization of Gains (Losses)	2	0
Defined Benefit Plan, Special Termination Benefits	0	(2)
Gain on curtailment of other postretirement benefit plans	0	0
Net Periodic Benefit Costs, Settlements	(2)	0
Net periodic benefit cost subtotal	(16)	(1)
Net Period Benefit Cost Regulatory Adjustment	5	9
Defined Benefit Plan, Net Periodic Benefit Cost	(11)	8
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0	1
Defined Benefit Plan, Interest Cost	6	3
Defined Benefit Plan, Expected Return on Plan Assets	(9)	(5)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	0
Defined Benefit Plan, Amortization of Gains (Losses)	0	0
Defined Benefit Plan, Special Termination Benefits	0	0
Gain on curtailment of other postretirement benefit plans	0	(15)
Net Periodic Benefit Costs, Settlements	0	0
Net periodic benefit cost subtotal	(2)	(16)
Net Period Benefit Cost Regulatory Adjustment	0	2
Defined Benefit Plan, Net Periodic Benefit Cost	$ (2)	$ (14)

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
Retirement Benefits (Benefit Assumptions) (Details)	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.57%	7.78%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.42%	5.32%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2018	2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.65%	3.41%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.17%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.50%	2.37%
Expected long term return on assets, tax exempt accounts	7.50%	7.63%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.02%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.33%	2.39%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.68%	2.43%
Expected long term return on assets, tax exempt accounts	6.95%	7.00%
Expected long term return on assets, taxable accounts	4.42%	4.50%

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2013 USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 31
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	29
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	28
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	26
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	24
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	87
Funded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	82
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	77
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	67
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	61
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	56
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	220
Unfunded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	9
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	9
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	8
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	7
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	7
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 23

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue	$ 1,442	$ 189	$ 1,049

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	$ 12,607	$ 12,486	$ 12,063	$ 11,179	$ 11,313	$ 2,107	$ 1,875	$ 1,669	$ 48,335	$ 16,964	$ 8,190
Cost of products sold									42,554	13,088	5,169
Depreciation and amortization									1,313	871	586
Equity in earnings of unconsolidated affiliates									236	212	117
Investment In ETP [Member]
Revenues									46,339	15,702	6,799
Cost of products sold									41,204	12,266	4,175
Depreciation and amortization									1,032	656	405
Equity in earnings of unconsolidated affiliates									172	142	26
Investment In Regency [Member]
Revenues									2,521	2,000	1,434
Cost of products sold									1,793	1,387	1,013
Depreciation and amortization									287	252	169
Equity in earnings of unconsolidated affiliates									135	105	120
Investment in Trunkline LNG [Member]
Revenues									216	166	0
Cost of products sold									0	0	0
Depreciation and amortization									39	30	0
Corporate and Other [Member]
Depreciation and amortization									16	14	12
Adjustments and Eliminations [Member]
Revenues									(741)	(904)	(43)
Cost of products sold									(443)	(565)	(19)
Depreciation and amortization									(61)	(81)	0
Equity in earnings of unconsolidated affiliates									(71)	(35)	(29)
External Customers [Member] \| Investment In ETP [Member]
Revenues									46,210	15,671	6,761
External Customers [Member] \| Investment In Regency [Member]
Revenues									2,404	1,986	1,426
External Customers [Member] \| Investment in Trunkline LNG [Member]
Revenues									216	166	0
Intersegment [Member] \| Investment In ETP [Member]
Revenues									129	31	38
Intersegment [Member] \| Investment In Regency [Member]
Revenues									117	14	8
Intersegment [Member] \| Investment in Trunkline LNG [Member]
Revenues									$ 0	$ 0	$ 0

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	$ 236	$ 212	$ 117
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	172	142	26
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	135	105	120
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	$ (71)	$ (35)	$ (29)

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 4,367	$ 3,105	$ 2,131
Depreciation and amortization	(1,313)	(871)	(586)
Interest expense, net of interest capitalized	(1,221)	(1,018)	(740)
Bridge loan related fees	0	(62)	0
Gain on deconsolidation of Propane Business	0	1,057	0
Gain on sale of AmeriGas common units	87	0	0
Goodwill impairment	(689)	0	0
Gains (losses) on interest rate derivatives	53	(19)	(78)
Non-cash compensation expense	(61)	(47)	(42)
Gains (losses) on interest rate derivatives	48	10	7
Gain (Loss) on Disposition of Assets	(2)	(4)	(1)
Losses on extinguishments of debt	(162)	(123)	0
Inventory, LIFO Reserve, Effect on Income, Net	3	(75)	0
Adjusted EBITDA related to discontinued operations	(76)	(99)	(23)
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(727)	(647)	(231)
Equity in earnings of unconsolidated affiliates	236	212	117
Non-operating environmental remediation	(168)	0	0
Other, net	(2)	14	(7)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	375	1,437	548
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,953	2,744	1,781
Depreciation and amortization	(1,032)	(656)	(405)
Equity in earnings of unconsolidated affiliates	172	142	26
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	608	517	420
Depreciation and amortization	(287)	(252)	(169)
Equity in earnings of unconsolidated affiliates	135	105	120
Investment in Trunkline LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	187	135	0
Depreciation and amortization	(39)	(30)	0
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(43)	(52)	(29)
Depreciation and amortization	(16)	(14)	(12)
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(338)	(239)	(41)
Depreciation and amortization	61	81	0
Equity in earnings of unconsolidated affiliates	$ (71)	$ (35)	$ (29)

Reportable Segments (Assets Segments)(Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets	$ 50,330	$ 48,904	$ 20,897
Investment In ETP [Member]
Assets	43,702	43,230	15,519
Investment In Regency [Member]
Assets	8,782	8,123	5,568
Investment in Trunkline LNG [Member]
Assets	1,338	1,917	0
Corporate and Other [Member]
Assets	720	707	470
Adjustments and Eliminations [Member]
Assets	$ (4,212)	$ (5,073)	$ (660)

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 3,489	$ 3,485	$ 1,890
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	2,455	3,049	1,484
Investment in Regency [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	1,034	560	406
Investment in Trunkline LNG [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	2	4	0
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ (2)	$ (128)	$ 0

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	$ 4,014	$ 4,737	$ 1,497
Investment In ETP [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,436	3,502	201
Investment In Regency [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	2,097	2,214	1,925
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	$ (2,519)	$ (979)	$ (629)

Reportable Segments ETP Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue from External Customer [Line Items]
Revenues	$ 12,607	$ 12,486	$ 12,063	$ 11,179	$ 11,313	$ 2,107	$ 1,875	$ 1,669	$ 48,335	$ 16,964	$ 8,190
Investment In ETP [Member]
Revenue from External Customer [Line Items]
Revenues									46,339	15,702	6,799
Investment In ETP [Member] \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									46,210	15,671	6,761
Investment In ETP [Member] \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									129	31	38
Investment In ETP [Member] \| Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									2,250	2,012	2,398
Investment In ETP [Member] \| Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,270	1,109	447
Investment In ETP [Member] \| Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									1,307	1,757	1,082
Investment In ETP [Member] \| NGL Transportation And Services [Member]
Revenue from External Customer [Line Items]
Revenues									2,063	619	363
Investment In ETP [Member] \| Investment in Sunoco Logistics [Member]
Revenue from External Customer [Line Items]
Revenues									16,480	3,109	0
Investment In ETP [Member] \| Retail Marketing [Member]
Revenue from External Customer [Line Items]
Revenues									21,004	5,926	0
Investment In ETP [Member] \| Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									$ 1,965	$ 1,170	$ 2,509

Reportable Segments Regency Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue from External Customer [Line Items]
Revenues	$ 12,607	$ 12,486	$ 12,063	$ 11,179	$ 11,313	$ 2,107	$ 1,875	$ 1,669	$ 48,335	$ 16,964	$ 8,190
Investment In Regency [Member]
Revenue from External Customer [Line Items]
Revenues									2,521	2,000	1,434
Investment In Regency [Member] \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									2,404	1,986	1,426
Investment In Regency [Member] \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									117	14	8
Investment In Regency [Member] \| Gathering And Processing [Member]
Revenue from External Customer [Line Items]
Revenues									2,287	1,797	1,226
Investment In Regency [Member] \| Natural Gas Transportation [Member]
Revenue from External Customer [Line Items]
Revenues									1	1	1
Investment In Regency [Member] \| Contract Services [Member]
Revenue from External Customer [Line Items]
Revenues									215	183	190
Investment In Regency [Member] \| Corporate and Other [Member]
Revenue from External Customer [Line Items]
Revenues									$ 18	$ 19	$ 17

Reportable Segments Trunkline Revenue (Details) - USD ($) $ in Millions	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 12,607	$ 12,486	$ 12,063	$ 11,179	$ 11,313	$ 2,107	$ 1,875	$ 1,669		$ 48,335	$ 16,964	$ 8,190
Investment in Trunkline LNG [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues										216	$ 166	$ 0
Investment in Trunkline LNG [Member] \| LNG Terminalling [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues									$ 166	$ 216

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	$ 12,607	$ 12,486	$ 12,063	$ 11,179	$ 11,313	$ 2,107	$ 1,875	$ 1,669	$ 48,335	$ 16,964	$ 8,190
Gross margin	1,489	1,422	1,498	1,372	1,430	876	916	654	5,781	3,876
Operating income (loss)	(153)	529	644	531	452	358	367	183	1,551	1,360	1,237
Net income (loss)	(701)	356	338	322	272	(34)	75	961	315	1,274	528
Limited Partners’ interest in net income (loss)	$ (171)	$ 150	$ 127	$ 90	$ 48	$ 35	$ 53	$ 166	$ 196	$ 302	$ 309
Basic net income (loss) per limited partner unit	$ (0.31)	$ 0.27	$ 0.23	$ 0.16	$ 0.09	$ 0.06	$ 0.10	$ 0.37	$ 0.35	$ 0.57	$ 0.69
Diluted net income (loss) per limited partner unit	$ (0.31)	$ 0.27	$ 0.23	$ 0.16	$ 0.09	$ 0.06	$ 0.10	$ 0.36	$ 0.35	$ 0.57	$ 0.69

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash and cash equivalents	$ 590	$ 372	$ 126	$ 86
Accounts receivable from related companies	63	71
Other current assets	312	311
Total current assets	6,536	5,597
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,014	4,737	1,497
INTANGIBLE ASSETS, net	2,264	2,291
GOODWILL	5,894	6,434	2,039
OTHER NON-CURRENT ASSETS, net	922	533
Total assets	50,330	48,904	20,897
Accounts payable	3,834	3,107
Accounts payable to related companies	14	15
Interest payable	357	334
Price risk management liabilities	53	115
Accrued and other current liabilities	1,678	1,754
Current maturities of long-term debt	637	613
Total current liabilities	6,500	5,845
LONG-TERM DEBT, less current maturities	22,562	21,440
OTHER NON-CURRENT LIABILITIES	1,019	995
COMMITMENTS AND CONTINGENCIES
General Partner	(3)	0
Limited Partners – Common Unitholders (559,923,300 and 559,911,216 units authorized, issued and outstanding at December 31, 2013 and 2012, respectively)	1,066	2,125
Accumulated other comprehensive income (loss)	9	(12)
Total partners’ capital	1,078	2,113
Total liabilities and equity	50,330	48,904
Parent Company [Member]
Cash and cash equivalents	8	9	$ 18	$ 27
Accounts receivable from related companies	5	11
Other current assets	0	3
Total current assets	13	23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,841	6,094
INTANGIBLE ASSETS, net	14	19
NOTE RECEIVABLE FROM AFFILIATE	0	166
GOODWILL	9	9
OTHER NON-CURRENT ASSETS, net	41	56
Total assets	3,918	6,367
Accounts payable	0	1
Accounts payable to related companies	11	15
Interest payable	24	48
Price risk management liabilities	0	5
Accrued and other current liabilities	3	1
Current maturities of long-term debt	0	4
Total current liabilities	38	74
LONG-TERM DEBT, less current maturities	2,801	3,840
PREFERRED UNITS	0	331
OTHER NON-CURRENT LIABILITIES	1	9
COMMITMENTS AND CONTINGENCIES
General Partner	(3)	0
Limited Partners – Common Unitholders (559,923,300 and 559,911,216 units authorized, issued and outstanding at December 31, 2013 and 2012, respectively)	1,066	2,125
Class D Units (1,540,000 units authorized, issued and outstanding at December 31, 2013)	6	0
Accumulated other comprehensive income (loss)	9	(12)
Total partners’ capital	1,078	2,113
Total liabilities and equity	$ 3,918	$ 6,367

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									$ (586)	$ (529)	$ (253)
InterestExpense									1,221	1,018	740
Bridge loan related fees											0
Equity in earnings of unconsolidated affiliates									236	212	117
Gains (losses) on interest rate derivatives									53	(19)	(78)
Losses on extinguishments of debt									(162)	(123)	0
Other, net									(1)	30	17
Income tax benefit									93	54	17
NET INCOME ATTRIBUTABLE TO PARTNERS									196	304	310
GENERAL PARTNER’S INTEREST IN NET INCOME									0	2	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ (171)	$ 150	$ 127	$ 90	$ 48	$ 35	$ 53	$ 166	196	302	309
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									(56)	(53)	(30)
InterestExpense									210	235	164
Bridge loan related fees									0	(62)
Equity in earnings of unconsolidated affiliates									617	666	509
Gains (losses) on interest rate derivatives									9	(15)	0
Losses on extinguishments of debt									(157)	0	0
Other, net									(8)	(4)	(5)
INCOME BEFORE INCOME TAXES									195	297	310
Income tax benefit									(1)	(7)	0
NET INCOME ATTRIBUTABLE TO PARTNERS									196	304	310
GENERAL PARTNER’S INTEREST IN NET INCOME									0	(2)	(1)
LIMITED PARTNERS’ INTEREST IN NET INCOME									$ 196	$ 302	$ 309

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$ 2,419	$ 1,078	$ 1,378
Cash paid for acquisitions		(405)	(10)	(1,972)
Proceeds from the sale of other assets		89	251	33
Net cash used in investing activities		(2,347)	(4,196)	(3,874)
Proceeds from borrowings		12,934	12,870	8,262
Repayments of long-term debt	$ (455)	(11,951)	(8,848)	(6,264)
Distributions to partners		(733)	(666)	(526)
Redemption of Preferred Units		(340)	0	0
Debt issuance costs		(87)	(112)	(53)
Net cash provided by financing activities		146	3,364	2,536
INCREASE IN CASH AND CASH EQUIVALENTS		218	246	40
CASH AND CASH EQUIVALENTS, beginning of period		372	126	86
CASH AND CASH EQUIVALENTS, end of period		590	372	126
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		768	555	469
Cash paid for acquisitions		0	(1,113)	0
Proceeds from the sale of other assets		1,332	0	0
Contributions to affiliates		(8)	(487)	0
Note receivable from affiliate		0	(221)	0
Payments received on note receivable from affiliate		166	55	0
Net cash used in investing activities		1,490	(1,766)	0
Proceeds from borrowings		2,080	2,108	92
Repayments of long-term debt		(3,235)	(162)	(20)
Distributions to partners		(733)	(666)	(526)
Redemption of Preferred Units		(340)	0	0
Debt issuance costs		(31)	(78)	(24)
Net cash provided by financing activities		(2,259)	1,202	(478)
INCREASE IN CASH AND CASH EQUIVALENTS		(1)	(9)	(9)
CASH AND CASH EQUIVALENTS, beginning of period		9	18	27
CASH AND CASH EQUIVALENTS, end of period		$ 8	$ 9	$ 18

Label	Element	Value
Funded Plans [Member]
Change in Plan Assets, Dispositions	ete_ChangeinPlanAssetsDispositions	$ (155,000,000)
Change in Benefit Obligations, Dispositions	ete_ChangeinBenefitObligationsDispositions	(253,000,000)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	us-gaap_DefinedBenefitPlanRecognizedNetGainLossDueToSettlements1	(95,000,000)
Unfunded Plans [Member]
Change in Benefit Obligations, Dispositions	ete_ChangeinBenefitObligationsDispositions	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	us-gaap_DefinedBenefitPlanRecognizedNetGainLossDueToSettlements1	0
Unfunded Plans [Member] \| Change in Plan Assets [Member]
Change in Plan Assets, Dispositions	ete_ChangeinPlanAssetsDispositions	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	us-gaap_DefinedBenefitPlanRecognizedNetGainLossDueToSettlements1	0
SUGS [Member]
Goodwill	us-gaap_Goodwill	$ 337,000,000
Pension Plan, Defined Benefit [Member]
Fixed Income Securities	ete_FixedIncomeSecurities	54.00%
Fixed Income Securities	ete_FixedIncomeSecurities	10.00%
Other Investments - Plan Asset Allocation	ete_OtherInvestmentsPlanAssetAllocation	10.00%
Other Investments - Plan Asset Allocation	ete_OtherInvestmentsPlanAssetAllocation	24.00%
Large Cap US Equitiies	ete_LargeCapUsEquitiies	66.00%
Large Cap US Equitiies	ete_LargeCapUsEquitiies	36.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	us-gaap_DefinedBenefitPlanExpectedFutureBenefitPaymentsNextTwelveMonths	$ 23,000,000
Pension Plan, Defined Benefit [Member] \| Funded Plans [Member]
Defined Benefit Plan, Funded Status of Plan	us-gaap_DefinedBenefitPlanFundedStatusOfPlan	(32,000,000)
Defined Benefit Plan, Interest Cost	us-gaap_DefinedBenefitPlanInterestCost	33,000,000
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	us-gaap_PensionAndOtherPostretirementDefinedBenefitPlansLiabilitiesNoncurrent	32,000,000
Defined Benefit Plan, Plan Amendments	us-gaap_DefinedBenefitPlanPlanAmendments	0
Defined Benefit Plan, Actual Return on Plan Assets	us-gaap_DefinedBenefitPlanActualReturnOnPlanAssets	43,000,000
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	us-gaap_PensionAndOtherPostretirementDefinedBenefitPlansCurrentLiabilities	0
Defined Benefit Plan, Benefits Paid	us-gaap_DefinedBenefitPlanBenefitsPaid	99,000,000
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	1,117,000,000
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	632,000,000
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	us-gaap_DefinedBenefitPlanAssetsForPlanBenefitsNoncurrent	0
Defined Benefit Plan, Amounts Recognized in Balance Sheet	us-gaap_DefinedBenefitPlanAmountsRecognizedInBalanceSheet	(32,000,000)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	us-gaap_OtherComprehensiveIncomeLossPensionAndOtherPostretirementBenefitPlansAdjustmentNetOfTax	(86,000,000)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	us-gaap_DefinedBenefitPlanAmountsRecognizedInOtherComprehensiveIncomeLossNetGainLossBeforeTax	86,000,000
Defined Benefit Plan, Actuarial Gain (Loss)	us-gaap_DefinedBenefitPlanActuarialGainLoss	(74,000,000)
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	906,000,000
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	600,000,000
Defined Benefit Plan, Contributions by Employer	us-gaap_DefinedBenefitPlanContributionsByEmployer	0
Defined Benefit Plan, Service Cost	us-gaap_DefinedBenefitPlanServiceCost	3,000,000
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	us-gaap_OtherComprehensiveIncomeDefinedBenefitPlanNetPriorServiceCostCreditArisingDuringPeriodBeforeTax	0
Defined Benefit Plan, Curtailments	us-gaap_DefinedBenefitPlanCurtailments	0
Pension Plan, Defined Benefit [Member] \| Unfunded Plans [Member]
Defined Benefit Plan, Funded Status of Plan	us-gaap_DefinedBenefitPlanFundedStatusOfPlan	(61,000,000)
Defined Benefit Plan, Interest Cost	us-gaap_DefinedBenefitPlanInterestCost	2,000,000
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	us-gaap_PensionAndOtherPostretirementDefinedBenefitPlansLiabilitiesNoncurrent	52,000,000
Defined Benefit Plan, Plan Amendments	us-gaap_DefinedBenefitPlanPlanAmendments	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	us-gaap_PensionAndOtherPostretirementDefinedBenefitPlansCurrentLiabilities	9,000,000
Defined Benefit Plan, Benefits Paid	us-gaap_DefinedBenefitPlanBenefitsPaid	16,000,000
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	61,000,000
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	78,000,000
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	us-gaap_DefinedBenefitPlanAssetsForPlanBenefitsNoncurrent	0
Defined Benefit Plan, Amounts Recognized in Balance Sheet	us-gaap_DefinedBenefitPlanAmountsRecognizedInBalanceSheet	(61,000,000)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	us-gaap_OtherComprehensiveIncomeLossPensionAndOtherPostretirementBenefitPlansAdjustmentNetOfTax	(4,000,000)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	us-gaap_DefinedBenefitPlanAmountsRecognizedInOtherComprehensiveIncomeLossNetGainLossBeforeTax	4,000,000
Defined Benefit Plan, Actuarial Gain (Loss)	us-gaap_DefinedBenefitPlanActuarialGainLoss	(3,000,000)
Defined Benefit Plan, Service Cost	us-gaap_DefinedBenefitPlanServiceCost	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	us-gaap_OtherComprehensiveIncomeDefinedBenefitPlanNetPriorServiceCostCreditArisingDuringPeriodBeforeTax	0
Defined Benefit Plan, Curtailments	us-gaap_DefinedBenefitPlanCurtailments	0
Pension Plan, Defined Benefit [Member] \| Unfunded Plans [Member] \| Change in Plan Assets [Member]
Defined Benefit Plan, Actual Return on Plan Assets	us-gaap_DefinedBenefitPlanActualReturnOnPlanAssets	0
Defined Benefit Plan, Benefits Paid	us-gaap_DefinedBenefitPlanBenefitsPaid	0
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	0
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	0
Defined Benefit Plan, Contributions by Employer	us-gaap_DefinedBenefitPlanContributionsByEmployer	$ 0
Other Postretirement Benefit Plan, Defined Benefit [Member]
Fixed Income Securities	ete_FixedIncomeSecurities	74.00%
Fixed Income Securities	ete_FixedIncomeSecurities	48.00%
Cash Fund Investments	ete_CashFundInvestments	6.00%
Cash Fund Investments	ete_CashFundInvestments	4.00%
Other Investments - Plan Asset Allocation	ete_OtherInvestmentsPlanAssetAllocation	5.00%
Other Investments - Plan Asset Allocation	ete_OtherInvestmentsPlanAssetAllocation	3.00%
Large Cap US Equitiies	ete_LargeCapUsEquitiies	19.00%
Large Cap US Equitiies	ete_LargeCapUsEquitiies	41.00%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Southern Union [Member]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	us-gaap_DefinedBenefitPlanRecognizedNetGainLossDueToCurtailments	$ 15,000,000
Cash [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	ete_DefinedBenefitPlanTargetAllocationPercentageCashMinimum	0.00%
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	ete_DefinedBenefitPlanTargetAllocationPercentageCashMaximum	10.00%
Cash [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	ete_DefinedBenefitPlanTargetAllocationPercentageCashMinimum	0.00%
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	ete_DefinedBenefitPlanTargetAllocationPercentageCashMaximum	10.00%
Private Equity Funds [Member] \| Pension Plan, Defined Benefit [Member] \| Sunoco [Member]
Defined Benefit Plan, Target Plan Asset Allocations	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocations	10.00%
Equity [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	70.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	25.00%
Equity [Member] \| Pension Plan, Defined Benefit [Member] \| Sunoco [Member]
Defined Benefit Plan, Target Plan Asset Allocations	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocations	35.00%
Equity [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	35.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	25.00%
Fixed Income Investments [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	35.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	15.00%
Fixed Income Investments [Member] \| Pension Plan, Defined Benefit [Member] \| Sunoco [Member]
Defined Benefit Plan, Target Plan Asset Allocations	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocations	55.00%
Fixed Income Investments [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	75.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	65.00%
Alternative Assets [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	35.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	10.00%

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 284	$ 312	$ 306
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	600	906	$ 941
Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	10	7
Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	25
Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	130	147
Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	368	516
Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	144	158
Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	220	354
Hedge Funds, Multi-strategy [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		11
Level 1 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	122	133
Level 1 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	25
Level 1 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	10	7
Level 1 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	25
Level 1 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	112	126
Level 1 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] \| Hedge Funds, Multi-strategy [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Level 2 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	162	179
Level 2 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	501	798
Level 2 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	18	21
Level 2 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	281	433
Level 2 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	144	158
Level 2 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	220	354
Level 2 [Member] \| Hedge Funds, Multi-strategy [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		11
Level 3 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	87	83
Level 3 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	87	83
Level 3 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	0
Level 3 [Member] \| Hedge Funds, Multi-strategy [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0