Energy Transfer 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 21, 2014	Jun. 30, 2013
Document Information [Line Items]	'	'	'
Entity Current Reporting Status	'Yes	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Entity Registrant Name	'Energy Transfer Partners, L.P.	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Central Index Key	'0001012569	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	316,923,087	'
Entity Public Float	'	'	$13.80
Entity Common Stock, Shares Outstanding	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$549	$311
Accounts receivable, net	3,359	2,910
Accounts receivable from related companies	165	94
Inventories	1,765	1,495
Exchanges receivable	56	55
Price risk management assets	35	21
Current assets held for sale	0	184
Other current assets	310	334
Total current assets	6,239	5,404
PROPERTY, PLANT AND EQUIPMENT	28,430	27,412
ACCUMULATED DEPRECIATION	-2,483	-1,639
PROPERTY, PLANT AND EQUIPMENT, net	25,947	25,773
NON-CURRENT ASSETS HELD FOR SALE	0	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,436	3,502
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	17	42
GOODWILL	4,729	5,606
INTANGIBLE ASSETS, net	1,568	1,561
OTHER NON-CURRENT ASSETS, net	766	357
Total assets	43,702	43,230
CURRENT LIABILITIES:	'	'
Accounts payable	3,627	3,002
Accounts payable to related companies	45	24
Exchanges payable	285	156
Price risk management liabilities	45	110
Accrued and other current liabilities	1,428	1,562
Current maturities of long-term debt	637	609
Current liabilities held for sale	0	85
Total current liabilities	6,067	5,548
NON-CURRENT LIABILITIES HELD FOR SALE	0	142
LONG-TERM DEBT, less current maturities	16,451	15,442
LONG-TERM NOTES PAYABLE — RELATED PARTY	0	166
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	54	129
DEFERRED INCOME TAXES	3,762	3,476
OTHER NON-CURRENT LIABILITIES	1,080	995
EQUITY:	'	'
General Partner	171	188
Limited Partners:	'	'
Common Unitholders (333,826,372 and 301,485,604 units authorized, issued and outstanding as of December 31, 2013 and 2012, respectively)	9,797	9,026
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary)	0	0
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary)	0	0
Class H Unitholders (50.6 units authorized, issued and outstanding – held by ETE)	1,511	0
Accumulated other comprehensive income (loss)	61	-13
Total partners’ capital	11,540	9,201
Noncontrolling interest	4,748	8,131
Total equity	16,288	17,332
Total liabilities and equity	$43,702	$43,230

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Common Units [Member]	'	'
Units - Authorized	333,826,372	301,485,604
Units - issued	333,826,372	301,485,604
Units - Outstanding	333,826,372	301,485,604
Class E Units [Member]	'	'
Units - Authorized	8,853,832	8,853,832
Units - issued	8,853,832	8,853,832
Units - Outstanding	8,853,832	8,853,832
Class G Units [Member]	'	'
Units - Authorized	90,706,000	'
Units - issued	90,706,000	'
Units - Outstanding	90,706,000	'
Class F Units [Member]	'	'
Units - Authorized	'	90,706,000
Units - issued	'	90,706,000
Units - Outstanding	'	90,706,000
Class F Units [Member]	'	'
Units - Authorized	50,160,000	0
Units - issued	50,160,000	0
Units - Outstanding	50,160,000	0

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:	'	'	'
Natural gas sales	$3,165	$2,387	$2,534
NGL sales	2,817	1,718	1,113
Crude sales	15,477	2,872	0
Gathering, transportation and other fees	2,590	2,007	1,488
Refined product sales	18,479	5,299	0
Other	3,811	1,419	1,664
Total revenues	46,339	15,702	6,799
COSTS AND EXPENSES:	'	'	'
Cost of products sold	41,204	12,266	4,175
Operating expenses	1,388	951	799
Depreciation and amortization	1,032	656	405
Selling, general and administrative	485	435	173
Goodwill impairment	689	0	0
Total costs and expenses	44,798	14,308	5,552
OPERATING INCOME	1,541	1,394	1,247
OTHER INCOME (EXPENSE):	'	'	'
Interest expense, net of interest capitalized	-849	-665	-474
Equity in earnings of unconsolidated affiliates	172	142	26
Gain on deconsolidation of Propane Business	0	1,057	0
Gain on sale of AmeriGas common units	87	0	0
Loss on extinguishment of debt	0	-115	0
Gains (losses) on interest rate derivatives	44	-4	-77
Non-operating environmental remediation	-168	0	0
Other, net	5	11	-3
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	832	1,820	719
Income tax expense from continuing operations	97	63	19
INCOME FROM CONTINUING OPERATIONS	735	1,757	700
Income (loss) from discontinued operations	33	-109	-3
NET INCOME	768	1,648	697
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	312	'	'
NET INCOME ATTRIBUTABLE TO PARTNERS	456	1,569	669
GENERAL PARTNER’S INTEREST IN NET INCOME	506	461	433
CLASS H UNITHOLDER’S INTEREST IN NET INCOME	'	0	0
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)	($98)	$1,108	$236
INCOME (LOSS) FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:	'	'	'
Basic income (loss) from continuing operations per Limited Partner unit	($0.23)	$4.93	$1.12
Diluted income (loss) from continuing operations per Limited Partner unit	($0.23)	$4.91	$1.12
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:	'	'	'
Basic	($0.18)	$4.43	$1.10
Diluted	($0.18)	$4.42	$1.10

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
NET INCOME	$768	$1,648	$697
Other comprehensive income (loss), net of tax:	'	'	'
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	-4	-14	-38
Change in value of derivative instruments accounted for as cash flow hedges	-1	8	19
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
Total other comprehensive income	79	-25	-20
Comprehensive income	847	1,623	677
Less: Comprehensive income attributable to noncontrolling interest	312	74	28
Comprehensive income attributable to partners	$535	$1,549	$649

CONSOLIDATED_STATEMENT_OF_EQUI

CONSOLIDATED STATEMENT OF EQUITY (USD $)

Total

General Partner [Member]

Limited Partner Common Unitholders [Member]

Class H [Member]

Accumulated Other Comprehensive Income (Loss)[Member]

Noncontrolling Interest [Member]

Other Acquisitions [Member]

Other Acquisitions [Member]

Other Acquisitions [Member]

Other Acquisitions [Member]

Other Acquisitions [Member]

Other Acquisitions [Member]

Class H [Member]

Class H [Member]

Class H [Member]

Class H [Member]

Class H [Member]

Class H [Member]

In Millions, unless otherwise specified

General Partner [Member]

Limited Partner Common Unitholders [Member]

Class H [Member]

Accumulated Other Comprehensive Income (Loss)[Member]

Noncontrolling Interest [Member]

General Partner [Member]

Limited Partner Common Unitholders [Member]

Accumulated Other Comprehensive Income (Loss)[Member]

Noncontrolling Interest [Member]

Balance at Dec. 31, 2010

$4,743

$175

$4,542

$0

$26

$0

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to partners

-1,159

-426

-733

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

-44

0

0

0

0

-44

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

1,467

0

1,467

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Noncontrolling Interests

645

0

0

0

0

645

'

'

'

'

'

'

'

'

'

'

'

'

Sunoco Merger (see Note 3)

3

0

3

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Other comprehensive loss, net of tax

-20

0

0

0

-20

0

'

'

'

'

'

'

'

'

'

'

'

'

Other, net

18

0

18

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to General Partners

-433

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to Limited Partners

236

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

697

'

236

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

CLASS H UNITHOLDER’S INTEREST IN NET INCOME

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST

'

'

'

'

'

28

'

'

'

'

'

'

'

'

'

'

'

'

Balance at Dec. 31, 2011

6,350

182

5,533

0

6

629

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to partners

-1,343

-454

-889

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

-233

0

0

0

0

-233

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

791

0

791

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Noncontrolling Interests

343

0

0

0

0

343

'

'

'

'

'

'

'

'

'

'

'

'

Holdco Acquisition and SUGS Contribution (see Note 3)

5,868

0

2,288

0

0

3,580

'

'

'

'

'

'

'

'

'

'

'

'

Holdco Transaction

3,913

0

165

0

0

3,748

'

'

'

'

'

'

'

'

'

'

'

'

Sunoco Merger (see Note 3)

2,295

'

'

'

'

'

7

0

-7

0

0

0

'

'

'

'

'

'

Other comprehensive loss, net of tax

-25

0

0

0

-19

-6

'

'

'

'

'

'

'

'

'

'

'

'

Other, net

13

1

-23

0

0

9

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to General Partners

-461

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to Limited Partners

1,108

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

1,648

'

1,108

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

CLASS H UNITHOLDER’S INTEREST IN NET INCOME

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST

'

'

'

'

'

79

'

'

'

'

'

'

'

'

'

'

'

'

Balance at Dec. 31, 2012

17,332

188

9,026

0

-13

8,131

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to partners

-1,802

523

1,228

-51

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

-382

0

0

0

0

382

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to noncontrolling interest

1,611

0

1,611

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Noncontrolling Interests

137

0

0

0

0

137

'

'

'

'

'

'

'

'

'

'

'

'

Holdco Acquisition and SUGS Contribution

-1,440

0

2,013

0

-5

-3,448

'

'

'

'

'

'

'

'

'

'

'

'

Sunoco Merger (see Note 3)

0

'

'

'

'

'

'

'

'

'

'

'

0

0

-1,514

1,514

0

0

Other comprehensive loss, net of tax

79

0

0

0

79

0

'

'

'

'

'

'

'

'

'

'

'

'

Other, net

-15

0

13

0

0

2

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to General Partners

-506

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Allocated to Limited Partners

-98

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

768

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

CLASS H UNITHOLDER’S INTEREST IN NET INCOME

'

'

'

48

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST

312

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at Dec. 31, 2013

$16,288

$171

$9,797

$1,511

$61

$4,748

'

'

'

'

'

'

'

'

'

'

'

'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
NET INCOME	$768	$1,648	$697
Reconciliation of net income to net cash provided by operating activities:	'	'	'
Depreciation and amortization	1,032	656	405
Deferred income taxes	48	62	4
Gain on curtailment of other postretirement benefits	0	-15	0
Amortization included in interest expense	-80	-35	10
Loss on extinguishment of debt	0	115	0
LIFO valuation adjustments	-3	75	0
Non-cash compensation expense	47	42	38
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
Write-down of assets included in loss from discontinued operations	0	132	0
Distributions on unvested awards	-12	-8	-8
Equity in earnings of unconsolidated affiliates	-172	-142	-26
Distributions from unconsolidated affiliates	247	132	29
Other non-cash	42	68	29
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2)	-146	-475	166
Net cash provided by operating activities	2,373	1,198	1,344
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Cash proceeds from SUGS Contribution (See Note 3)	504	0	0
Cash paid for Holdco Acquisition (See Note 3)	-1,332	0	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
Cash (paid) received from all other acquisitions	-405	531	-1,972
Capital expenditures (excluding allowance for equity funds used during construction)	-2,575	-2,840	-1,416
Cash (paid) received from all other acquisitions	52	35	25
Contributions to unconsolidated affiliates	-1	-30	-222
Distributions from unconsolidated affiliates in excess of cumulative earnings	217	130	22
Proceeds from sale of disposal group	0	207	0
Proceeds from the sale of assets	53	18	9
Restricted cash	-348	5	0
Other	21	111	1
Net cash used in investing activities	-2,460	-2,285	-3,553
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from borrowings	8,001	8,208	6,594
Repayments of long-term debt	-7,016	-6,598	-5,217
Proceeds from borrowings from affiliates	0	221	0
Repayments of borrowings from affiliates	-166	-55	0
Net proceeds from issuance of Limited Partner units	1,611	791	1,467
Capital contributions received from noncontrolling interest	147	320	645
Distributions to partners	-1,802	-1,343	-1,159
Distributions to noncontrolling interest	-382	-233	-44
Debt issuance costs	-32	-20	-20
Other	-36	0	0
Net cash provided by financing activities	325	1,291	2,266
INCREASE IN CASH AND CASH EQUIVALENTS	238	204	57
CASH AND CASH EQUIVALENTS, beginning of period	311	107	50
CASH AND CASH EQUIVALENTS, end of period	549	311	107
Citrus [Member]	'	'	'
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Cash paid for Citrus Merger	0	-1,895	0
Cash proceeds from contribution and sale of propane operations	$0	$1,443	$0

Operations_and_Organization_No

Operations and Organization (Notes)	12 Months Ended
	Dec. 31, 2013
Operations And Organization [Abstract]	'
OPERATIONS AND ORGANIZATION	'
	OPERATIONS AND ORGANIZATION:
	The consolidated financial statements and notes thereto of Energy Transfer Partners, L.P., and its subsidiaries (the “Partnership,” “we” or “ETP”) 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 subsidiaries we control, even if we do not have a majority ownership. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.
	We 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 assets.
	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, we 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 restated to present Canyon’s operations as discontinued operations.  Canyon was previously included in our midstream segment. 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.
	In accordance with GAAP, we have accounted for the Holdco Transaction (described in Note 3), whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted interim periods in 2012, and no prior annual amounts have been adjusted.
	We are managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
	Business Operations
	Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
	•	ETC OLP, a Texas limited partnership 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 our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star 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, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets.
	•	Holdco, a Delaware limited liability company that indirectly owns 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, storage and distribution 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.
	Our financial statements reflect the following reportable business segments:
	•	intrastate transportation and storage;
	•	interstate transportation and storage;
	•	midstream;
	•	NGL transportation and services;
	•	investment in Sunoco Logistics;
	•	retail marketing; and
	•	all other.

Estimates_Significant_Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes)	12 Months Ended
	Dec. 31, 2013
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'
Estimates Significant Accounting Policies And Balance Sheet Detail Text Block	'
	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 the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
	Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
	Revenue Recognition
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
	In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
	Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
	We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	In our 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.
	We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	Our retail marketing segment sells 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.
	Regulatory Accounting – Regulatory Assets and Liabilities
	Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment 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 our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Southern Union recorded regulatory assets with respect to its distribution segment operations. At December 31, 2012, we had $123 million of regulatory assets included in the 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 Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
	Cash, Cash Equivalents and Supplemental Cash Flow Information
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that 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 acquisitions) included in cash flows from operating activities is comprised as follows:
		Years Ended December 31,
		2013			2012			2011
	Accounts receivable	$	(458	)	$	300		$	3
	Accounts receivable from related companies	(17		)	(50		)	(28		)
	Inventories	(256		)	(253		)	68
	Exchanges receivable	(24		)	11			3
	Other current assets	(56		)	571			(62		)
	Other non-current assets, net	(22		)	(53		)	7
	Accounts payable	525			(979		)	31
	Accounts payable to related companies	(122		)	100			6
	Exchanges payable	131			—			3
	Accrued and other current liabilities	152			(151		)	60
	Other non-current liabilities	151			25			—
	Price risk management assets and liabilities, net	(150		)	4			75
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(146	)	$	(475	)	$	166
	Non-cash investing and financing activities and supplemental cash flow information are as follows:
		Years Ended December 31,
		2013			2012			2011
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	167		$	359		$	202
	AmeriGas limited partner interest received in exchange for contribution of Propane Business	$	—		$	1,123		$	—
	Regency common and Class F units received in exchange for contribution of SUGS	$	961		$	—		$	—
	NON-CASH FINANCING ACTIVITIES:
	Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—		$	6,658		$	4
	Issuance of Common Units in connection with acquisitions	$	—		$	2,295		$	3
	Issuance of Common Units in connection with the Holdco Acquisition	$	2,464		$	—		$	—
	Issuance of Class H Units	$	1,514		$	—		$	—
	Contributions receivable related to noncontrolling interest	$	13		$	23		$	—
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	903		$	678		$	476
	Cash paid for income taxes	$	57		$	22		$	24
	Accounts Receivable
	Our midstream, NGL and intrastate transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master setoff agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and intrastate transportation and storage operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.
	Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
	Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operations establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability.
	Our retail marketing segment extends credit to customers after a review of credit rating and other credit indicators.  Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable.  This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible.  The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability.
	We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
	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	$	519		$	334
Crude oil	488			418
Refined products	597			572
Appliances, parts and fittings, and other	161			171
Total inventories	$	1,765		$	1,495
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and 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	261			293
Total other current assets	$	310		$	334
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. Additionally, we 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 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 of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
	December 31,
	2013			2012
Land and improvements	$	878		$	551
Buildings and improvements (5 to 45 years)	900			673
Pipelines and equipment (5 to 83 years)	16,966			17,031
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)	1,685			1,187
Retail equipment (3 to 99 years)	450			258
Vehicles (1 to 25 years)	124			135
Right of way (20 to 83 years)	1,901			2,042
Furniture and fixtures (2 to 25 years)	48			65
Linepack	116			116
Pad gas	52			58
Other (1 to 48 years)	626			806
Construction work-in-process	1,668			1,688
	28,430			27,412
Less – Accumulated depreciation	(2,483		)	(1,639		)
Property, plant and equipment, net	$	25,947		$	25,773
We recognized the following amounts of depreciation expense for the periods presented:
	Years Ended December 31,
	2013			2012			2011
Depreciation expense(1)	$	944		$	615		$	380
Capitalized interest, excluding AFUDC	$	43		$	99		$	11
(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 Unconsolidated Affiliates
We 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 subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, NGL transportation and services, and retail marketing segments and all others. We recorded goodwill impairments for the periods presented in these consolidated financial statements.
Changes in the carrying amount of goodwill were as follows:
	Intrastate			Interstate			Midstream			NGL Transportation and Services			Investment in Sunoco Logistics			Retail Marketing		All Other			Total
	Transportation			Transportation and Storage
	and Storage
Balance, December 31, 2011	$	10		$	99		$	37		$	432		$	—		$	—	$	642		$	1,220
Goodwill acquired	—			1,785			338			—			1,368			1,272		375			5,138
Goodwill sold in deconsolidation of Propane Business	—			—			—			—			—			—		(619		)	(619		)
Goodwill allocated to the disposal group	—			—			—			—			—			—		(133		)	(133		)
Balance, December 31, 2012	10			1,884			375			432			1,368			1,272		265			5,606
Goodwill acquired	—			—			—			—			—			156		—			156
Goodwill disposed	—			—			(337		)	—			—			—		—			(337		)
Goodwill impairment	—			(689		)	—			—			—			—		—			(689		)
Other	—			—			(2		)	—			(22		)	17		—			(7		)
Balance, December 31, 2013	$	10		$	1,195		$	36		$	432		$	1,346		$	1,445	$	265		$	4,729
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 decrease in goodwill of $877 million during the year ended December 31, 2013 primarily due to Trunkline LNG’s goodwill impairment of $689 million (see below) and a decrease of $337 million as a result of the SUGS Contribution (see Note 3). These decreases were offset by additional goodwill of $156 million from acquisitions in 2013. This additional goodwill is not expected to be deductible for tax purposes.
During the fourth quarter of 2013, we performed a goodwill impairment test on our Trunkline LNG reporting unit. In accordance with GAAP, we 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.  We 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, we 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, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We 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, we 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 balance sheet 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:
	31-Dec-13						31-Dec-12
	Gross Carrying			Accumulated			Gross Carrying			Accumulated
	Amount			Amortization			Amount			Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	1,393		$	(164	)	$	1,290		$	(80	)
Patents (9 years)	48			(6		)	48			(1		)
Other (10 to 15 years)	4			(1		)	4			(1		)
Total amortizable intangible assets	$	1,445		$	(171	)	$	1,342		$	(82	)
Non-amortizable intangible assets:
Trademarks	294			—			301			—
Total intangible assets	$	1,739		$	(171	)	$	1,643		$	(82	)
Aggregate amortization expense of intangible assets was as follows:
	Years Ended December 31,
	2013			2012			2011
Reported in depreciation and amortization	$	88		$	36		$	24
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31:
2014		$	93
2015		93
2016		93
2017		93
2018		92
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)	$	70		$	54
Regulatory assets	86			87
Deferred charges	144			140
Restricted funds	378			—
Other	88			76
Total other non-current assets, net	$	766		$	357
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 estimate 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 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	$	294		$	256
Customer advances and deposits	126			44
Accrued capital expenditures	166			356
Accrued wages and benefits	155			236
Taxes payable other than income taxes	214			203
Income taxes payable	3			40
Deferred income taxes	119			130
Other	351			297
Total accrued and other current liabilities	$	1,428		$	1,562
Deposits or advances are received from our 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 loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2013 was $17.69 billion and $17.09 billion, respectively. As of December 31, 2012, the aggregate fair value and carrying amount of our debt obligations was $17.84 billion and $16.22 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of 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. During the period ended December 31, 2013, no transfers were made between any levels within the fair value hierarchy.
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 Total			Fair Value Measurements at December 31, 2013
				Level 1			Level 2
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	201			201			—
Power:
Forwards	3			—			3
Natural Gas Liquids – Forwards/Swaps	5			5			—
Refined Products – Futures	5			5			—
Total commodity derivatives	227			217			10
Total assets	$	274		$	217		$	57
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—
Swing Swaps IFERC	(6		)	—			(6		)
Fixed Swaps/Futures	(201		)	(201		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(1		)	—			(1		)
Natural Gas Liquids – Forwards/Swaps	(5		)	(5		)	—
Refined Products – Futures	(5		)	(5		)	—
Total commodity derivatives	(223		)	(215		)	(8		)
Total liabilities	$	(318	)	$	(215	)	$	(103	)
	Fair Value			Fair Value Measurements at December 31, 2012
	Total			Level 1			Level 2
Assets:
Interest rate derivatives	$	55		$	—		$	55
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—
Swing Swaps IFERC	3			—			3
Fixed Swaps/Futures	96			94			2
Options – Puts	1			—			1
Options – Calls	3			—			3
Forward Physical Swaps	1			—			1
Power:
Forwards	27			—			27
Futures	1			1			—
Options – Calls	2			—			2
Natural Gas Liquids – Swaps	1			1			—
Refined Products – Futures	5			1			4
Total commodity derivatives	151			108			43
Total assets	$	206		$	108		$	98
Liabilities:
Interest rate derivatives	$	(223	)	$	—		$	(223	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—
Swing Swaps IFERC	(2		)	—			(2		)
Fixed Swaps/Futures	(103		)	(94		)	(9		)
Options – Puts	(1		)	—			(1		)
Options – Calls	(3		)	—			(3		)
Power:
Forwards	(27		)	—			(27		)
Futures	(2		)	(2		)	—
Natural Gas Liquids – Swaps	(3		)	(3		)	—
Refined Products – Futures	(8		)	(1		)	(7		)
Total commodity derivatives	(167		)	(118		)	(49		)
Total liabilities	$	(390	)	$	(118	)	$	(272	)
At December 31, 2013, the fair value of the 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. We used the income approach to measure the fair value of the Trunkline LNG reporting unit. Under the income approach, we 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.
Contributions in Aid of Construction Costs
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 our 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 government authorities on a net basis except for our retail marketing segment 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 our retail marketing segment were $2.22 billion and $573 million for the years ended December 31, 2013 and 2012, respectively.
Income Taxes
ETP 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 most state 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 basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second 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, ETP 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 our consolidated statements 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 statements 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, the 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 manage 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 subsidiaries.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
ACQUISITIONS AND DIVESTITURE	'
		ACQUISITIONS, DIVESTITURES 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 common units and 6.3 million Class F Units), and ETP (2.2 million 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. This transaction was effective as of January 1, 2014. The results of Trunkline LNG’s operations have not been presented as discontinued operations and Trunkline LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the expected continuing involvement among the entities.
	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 7.
	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’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that 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 income 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. The Partnership has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.
	Acquisition of ETE’s Holdco Interest
	On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
	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. See below for discussion of Holdco Transaction and ETE’s contribution of Southern Union to Holdco.
	Under the terms of the merger agreement, Southern Union stockholders received a total of 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, we completed our 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 our 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 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 the Partnership.
	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 approximate 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 in 2012, 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 (“Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 7. 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.
	In accordance with GAAP, we have accounted for the Holdco Transaction, whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted interim periods in 2012, and no prior annual amounts have been adjusted.
	Summary of Assets Acquired and Liabilities Assumed
	We accounted for the 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. Upon consummation of the Holdco Transaction, we applied the accounting guidance for transactions between entities under common control. In doing so, we recorded the values of assets and liabilities that had been recorded by ETE as reflected below.
	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 Holdco Transaction, we recognized $38 million of merger-related costs during the year ended December 31, 2012 related to Southern Union. 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, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We 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, we entered into a support agreement with AmeriGas pursuant to which we are 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 we will have a continuing involvement in this business as a result of the investment in AmeriGas that was transferred as consideration for the transaction.
In June 2012, we sold the remainder of our retail propane operations, consisting of our 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 we received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, we sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated 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 midstream segment.
2011 Transaction
LDH Acquisition
On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by the Partnership 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. The Partnership contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% 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 the Partnership’s asset portfolio by adding an NGL platform with storage, transportation and fractionation capabilities.
We accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are included in our NGL transportation and services segment. Regency’s 30% interest in Lone Star is reflected as noncontrolling interest.
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	$	39,136	$	36,169
Net income	1,133		1,027
Net income attributable to partners	788		745
Basic net income per Limited Partner unit	$	1.33	$	1.24
Diluted net income per Limited Partner unit	$	1.33	$	1.24
The pro forma consolidated results of operations include adjustments to:
•	include the results of Lone Star, 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;
•	include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price; and
•	reflect noncontrolling interest related to ETE’s 60% interest in Holdco during the periods.
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.

Investments_in_Unconsolidated_

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2013
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]	'
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	'
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
	Regency
	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 (see Note 3). The consideration paid by Regency in connection with this transaction included approximately 31.4 million Regency common units, approximately 6.3 million Regency Class F units, the distribution of $463 million in cash to Southern Union, net of closing adjustments, and the payment of $30 million in cash to a subsidiary of ETP. This direct investment in Regency common and Class F units received has been accounted for using the equity method.
	The carrying amount of our investment in Regency was $1.41 billion as of December 31, 2013 and was reflected in our all other segment.
	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.
	We recorded our investment in Citrus at $2.0 billion, which exceeded our 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 our investment in Citrus was $1.89 billion and $1.98 billion as of December 31, 2013 and 2012, respectively, and was reflected in our interstate transportation and storage segment.
	AmeriGas Partners, L.P.
	As discussed in Note 3, on January 12, 2012, we received approximately 29.6 million AmeriGas common units in connection with the contribution of our propane operations. On July 12, 2013, we sold 7.5 million AmeriGas common units for net proceeds of $346 million, and as of December 31, 2013, we owned 22.1 million AmeriGas common units representing an approximate 24% limited partner interest.
	The carrying amount of our investment in AmeriGas was $746 million and $1.02 billion as of December 31, 2013 and 2012, respectively, and was reflected in our all other segment. As of December 31, 2013, our investment in AmeriGas reflected $439 million in excess of our 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, we 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.
	FEP
	We have a 50% interest in FEP, a 50/50 joint venture with KMP. 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 our investment in FEP was $144 million and $159 million as of December 31, 2013 and 2012, respectively, and was reflected in our interstate transportation and storage segment.
	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, FEP, AmeriGas, Citrus and Regency (on a 100% basis) for all periods presented:
		December 31,
		2013		2012
	Current assets	$	1,372	$	878
	Property, plant and equipment, net	12,320		8,063
	Other assets	6,478		2,529
	Total assets	$	20,170	$	11,470
	Current liabilities	$	1,455	$	1,605
	Non-current liabilities	10,286		6,143
	Equity	8,429		3,722
	Total liabilities and equity	$	20,170	$	11,470
		Years Ended December 31,
		2013		2012		2011
	Revenue	$	6,806	$	4,057	$	3,337
	Operating income	1,043		635		681
	Net income	574		338		341
	In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner Unit (Notes)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
NET INCOME PER LIMITED PARTNER UNIT	'
	NET INCOME PER LIMITED PARTNER UNIT:
	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	$	735		$	1,757		$	700
	Less: Income from continuing operations attributable to noncontrolling interest	296			62			28
	Income from continuing operations, net of noncontrolling interest	439			1,695			672
	General Partner’s interest in income from continuing operations	505			463			433
	Limited Partners’ interest in income (loss) from continuing operations	(66		)	1,232			239
	Additional earnings allocated (to) from General Partner	(2		)	1			1
	Distributions on employee unit awards, net of allocation to General Partner	(10		)	(9		)	(8		)
	Income (loss) from continuing operations available to Limited Partners	$	(78	)	$	1,224		$	232
	Weighted average Limited Partner units – basic	343.4			248.3			207.2
	Basic income (loss) from continuing operations per Limited Partner unit	$	(0.23	)	$	4.93		$	1.12
	Dilutive effect of unvested Unit Awards	—			0.7			0.9
	Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	343.4			249			208.1
	Diluted income (loss) from continuing operations per Limited Partner unit	$	(0.23	)	$	4.91		$	1.12
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.05		$	(0.50	)	$	(0.02	)
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.05		$	(0.50	)	$	(0.02	)

Debt_Obligations_Notes

Debt Obligations (Notes)	12 Months Ended
	Dec. 31, 2013
Debt Obligations [Abstract]	'
DEBT OBLIGATIONS	'
	DEBT OBLIGATIONS:
	Our debt obligations consist of the following:
		December 31,
		2013			2012
	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
	6.50% 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
	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
	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
	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
	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
Note Payable to ETE	—			166
Other	228			32
	17,088			16,217
Less: current maturities	637			609
	$	16,451		$	15,608
(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 $308 million in unamortized net premiums and fair value adjustments:
2014		$	812
2015		1,047
2016		375
2017		1,220
2018		1,205
Thereafter		12,121
Total		$	16,780
ETP as Co-Obligor of Sunoco Debt
In connection with the Sunoco Merger and Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco’s existing senior notes and debentures.
ETP Senior Notes
The ETP Senior Notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP Senior Notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP Senior Notes. The balance is payable upon maturity. Interest on the ETP Senior Notes is paid semi-annually.
The ETP Senior Notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP Senior Notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
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 paid semi-annually.
Note Payable – ETE
On March 26, 2012, Southern Union received $221 million from ETE to pay certain expenses in connection with the Merger, including (i) payments made to employees related to outstanding awards of stock options, stock appreciation rights and RSUs; and (ii) payments to certain executives under applicable employment or change in control agreements, which provided for compensation when their employment was terminated in connection with a change in control.  In connection with the receipt of the $221 million from ETE, on March 26, 2012, Southern Union entered into an interest-bearing promissory note payable due on or before March 25, 2013.  The interest rate under the promissory note was 3.25% and accrued interest was payable monthly in arrears. A payment of $55 million to ETE was made in May 2012, and the outstanding balance of $166 million was assumed by Holdco as of December 31, 2012 and the maturity date of the note payable was extended to January 22, 2014. The note payable outstanding was paid in 2013.
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.
Panhandle Term Loans
A portion of the proceeds from ETP’s September 2013 Senior Notes Offering, as discussed below, was used to repay $455 million in borrowings outstanding under the LNG Holdings term loan due February 2015.
January 2013 Senior Notes Offerings
In January 2013, ETP issued $800 million aggregate principal amount of 3.6% Senior Notes due February 2023 and $450 million aggregate principal amount of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.
In January 2013, Sunoco Logistics issued $350 million aggregate principal amount of 3.45% Senior Notes due January 2023 and $350 million aggregate principal amount of 4.95% Senior Notes due January 2043. Sunoco Logistics’ used the net proceeds of $691 million from the offering to repay borrowings outstanding under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.
September 2013 Senior Notes Offering
In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly-owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.
Note Exchange
On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066.  These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates.  In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.
Credit Facilities
ETP Credit Facility
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 the Partnership’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 our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes.
In November 2013, we 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%.
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 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 Partnership’s and certain of the Partnership’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 the Partnership 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 5.0 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.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
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 Southern Union’s debt agreements that require Southern Union to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. 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, 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.
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2013.

Equity_Notes

Equity (Notes)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
EQUITY	'
	EQUITY:
	Limited Partner interests are represented by Common, Class E Units, Class G Units and Class H Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. As of December 31, 2013, there were issued and outstanding 333.8 million Common Units representing an aggregate 99.3% Limited Partner interest in us. There are also 8.9 million Class E Units and 90.7 million Class G Units outstanding that are reported as treasury units, which units are entitled to receive distributions in accordance with their terms. There are also 50.2 million Class H Units outstanding representing Limited Partner interests owned by ETE Holdings (see “Class H Units” below).
	No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.
	IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
	Common Units
	The change in Common Units was as follows:
		Years Ended December 31,
		2013			2012			2011
	Number of Common Units, beginning of period	301.5			225.5			193.2
	Common Units issued in connection with public offerings	13.8			15.5			29.4
	Common Units issued in connection with certain acquisitions	49.5			57.4			0.1
	Common Units redeemed for Class H Units	(50.2	)		—			—
	Common Units issued in connection with the Distribution Reinvestment Plan	2.3			1			0.4
	Common Units issued in connection with Equity Distribution Agreements	16.9			1.6			2
	Repurchases of Common Units in open-market transactions	(0.4	)		—			—
	Issuance of Common Units under equity incentive plans	0.4			0.5			0.4
	Number of Common Units, end of period	333.8			301.5			225.5
	Our 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 our 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 “Quarterly Distributions of Available Cash.”
	Public Offerings
	The following table summarizes our public offerings of Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
	Date		Number of Common Units			Price per Unit			Net Proceeds
	Apr-11		14.2			$	50.52		$	695
	Nov-11		15.2			44.67			660
	Jul-12		15.5			44.57			671
	Apr-13		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.
	Equity Distribution Program
	From time to time, we have sold Common Units through an equity distribution agreement. Such sales of 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, we entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the year ended December 31, 2013, we issued approximately 16.9 million units for $846 million, net of commissions of $9 million. Approximately $145 million of our Common Units remained available to be issued under the currently effective equity distribution agreements as of December 31, 2013.
	Equity Incentive Plan Activity
	As discussed in Note 8, we issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.
	Distribution Reinvestment Program
	In April 2011, we filed a registration statement with the SEC covering our Distribution Reinvestment Plan (the “DRIP”). The DRIP provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. The registration statement covers the issuance of up to 5.8 million 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 Common Units. As of December 31, 2013, a total of 2.1 million Common Units remain available to be issued under the existing registration statement.
	Class E Units
	There are 8.9 million Class E Units outstanding that are reported as treasury units. These Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests. The Class E Units are treated 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 Class E Units at a future date.
	Class G Units
	In conjunction with the Sunoco Merger, we amended our partnership agreement to create the Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million Class F Units issued in exchange for cash contributed by Sunoco to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally did not have any voting rights. The Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than Holdco, and available for distribution, up to a maximum of $3.75 per Class F Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements.
	Class H Units
	Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE 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.
	Quarterly Distributions of Available Cash
	The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our General Partner within forty-five 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 of our fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of our 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 our Partnership Agreement.
	Our distributions of Available Cash from operating surplus, excluding incentive distributions, to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner are determined based on the amount by which quarterly distribution to common Unitholders exceed certain specified target levels, as set forth in our Partnership Agreement.
	Distributions declared during the periods presented below are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Rate
	31-Dec-10		7-Feb-11		14-Feb-11		$	0.89375
	31-Mar-11		6-May-11		16-May-11		0.89375
	30-Jun-11		5-Aug-11		15-Aug-11		0.89375
	30-Sep-11		4-Nov-11		14-Nov-11		0.89375
	31-Dec-11		7-Feb-12		14-Feb-12		0.89375
	31-Mar-12		4-May-12		15-May-12		0.89375
	30-Jun-12		6-Aug-12		14-Aug-12		0.89375
	30-Sep-12		6-Nov-12		14-Nov-12		0.89375
	31-Dec-12		7-Feb-13		14-Feb-13		0.89375
	31-Mar-13		6-May-13		15-May-13		0.89375
	30-Jun-13		5-Aug-13		14-Aug-13		0.89375
	30-Sep-13		4-Nov-13		14-Nov-13		0.905
	31-Dec-13		7-Feb-14		14-Feb-14		0.92
	Following are incentive distributions ETE has agreed to relinquish:
	•	In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.
	•	In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
	•	As discussed in Note 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 “Class H Units” above, were intended to offset a portion of the incentive distribution relinquishments previously granted by ETE to the Partnership. In connection with the issuance of the Class H Units, ETE and the Partnership also agreed to certain adjustments to the incremental distributions on the 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 Class H Units are fixed amounts for each quarter for which the incentive distribution relinquishments and incremental distributions on the Class H Units are in effect.
In addition to the amounts above, in connection with the Partnership’s transfer of Trunkline LNG to ETE in February 2014, ETE agreed to provide additional subsidies to ETP through its relinquishment of incentive distributions of $50 million, $50 million, $45 million and $35 million for the years ending 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 Class H Units would reduce the total distributions that would potentially be made to ETE in future quarters:
		Quarters Ending
		31-Mar				30-Jun			30-Sep		31-Dec		Total Year
2014		$	26.5			$	26.5		$	26.5	$	26.5	$	106
2015		12.5				12.5			13		13		51
2016		18				18			18		18		72
2017		12.5				12.5			12.5		12.5		50
2018		11.25				11.25			11.25		11.25		45
2019		8.75				8.75			8.75		8.75		35
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared during the periods presented below are summarized as follows:
Quarter Ended		Record Date		Payment Date		Rate
December 31, 2012		February 8, 2013		February 14, 2013		$	0.545
March 31, 2013		May 9, 2013		May 15, 2013		0.5725
June 30, 2013		8-Aug-13		14-Aug-13		0.6
September 30, 2013		8-Nov-13		14-Nov-13		0.63
December 31, 2013		10-Feb-14		14-Feb-14		0.6625
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
	December 31,
	2013				2012
Available-for-sale securities	$	2			$	—
Foreign currency translation adjustment	(1		)		—
Net loss on commodity related hedges	(4		)		—
Actuarial gain (loss) related to pensions and other postretirement benefits	56				(10		)
Equity investments, net	8				(9		)
Subtotal	61				(19		)
Amounts attributable to noncontrolling interest	—				6
Total AOCI, net of tax	$	61			$	(13	)
The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:
	December 31,
	2013				2012
Net gains on commodity related hedges	$	—			$	1
Actuarial (gain) loss relating to pension and other postretirement benefits	(39		)		5
Total	$	(39	)		$	6

UnitBased_Compensation_Plans_N

Unit-Based Compensation Plans (Notes)	12 Months Ended
	Dec. 31, 2013
Deferred Compensation Arrangements [Abstract]	'
UNIT-BASED COMPENSATION PLANS	'
	UNIT-BASED COMPENSATION PLANS:
	ETP Unit-Based Compensation Plan
	We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2013, an aggregate total of 0.9 million ETP Common Units remain available to be awarded under our equity incentive plans.
	Unit Grants
	We have 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 Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.
	Award Activity
	The following table shows the activity of the awards granted to employees and non-employee directors:
		Number of Units		Weighted Average Grant-Date Fair Value Per 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 the President of the entity that indirectly owns our General Partner, 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 5 year vesting schedule whereby the officer 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.
	We recognized non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded the ETP employees assuming no forfeitures. For the years ended December 31, 2013, 2012 and 2011, we 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.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [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) are summarized as follows:
		Years Ended December 31,
		2013			2012			2011
	Current expense (benefit):
	Federal	$	51		$	(3	)	$	(1	)
	State	(2		)	4			16
	Total	49			1			15
	Deferred expense:
	Federal	(6		)	45			4
	State	54			17			—
	Total	48			62			4
	Total income tax expense from continuing operations	$	97		$	63		$	19
	Historically, our effective 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 Merger, Sunoco Merger and Holdco Transaction (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:
		31-Dec-13									31-Dec-12
		Corporate Subsidiaries(1)			Partnership(2)			Consolidated			Corporate Subsidiaries(1)		Partnership(2)		Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	(166	)	$	—		$	(166	)	$	1	$	—	$	1
	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			5			36			9		7		16
	Other	(13		)	(1		)	(14		)	18		—		18
	Income tax from continuing operations	$	93		$	4		$	97		$	56	$	7	$	63
	(1)	Includes Holdco, Oasis Pipeline Company, 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 ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes.
	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
		December 31,
		2013			2012
	Deferred income tax assets:
	Net operating losses and alternative minimum tax credit	$	217		$	268
	Pension and other postretirement benefits	57			127
	Long term debt	108			117
	Other	104			288
	Total deferred income tax assets	486			800
	Valuation allowance	(74		)	(90		)
	Net deferred income tax assets	$	412		$	710
	Deferred income tax liabilities:
	Properties, plants and equipment	$	(1,522	)	$	(1,938	)
	Inventory	(302		)	(516		)
	Investment in unconsolidated affiliates	(2,244		)	(1,542		)
	Trademarks	(180		)	(192		)
	Other	(45		)	(128		)
	Total deferred income tax liabilities	(4,293		)	(4,316		)
	Net deferred income tax liability	(3,881		)	(3,606		)
	Less: current portion of deferred income tax assets (liabilities)	(119		)	(130		)
	Accumulated deferred income taxes	$	(3,762	)	$	(3,476	)
	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	$	(3,606	)	$	(123	)
	Southern Union acquisition	—			(1,420		)
	Sunoco acquisition	—			(1,989		)
	SUGS Contribution to Regency	(115		)	—
	Tax provision (including discontinued operations)	(111		)	(73		)
	Other	(49		)	(1		)
	Net deferred income tax liability	$	(3,881	)	$	(3,606	)
	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	—			—			(1		)
Lapse of statute	(4		)	(3		)	—
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 financial statements 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, ETP and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2009, except Sunoco and Southern Union which are no longer subject to examination by the IRS for tax years prior to 2007 and 2004, respectively.
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.
ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory_Matters_Commitments

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
Commitments Contingencies and Guarantees [Text Block]	'
	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
	FERC Audit
	The FERC recently completed an audit of PEPL, a subsidiary of Southern Union, for the period from January 1, 2010 through December 31, 2011, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. An audit report was received in August 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.
	Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
	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 its 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
	We have interests in NGL pipelines located in Texas and New Mexico. We 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 our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $140 million, $57 million and $26 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	$	80
	2015	78
	2016	70
	2017	66
	2018	53
	Thereafter	420
	Future minimum lease commitments	767
	Less: Sublease rental income	(57		)
	Net future minimum lease commitments	$	710
	Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
	Litigation and Contingencies
	We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
	Sunoco Litigation
	Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania.  Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.
	Litigation Relating to the Southern Union Merger
	In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.
	Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.
	On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.
	MTBE Litigation
	Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases 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.
	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 consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
	The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
	No amounts have been recorded in our 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 (“AG”) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling 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, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses.
	Environmental Matters
	Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
	Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
	Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
	Environmental Remediation
	Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
	•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
	•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
	•	Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.
	•	Currently operating Sunoco retail sites.
	•	Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
	•	Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of 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	$	45		$	46
Non-current	350			165
Total environmental liabilities	$	395		$	211
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, Sunoco had $36 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 segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Price_risk_management_assets_a

Price risk management assets and liabilties (Notes)	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, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
	We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
	We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	We may use derivatives in our NGL transportation and services segment to manage our 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.
	Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
	Derivatives are utilized in our all other segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.
	The following table details our outstanding commodity-related derivatives:
		31-Dec-13					31-Dec-12
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	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 commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.
	Interest Rate Risk
	We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
	The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
							Notional Amount Outstanding
	Entity		Term		Type(1)		31-Dec-13				31-Dec-12
	ETP		July 2013(2)		Forward-starting to pay a fixed rate of 4.03% and receive a floating rate		$	—			$	400
	ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		400				400
	ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				600
	ETP		Jun-21		Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%		400				—
	ETP		Feb-23		Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		400				—
	Southern Union(3)		Nov-16		Pay a fixed rate of 2.97% and receive a floating rate		—				75
	Southern Union(3)		Nov-21		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 termination date the same as the effective date. During the year ended December 31, 2013, we 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 transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s 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.
We have 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 our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
	Fair Value of Derivative Instruments
	Asset Derivatives								Liability Derivatives
	31-Dec-13				31-Dec-12				31-Dec-13				31-Dec-12
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	39				33				(38		)		(34		)
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		)		(223		)
	313				200				(342		)		(382		)
Total derivatives	$	316			$	208			$	(360	)		$	(392	)
In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
				Asset Derivatives								Liability Derivatives
		Balance Sheet Location		December 31, 2013				December 31, 2012				December 31, 2013				December 31, 2012
Derivatives in offsetting agreements:
OTC contracts		Price risk management assets (liabilities)		$	41			$	28			$	(38	)		$	(27	)
Broker cleared derivative contracts		Other current assets (liabilities)		265				150				(318		)		(228		)
				306				178				(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				153				(265		)		(169		)
Derivatives without offsetting agreements				47				55				(95		)		(223		)
Total derivatives				$	316			$	208			$	(360	)		$	(392	)
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following tables summarize the amounts recognized with respect to our derivative financial instruments:
	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Years Ended December 31,
	2013				2012				2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(1	)		$	8			$	19
Total	$	(1	)		$	8			$	19
	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			$	38
Total			$	4			$	14			$	38
	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 not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold		$	(11	)		$	(7	)		$	(30	)
Commodity derivatives – Non-trading	Cost of products sold		(12		)		(15		)		9
Commodity contracts – Non-trading	Deferred gas purchases		(3		)		(26		)		—
Interest rate derivatives	Gains (losses) on interest rate derivatives		44				(4		)		(77		)
Total			$	18			$	(52	)		$	(98	)

Retirement_Benefits_Notes

Retirement Benefits (Notes)	12 Months Ended
	Dec. 31, 2013
RETIREMENT BENEFITS	'
Pension and Other Postretirement Benefits Disclosure	'
	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. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38 million, $21 million and $11 million to these 401(k) savings plans for the years ended December 31, 2013, 2012 and 2011, respectively.
	Pension and Other Postretirement Benefit Plans
	Southern Union
	Southern Union has funded non-contributory defined benefit pension plans that cover substantially all employees of Southern Union’s distribution operations.  Normal retirement age is 65, but certain plan provisions allow for earlier retirement.  Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.
	The 2012 postretirement benefits expense for Southern Union reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated.  Southern Union previously had postretirement health care and life insurance plans that covered substantially of its distribution and transportation and storage operations employees as well as all corporate employees.  The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.
	Sunoco
	Sunoco has both funded and unfunded noncontributory defined benefit pension plans. Sunoco also has plans which provide health care benefits for substantially all of its current retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are shared by Sunoco and its retirees. Prior to the Sunoco Merger on October 5, 2012, pension benefits under Sunoco’s defined benefit plans were frozen for most of the participants in these plans at which time Sunoco instituted a discretionary profit-sharing contribution on behalf of these employees in its defined contribution plan. Postretirement medical benefits were also phased down or eliminated for all employees retiring after July 1, 2010. Sunoco has established a trust for its postretirement benefit liabilities by making a tax-deductible contribution of approximately $200 million and restructuring the retiree medical plan to eliminate Sunoco’s liability beyond this funded amount. The retiree medical plan change eliminated substantially all of Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
	Obligations and Funded Status
	Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
		31-Dec-13												31-Dec-12
		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:
		31-Dec-13											31-Dec-12
		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
		31-Dec-13								31-Dec-12
		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 operations.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
	31-Dec-13						31-Dec-12
	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:
	31-Dec-13						31-Dec-12
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Discount rate	3.5	%		2.68	%		2.37	%		2.43	%
Expected return on assets:
Tax exempt accounts	7.5	%		6.95	%		7.63	%		7	%
Taxable accounts	N/A			4.42	%		N/A			4.5	%
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 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 allocation 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 Measurements at December 31, 2013 Using Fair Value Hierarchy
	Fair Value as of 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 Measurements at December 31, 2012 Using Fair Value Hierarchy
	Fair Value as of 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 other postretirement plan assets by asset category at the dates indicated is as follows:
					Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
	Fair Value as of 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 Measurements at December 31, 2012 Using Fair Value Hierarchy
	Fair Value as of 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.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.
Contributions
We expect to contribute approximately $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 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_Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	RELATED PARTY TRANSACTIONS:
	ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includes the reimbursement of various general and administrative services for expenses incurred by us on behalf of Regency.
	In the ordinary course of business, we provide Regency with certain natural gas and NGLs sales and transportation services and compression equipment, and Regency provides us with certain contract compression services. These related party transactions are generally based on transactions made at market-related rates.
	Sunoco Logistics has an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 Bbls/d of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, Sunoco Logistics is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. Sunoco Logistics entered into a ten-year agreement to provide terminalling services to PES in September 2012.
	In September 2012, Sunoco assigned its lease for the use of Sunoco Logistics’ inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67% each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse Sunoco Logistics for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during the periods presented.
	In connection with the acquisition of the Marcus Hook Facility, Sunoco Logistics assumed an agreement to provide butane storage and terminal services to PES at the facility. The 10 year agreement extends through September 2022.
	Sunoco Logistics has agreements with PES whereby PES purchases crude oil, at market-based rates, for delivery to Sunoco Logistics’ Fort Mifflin and Eagle Point terminal facilities. These agreements contain minimum volume commitments and extend through 2014.
	The renegotiated terms of the agreements with PES provide PES with the option to purchase the Fort Mifflin and Belmont terminals if certain triggering events occur, including a sale of substantially all of the assets or operations of the Philadelphia refinery, an initial public offering or a public debt filing of more than $200 million. The purchase price for each facility would be established based on a fair value amount determined by designated third parties.
	The following table summarizes the affiliated revenues on our consolidated statements of operations:
		Years Ended December 31,
		2013		2012		2011
	Affiliated revenues	$	1,550	$	173	$	690
	The following table summarizes the related company balances on our consolidated balance sheets:
		December 31,
		2013		2012
	Accounts receivable from related companies:
	ETE	$	18	$	16
	Regency	53		10
	PES	7		60
	FGT	29		2
	Eastern Gulf	24		—
	Other	34		6
	Total accounts receivable from related companies:	$	165	$	94
	Accounts payable to related companies:
	ETE	$	8	$	7
	Regency	24		2
	PES	—		13
	FGT	8		—
	Other	5		2
	Total accounts payable to related companies:	$	45	$	24

Reportable_Segments_Notes

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2013
Reportable Segments [Abstract]	'
REPORTABLE SEGMENTS	'
	REPORTABLE SEGMENTS:
	As a result of the Sunoco Merger and Holdco Transaction, our reportable segments were re-evaluated and changed in 2012. Our financial statements currently reflect the following reportable segments, which conduct their business exclusively in the United States, as follows:
	•intrastate transportation and storage;
	•interstate transportation and storage;
	•midstream;
	•NGL transportation and services;
	•investment in Sunoco Logistics;
	•retail marketing; and
	•all other.
	During the fourth quarter 2013, management realigned the composition of our reportable segments, and as a result, our natural gas marketing operations are now aggregated into the “all other” segment. These operations were previously reported in the midstream segment. Based on this change in our segment presentation, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
	Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
	Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our retail marketing segment are primarily reflected in refined product sales.
	We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
	The following tables present the financial information by segment:
		Years Ended December 31,
		2013			2012			2011
	Revenues:
	Intrastate transportation and storage:
	Revenues from external customers	$	2,250		$	2,012		$	2,398
	Intersegment revenues	202			179			276
		2,452			2,191			2,674
	Interstate transportation and storage:
	Revenues from external customers	1,270			1,109			447
	Intersegment revenues	39			—			—
		1,309			1,109			447
	Midstream:
	Revenues from external customers	1,307			1,757			1,082
	Intersegment revenues	942			196			401
		2,249			1,953			1,483
	NGL transportation and services:
	Revenues from external customers	2,063			619			363
	Intersegment revenues	64			31			34
		2,127			650			397
	Investment in Sunoco Logistics:
	Revenues from external customers	16,480			3,109			—
	Intersegment revenues	159			80			—
		16,639			3,189			—
	Retail marketing:
	Revenues from external customers	21,004			5,926			—
	Intersegment revenues	8			—			—
		21,012			5,926			—
	All other:
	Revenues from external customers	1,965			1,170			2,509
	Intersegment revenues	402			385			379
		2,367			1,555			2,888
	Eliminations	(1,816		)	(871		)	(1,090		)
	Total revenues	$	46,339		$	15,702		$	6,799
		Years Ended December 31,
		2013			2012			2011
	Cost of products sold:
	Intrastate transportation and storage	$	1,737		$	1,394		$	1,774
	Midstream	1,579			1,273			988
	NGL transportation and services	1,655			361			218
	Investment in Sunoco Logistics	15,574			2,885			—
	Retail marketing	20,150			5,757			—
	All other	2,309			1,496			2,274
	Eliminations	(1,800		)	(900		)	(1,079		)
	Total cost of products sold	$	41,204		$	12,266		$	4,175
		Years Ended December 31,
		2013			2012			2011
	Depreciation and amortization:
	Intrastate transportation and storage	$	122		$	122		$	120
	Interstate transportation and storage	244			209			81
Midstream	172			168			85
NGL transportation and services	91			53			32
Investment in Sunoco Logistics	265			63			—
Retail marketing	114			28			—
All other	24			13			87
Total depreciation and amortization	$	1,032		$	656		$	405
	Years Ended December 31,
	2013			2012			2011
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	—		$	4		$	2
Interstate transportation and storage	142			120			24
Midstream	—			(9		)	—
NGL transportation and services	(2		)	2			—
Investment in Sunoco Logistics	18			5			—
Retail marketing	2			1			—
All other	12			19			—
Total equity in earnings of unconsolidated affiliates	$	172		$	142		$	26
	Years Ended December 31,
	2013			2012			2011
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	464		$	601		$	667
Interstate transportation and storage	1,269			1,013			373
Midstream	479			467			421
NGL transportation and services	351			209			127
Investment in Sunoco Logistics	871			219			—
Retail marketing	325			109			—
All other	194			126			193
Total Segment Adjusted EBITDA	3,953			2,744			1,781
Depreciation and amortization	(1,032		)	(656		)	(405		)
Interest expense, net of interest capitalized	(849		)	(665		)	(474		)
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	44			(4		)	(77		)
Non-cash unit-based compensation expense	(47		)	(42		)	(38		)
Unrealized gains (losses) on commodity risk management activities	51			(9		)	(11		)
LIFO valuation adjustments	3			(75		)	—
Loss on extinguishment of debt	—			(115		)	—
Non-operating environmental remediation	(168		)	—			—
Adjusted EBITDA related to discontinued operations	(76		)	(99		)	(23		)
Adjusted EBITDA related to unconsolidated affiliates	(629		)	(480		)	(56		)
Equity in earnings of unconsolidated affiliates	172			142			26
Other, net	12			22			(4		)
Income from continuing operations before income tax expense	$	832		$	1,820		$	719
	December 31,
	2013			2012			2011
Total assets:
Intrastate transportation and storage	$	4,606		$	4,691		$	4,785
Interstate transportation and storage	10,988			11,794			3,661
Midstream	3,133			4,946			2,513
NGL transportation and services	4,326			3,765			2,360
Investment in Sunoco Logistics	11,650			10,291			—
Retail marketing	3,936			3,926			—
All other	5,063			3,817			2,200
Total	$	43,702		$	43,230		$	15,519
	Years Ended December 31,
	2013			2012			2011
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis):
Intrastate transportation and storage	$	47		$	37		$	53
Interstate transportation and storage	152			133			207
Midstream	565			1,317			837
NGL transportation and services	443			1,302			325
Investment in Sunoco Logistics	1,018			139			—
Retail marketing	176			58			—
All other	54			63			62
Total	$	2,455		$	3,049		$	1,484
	December 31,
	2013			2012			2011
Advances to and investments in unconsolidated affiliates:
Intrastate transportation and storage	$	1		$	2		$	1
Interstate transportation and storage	2,040			2,142			173
Midstream	—			1			—
NGL transportation and services	29			29			27
Investment in Sunoco Logistics	125			118			—
Retail marketing	22			21			—
All other	2,219			1,189			—
Total	$	4,436		$	3,502		$	201

Quarterly_Financial_Data_Notes

Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
QUARTERLY FINANCIAL DATA (UNAUDITED)	'
		QUARTERLY FINANCIAL DATA (UNAUDITED):
	Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. ETC OLP’s business is also seasonal due to the operations of ET Fuel System and the HPL System. We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
			Quarter Ended
			31-Mar		30-Jun		September 30			December 31			Total Year
	2013:00:00
	Revenues		$	10,854	$	11,551	$	11,902		$	12,032		$	46,339
	Gross profit		1,260		1,322		1,248			1,305			5,135
	Operating income (loss)		534		632		526			(151		)	1,541
	Net income (loss)		424		413		404			(473		)	768
	Limited Partners’ interest in net income (loss)		194		165		209			(666		)	(98		)
	Basic net income (loss) per limited partner unit		$	0.63	$	0.53	$	0.55		$	(1.90	)	$	(0.18	)
	Diluted net income (loss) per limited partner unit		$	0.63	$	0.53	$	0.55		$	(1.90	)	$	(0.18	)
	The three months ended December 31, 2013 was impacted by ETP’s recognition of a goodwill impairment of $689 million. For the three months ended December 31, 2013, distributions paid for the period exceeded net income attributable to partners by $1.12 billion. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.
			Quarter Ended
			31-Mar		30-Jun		September 30			December 31			Total Year
	2012:00:00
	Revenues		$	1,323	$	1,596	$	1,802		$	10,981		$	15,702
	Gross profit		542		797		776			1,321			3,436
	Operating income		209		357		365			463			1,394
	Net income		1,088		135		64			361			1,648
	Limited Partners’ interest in net income (loss)		998		2		(80		)	188			1,108
	Basic net income (loss) per limited partner unit		$	4.36	$	0	$	(0.33	)	$	0.62		$	4.43
	Diluted net income (loss) per limited partner unit		$	4.35	$	0	$	(0.33	)	$	0.62		$	4.42
	For the three months ended September 30, 2012, distributions paid for the period exceeded net income attributable to partners by $356 million. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period. In addition, for the three months ended June 30, 2012 distributions paid for the period exceeded net income attributable to partners by $223 million. The allocation of the distributions in excess of net income is based on the proportionate ownership interests of the Limited Partners and General Partner. Based on this allocation approach, net income per Limited Partner unit (basic and diluted) for the three months ended June 30, 2012 was approximately zero, after taking into account distributions to be paid with respect to incentive distribution rights and employee unit awards.

Estimates_Significant_Accounti1

Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy)	12 Months Ended
	Dec. 31, 2013
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'
Use of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
	The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
	Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Revenue Recognition	'
	Revenue Recognition
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
	In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
	Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
	We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	In our 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.
	We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	Our retail marketing segment sells 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.
Regulatory Accounting - Regulatory Assets and Liabilities	'
	Regulatory Accounting – Regulatory Assets and Liabilities
	Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment 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 our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Southern Union recorded regulatory assets with respect to its distribution segment operations. At December 31, 2012, we had $123 million of regulatory assets included in the consolidated balance sheet as non-current assets held for sale. Southern Union’s distribution operations were sold in 2013.
Cash, Cash Equivalents and Supplemental Cash Flow Information	'
	Cash, Cash Equivalents and Supplemental Cash Flow Information
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
	We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable	'
	Accounts Receivable
	Our midstream, NGL and intrastate transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master setoff agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and intrastate transportation and storage operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.
	Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
	Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operations establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability.
	Our retail marketing segment extends credit to customers after a review of credit rating and other credit indicators.  Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable.  This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible.  The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability.
	We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories	'
	Inventories
	Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
	Inventories consisted of the following:
		December 31,
		2013			2012
	Natural gas and NGLs	$	519		$	334
	Crude oil	488			418
	Refined products	597			572
	Appliances, parts and fittings, and other	161			171
	Total inventories	$	1,765		$	1,495
	We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Exchanges	'
	Exchanges
	Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets	'
	Other Current Assets
	Other current assets consisted of the following:
		December 31,
		2013			2012
	Deposits paid to vendors	$	49		$	41
	Prepaid and other	261			293
	Total other current assets	$	310		$	334
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we 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 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 of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Advances to and Investment in Affiliates	'
	Advances to and Investments in Unconsolidated Affiliates
	We 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
	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 subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, NGL transportation and services, and retail marketing segments and all others. We recorded goodwill impairments for the periods presented in these consolidated financial statements.
Intangible Assets Disclosure [Text Block]	'
	Intangible Assets
	Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheet 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:
		31-Dec-13						31-Dec-12
		Gross Carrying			Accumulated			Gross Carrying		Accumulated
		Amount			Amortization			Amount		Amortization
	Amortizable intangible assets:
	Customer relationships, contracts and agreements (3 to 46 years)	$	1,393		$	(164	)	$	1,290	$	(80	)
	Patents (9 years)	48			(6		)	48		(1		)
	Other (10 to 15 years)	4			(1		)	4		(1		)
	Total amortizable intangible assets	$	1,445		$	(171	)	$	1,342	$	(82	)
	Non-amortizable intangible assets:
	Trademarks	294			—			301		—
	Total intangible assets	$	1,739		$	(171	)	$	1,643	$	(82	)
	Aggregate amortization expense of intangible assets was as follows:
		Years Ended December 31,
		2013			2012			2011
	Reported in depreciation and amortization	$	88		$	36		$	24
	Estimated aggregate amortization expense for the next five years is as follows:
	Years Ending December 31:
	2014		$	93
	2015		93
	2016		93
	2017		93
	2018		92
	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 Noncurrent Assets [Policy Text Block]	'
	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)	$	70		$	54
	Regulatory assets	86			87
	Deferred charges	144			140
	Restricted funds	378			—
	Other	88			76
	Total other non-current assets, net	$	766		$	357
	Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
Asset Retirement Obligation	'
	Asset Retirement Obligation
	We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
	An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate 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 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
	Accrued and other current liabilities consisted of the following:
		December 31,
		2013			2012
	Interest payable	$	294		$	256
	Customer advances and deposits	126			44
	Accrued capital expenditures	166			356
	Accrued wages and benefits	155			236
	Taxes payable other than income taxes	214			203
	Income taxes payable	3			40
	Deferred income taxes	119			130
	Other	351			297
	Total accrued and other current liabilities	$	1,428		$	1,562
	Deposits or advances are received from our 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 Costs, Policy [Policy Text Block]	'
	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, Policy [Policy Text Block]	'
	Fair Value of Financial Instruments
	The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
	Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2013 was $17.69 billion and $17.09 billion, respectively. As of December 31, 2012, the aggregate fair value and carrying amount of our debt obligations was $17.84 billion and $16.22 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
	We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of 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. During the period ended December 31, 2013, no transfers were made between any levels within the fair value hierarchy.
Contributions in Aid of Construction Costs	'
	Contributions in Aid of Construction Costs
	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	'
	ipping 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
	Cos
Costs and Expenses	'
	Costs and Expenses
	Costs of products sold include actual cost of fuel sold, adjusted for the effects of our 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 government authorities on a net basis except for our retail marketing segment 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).
Income Tax, Policy [Policy Text Block]	'
	Income Taxes
	ETP 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 most state 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 basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second 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, ETP 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	'
	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 our consolidated statements 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 statements 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, the 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 manage 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.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	'
	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 subsidiaries.
Allocation of Income (Loss)	'
	Allocation of Income
	For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

Estimates_Significant_Accounti2

Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables)	12 Months Ended
	Dec. 31, 2013
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'
Net change in operating assets and liabilities (net of acquisitions)	'
	The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows:
		Years Ended December 31,
		2013			2012			2011
	Accounts receivable	$	(458	)	$	300		$	3
	Accounts receivable from related companies	(17		)	(50		)	(28		)
	Inventories	(256		)	(253		)	68
	Exchanges receivable	(24		)	11			3
	Other current assets	(56		)	571			(62		)
	Other non-current assets, net	(22		)	(53		)	7
	Accounts payable	525			(979		)	31
	Accounts payable to related companies	(122		)	100			6
	Exchanges payable	131			—			3
	Accrued and other current liabilities	152			(151		)	60
	Other non-current liabilities	151			25			—
	Price risk management assets and liabilities, net	(150		)	4			75
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(146	)	$	(475	)	$	166
Non-cash investing and financing activities and supplemental cash flow information	'
	Non-cash investing and financing activities and supplemental cash flow information are as follows:
		Years Ended December 31,
		2013			2012			2011
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	167		$	359		$	202
	AmeriGas limited partner interest received in exchange for contribution of Propane Business	$	—		$	1,123		$	—
	Regency common and Class F units received in exchange for contribution of SUGS	$	961		$	—		$	—
	NON-CASH FINANCING ACTIVITIES:
	Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—		$	6,658		$	4
	Issuance of Common Units in connection with acquisitions	$	—		$	2,295		$	3
	Issuance of Common Units in connection with the Holdco Acquisition	$	2,464		$	—		$	—
	Issuance of Class H Units	$	1,514		$	—		$	—
	Contributions receivable related to noncontrolling interest	$	13		$	23		$	—
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	903		$	678		$	476
	Cash paid for income taxes	$	57		$	22		$	24
Inventory	'
	Inventories consisted of the following:
		December 31,
		2013			2012
	Natural gas and NGLs	$	519		$	334
	Crude oil	488			418
	Refined products	597			572
	Appliances, parts and fittings, and other	161			171
	Total inventories	$	1,765		$	1,495
Other Current Assets	'
	Other current assets consisted of the following:
		December 31,
		2013			2012
	Deposits paid to vendors	$	49		$	41
	Prepaid and other	261			293
	Total other current assets	$	310		$	334
Components and useful lives of property, plant and equipment	'
	Components and useful lives of property, plant and equipment were as follows:
		December 31,
		2013			2012
	Land and improvements	$	878		$	551
	Buildings and improvements (5 to 45 years)	900			673
	Pipelines and equipment (5 to 83 years)	16,966			17,031
	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)	1,685			1,187
	Retail equipment (3 to 99 years)	450			258
	Vehicles (1 to 25 years)	124			135
	Right of way (20 to 83 years)	1,901			2,042
	Furniture and fixtures (2 to 25 years)	48			65
	Linepack	116			116
	Pad gas	52			58
	Other (1 to 48 years)	626			806
	Construction work-in-process	1,668			1,688
		28,430			27,412
	Less – Accumulated depreciation	(2,483		)	(1,639		)
	Property, plant and equipment, net	$	25,947		$	25,773
Depreciation expense	'We recognized the following amounts of depreciation expense for the periods presented: Years Ended December 31, 2013 2012 2011Depreciation expense(1)$944 $615 $380Capitalized interest, excluding AFUDC$43 $99 $11(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.
Changes in carrying amount of goodwill	'
	Changes in the carrying amount of goodwill were as follows:
		Intrastate			Interstate			Midstream			NGL Transportation and Services			Investment in Sunoco Logistics			Retail Marketing		All Other			Total
		Transportation			Transportation and Storage
		and Storage
	Balance, December 31, 2011	$	10		$	99		$	37		$	432		$	—		$	—	$	642		$	1,220
	Goodwill acquired	—			1,785			338			—			1,368			1,272		375			5,138
	Goodwill sold in deconsolidation of Propane Business	—			—			—			—			—			—		(619		)	(619		)
	Goodwill allocated to the disposal group	—			—			—			—			—			—		(133		)	(133		)
	Balance, December 31, 2012	10			1,884			375			432			1,368			1,272		265			5,606
	Goodwill acquired	—			—			—			—			—			156		—			156
	Goodwill disposed	—			—			(337		)	—			—			—		—			(337		)
	Goodwill impairment	—			(689		)	—			—			—			—		—			(689		)
	Other	—			—			(2		)	—			(22		)	17		—			(7		)
	Balance, December 31, 2013	$	10		$	1,195		$	36		$	432		$	1,346		$	1,445	$	265		$	4,729
Components and useful lives of intangibles assets	'
	Components and useful lives of intangible assets were as follows:
		31-Dec-13						31-Dec-12
		Gross Carrying			Accumulated			Gross Carrying			Accumulated
		Amount			Amortization			Amount			Amortization
	Amortizable intangible assets:
	Customer relationships, contracts and agreements (3 to 46 years)	$	1,393		$	(164	)	$	1,290		$	(80	)
	Patents (9 years)	48			(6		)	48			(1		)
	Other (10 to 15 years)	4			(1		)	4			(1		)
	Total amortizable intangible assets	$	1,445		$	(171	)	$	1,342		$	(82	)
	Non-amortizable intangible assets:
	Trademarks	294			—			301			—
	Total intangible assets	$	1,739		$	(171	)	$	1,643		$	(82	)
Amortization expense of intangible assets	'
	Aggregate amortization expense of intangible assets was as follows:
		Years Ended December 31,
		2013			2012			2011
	Reported in depreciation and amortization	$	88		$	36		$	24
Amortization expense, expected	'
	Estimated aggregate amortization expense for the next five years is as follows:
	Years Ending December 31:
	2014		$	93
	2015		93
	2016		93
	2017		93
	2018		92
Other non-current assets	'
	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)	$	70		$	54
	Regulatory assets	86			87
	Deferred charges	144			140
	Restricted funds	378			—
	Other	88			76
	Total other non-current assets, net	$	766		$	357
Schedule of Asset Retirement Obligations [Table Text Block]	'
	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
Accounts payable and accrued liabilities	'
	Accrued and other current liabilities consisted of the following:
		December 31,
		2013			2012
	Interest payable	$	294		$	256
	Customer advances and deposits	126			44
	Accrued capital expenditures	166			356
	Accrued wages and benefits	155			236
	Taxes payable other than income taxes	214			203
	Income taxes payable	3			40
	Deferred income taxes	119			130
	Other	351			297
	Total accrued and other current liabilities	$	1,428		$	1,562
Summary of fair value of financials	'
	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 Total			Fair Value Measurements at December 31, 2013
					Level 1			Level 2
	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	201			201			—
	Power:
	Forwards	3			—			3
	Natural Gas Liquids – Forwards/Swaps	5			5			—
	Refined Products – Futures	5			5			—
	Total commodity derivatives	227			217			10
	Total assets	$	274		$	217		$	57
	Liabilities:
	Interest rate derivatives	$	(95	)	$	—		$	(95	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(4		)	(4		)	—
	Swing Swaps IFERC	(6		)	—			(6		)
	Fixed Swaps/Futures	(201		)	(201		)	—
	Forward Physical Swaps	(1		)	—			(1		)
	Power:
	Forwards	(1		)	—			(1		)
	Natural Gas Liquids – Forwards/Swaps	(5		)	(5		)	—
	Refined Products – Futures	(5		)	(5		)	—
	Total commodity derivatives	(223		)	(215		)	(8		)
	Total liabilities	$	(318	)	$	(215	)	$	(103	)
		Fair Value			Fair Value Measurements at December 31, 2012
		Total			Level 1			Level 2
	Assets:
	Interest rate derivatives	$	55		$	—		$	55
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	11			11			—
	Swing Swaps IFERC	3			—			3
	Fixed Swaps/Futures	96			94			2
	Options – Puts	1			—			1
	Options – Calls	3			—			3
	Forward Physical Swaps	1			—			1
	Power:
	Forwards	27			—			27
	Futures	1			1			—
	Options – Calls	2			—			2
	Natural Gas Liquids – Swaps	1			1			—
	Refined Products – Futures	5			1			4
	Total commodity derivatives	151			108			43
	Total assets	$	206		$	108		$	98
	Liabilities:
	Interest rate derivatives	$	(223	)	$	—		$	(223	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(18		)	(18		)	—
	Swing Swaps IFERC	(2		)	—			(2		)
	Fixed Swaps/Futures	(103		)	(94		)	(9		)
	Options – Puts	(1		)	—			(1		)
	Options – Calls	(3		)	—			(3		)
	Power:
	Forwards	(27		)	—			(27		)
	Futures	(2		)	(2		)	—
	Natural Gas Liquids – Swaps	(3		)	(3		)	—
Refined Products – Futures	(8		)	(1		)	(7		)
Total commodity derivatives	(167		)	(118		)	(49		)
Total liabilities	$	(390	)	$	(118	)	$	(272	)
Shipping and handling costs	'
	Shipping and Handling Costs
	Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and are as follows:
		Years Ended December 31,
		2013			2012			2011
	Shipping and handling costs – recorded in operating expenses	$	28		$	25		$	40

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Summary Of Preliminary Assets And Liability Acquired	'
	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.
Selected Financial Data related To Southern Unions Discontinued Operations [Table Text Block]	'
	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 income of discontinued operations, excluding effect of taxes and overhead allocations	65		43
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	$	39,136	$	36,169
	Net income	1,133		1,027
	Net income attributable to partners	788		745
	Basic net income per Limited Partner unit	$	1.33	$	1.24
	Diluted net income per Limited Partner unit	$	1.33	$	1.24

Investments_in_Unconsolidated_1

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2013
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]	'
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	'
	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, FEP, AmeriGas, Citrus and Regency (on a 100% basis) for all periods presented:
		December 31,
		2013		2012
	Current assets	$	1,372	$	878
	Property, plant and equipment, net	12,320		8,063
	Other assets	6,478		2,529
	Total assets	$	20,170	$	11,470
	Current liabilities	$	1,455	$	1,605
	Non-current liabilities	10,286		6,143
	Equity	8,429		3,722
	Total liabilities and equity	$	20,170	$	11,470
		Years Ended December 31,
		2013		2012		2011
	Revenue	$	6,806	$	4,057	$	3,337
	Operating income	1,043		635		681
	Net income	574		338		341
	In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Unit, Basic and Diluted	'
	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	$	735		$	1,757		$	700
	Less: Income from continuing operations attributable to noncontrolling interest	296			62			28
	Income from continuing operations, net of noncontrolling interest	439			1,695			672
	General Partner’s interest in income from continuing operations	505			463			433
	Limited Partners’ interest in income (loss) from continuing operations	(66		)	1,232			239
	Additional earnings allocated (to) from General Partner	(2		)	1			1
	Distributions on employee unit awards, net of allocation to General Partner	(10		)	(9		)	(8		)
	Income (loss) from continuing operations available to Limited Partners	$	(78	)	$	1,224		$	232
	Weighted average Limited Partner units – basic	343.4			248.3			207.2
	Basic income (loss) from continuing operations per Limited Partner unit	$	(0.23	)	$	4.93		$	1.12
	Dilutive effect of unvested Unit Awards	—			0.7			0.9
	Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	343.4			249			208.1
	Diluted income (loss) from continuing operations per Limited Partner unit	$	(0.23	)	$	4.91		$	1.12
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.05		$	(0.50	)	$	(0.02	)
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.05		$	(0.50	)	$	(0.02	)

Debt_Obligations_Tables

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Obligations [Abstract]	'
Debt instruments	'
	Our debt obligations consist of the following:
		December 31,
		2013			2012
	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
	6.50% 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
	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
	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
	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
	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
Note Payable to ETE	—			166
Other	228			32
	17,088			16,217
Less: current maturities	637			609
	$	16,451		$	15,608
Future maturities of long-term debt	'
	The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $308 million in unamortized net premiums and fair value adjustments:
	2014		$	812
	2015		1,047
	2016		375
	2017		1,220
	2018		1,205
	Thereafter		12,121
	Total		$	16,780

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]	'
	Following is a summary of the net amounts by which these incentive distribution relinquishments and incremental distributions on Class H Units would reduce the total distributions that would potentially be made to ETE in future quarters:
			Quarters Ending
			31-Mar				30-Jun			30-Sep		31-Dec		Total Year
	2014		$	26.5			$	26.5		$	26.5	$	26.5	$	106
	2015		12.5				12.5			13		13		51
	2016		18				18			18		18		72
	2017		12.5				12.5			12.5		12.5		50
	2018		11.25				11.25			11.25		11.25		45
	2019		8.75				8.75			8.75		8.75		35
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	Distributions declared during the periods presented below are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Rate
	31-Dec-10		7-Feb-11		14-Feb-11		$	0.89375
	31-Mar-11		6-May-11		16-May-11		0.89375
	30-Jun-11		5-Aug-11		15-Aug-11		0.89375
	30-Sep-11		4-Nov-11		14-Nov-11		0.89375
	31-Dec-11		7-Feb-12		14-Feb-12		0.89375
	31-Mar-12		4-May-12		15-May-12		0.89375
	30-Jun-12		6-Aug-12		14-Aug-12		0.89375
	30-Sep-12		6-Nov-12		14-Nov-12		0.89375
	31-Dec-12		7-Feb-13		14-Feb-13		0.89375
	31-Mar-13		6-May-13		15-May-13		0.89375
	30-Jun-13		5-Aug-13		14-Aug-13		0.89375
	30-Sep-13		4-Nov-13		14-Nov-13		0.905
	31-Dec-13		7-Feb-14		14-Feb-14		0.92
Schedule of Capital Units [Table Text Block]	'
	The change in Common Units was as follows:
		Years Ended December 31,
		2013			2012			2011
	Number of Common Units, beginning of period	301.5			225.5			193.2
	Common Units issued in connection with public offerings	13.8			15.5			29.4
	Common Units issued in connection with certain acquisitions	49.5			57.4			0.1
	Common Units redeemed for Class H Units	(50.2	)		—			—
	Common Units issued in connection with the Distribution Reinvestment Plan	2.3			1			0.4
	Common Units issued in connection with Equity Distribution Agreements	16.9			1.6			2
	Repurchases of Common Units in open-market transactions	(0.4	)		—			—
	Issuance of Common Units under equity incentive plans	0.4			0.5			0.4
	Number of Common Units, end of period	333.8			301.5			225.5
Net Proceeds From Sale Of Units [Text Block]	'
	The following table summarizes our public offerings of Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
	Date		Number of Common Units			Price per Unit			Net Proceeds
	Apr-11		14.2			$	50.52		$	695
	Nov-11		15.2			44.67			660
	Jul-12		15.5			44.57			671
	Apr-13		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.
Comprehensive Income (Loss) Note [Text Block]	'
	The following table presents the components of AOCI, net of tax:
		December 31,
		2013				2012
	Available-for-sale securities	$	2			$	—
	Foreign currency translation adjustment	(1		)		—
	Net loss on commodity related hedges	(4		)		—
	Actuarial gain (loss) related to pensions and other postretirement benefits	56				(10		)
	Equity investments, net	8				(9		)
	Subtotal	61				(19		)
	Amounts attributable to noncontrolling interest	—				6
	Total AOCI, net of tax	$	61			$	(13	)
Schedule of taxes related to accumulated other comprehensive income [Table Text Block]	'
	The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:
		December 31,
		2013				2012
	Net gains on commodity related hedges	$	—			$	1
	Actuarial (gain) loss relating to pension and other postretirement benefits	(39		)		5
	Total	$	(39	)		$	6
Sunoco Logistics [Member]	'
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	Distributions declared during the periods presented below are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Rate
	December 31, 2012		February 8, 2013		February 14, 2013		$	0.545
	March 31, 2013		May 9, 2013		May 15, 2013		0.5725
	June 30, 2013		8-Aug-13		14-Aug-13		0.6
	September 30, 2013		8-Nov-13		14-Nov-13		0.63
	December 31, 2013		10-Feb-14		14-Feb-14		0.6625

UnitBased_Compensation_Plans_T

Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Deferred Compensation Arrangements [Abstract]	'
Activity of the awards granted to employees and non-employee directors	'
	The following table shows the activity of the awards granted to employees and non-employee directors:
		Number of Units		Weighted Average Grant-Date Fair Value Per 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_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
		Years Ended December 31,
		2013			2012			2011
	Current expense (benefit):
	Federal	$	51		$	(3	)	$	(1	)
	State	(2		)	4			16
	Total	49			1			15
	Deferred expense:
	Federal	(6		)	45			4
	State	54			17			—
	Total	48			62			4
	Total income tax expense from continuing operations	$	97		$	63		$	19
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	(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:
		31-Dec-13									31-Dec-12
		Corporate Subsidiaries(1)			Partnership(2)			Consolidated			Corporate Subsidiaries(1)		Partnership(2)		Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	(166	)	$	—		$	(166	)	$	1	$	—	$	1
	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			5			36			9		7		16
	Other	(13		)	(1		)	(14		)	18		—		18
	Income tax from continuing operations	$	93		$	4		$	97		$	56	$	7	$	63
	(1)	Includes Holdco, Oasis Pipeline Company, 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 ETP and its 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		$	268
	Pension and other postretirement benefits	57			127
	Long term debt	108			117
	Other	104			288
	Total deferred income tax assets	486			800
	Valuation allowance	(74		)	(90		)
	Net deferred income tax assets	$	412		$	710
	Deferred income tax liabilities:
	Properties, plants and equipment	$	(1,522	)	$	(1,938	)
	Inventory	(302		)	(516		)
	Investment in unconsolidated affiliates	(2,244		)	(1,542		)
	Trademarks	(180		)	(192		)
	Other	(45		)	(128		)
	Total deferred income tax liabilities	(4,293		)	(4,316		)
	Net deferred income tax liability	(3,881		)	(3,606		)
	Less: current portion of deferred income tax assets (liabilities)	(119		)	(130		)
	Accumulated deferred income taxes	$	(3,762	)	$	(3,476	)
Balance Sheet Classification of Deferred Taxes [Table Text Block]	'
	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	$	(3,606	)	$	(123	)
	Southern Union acquisition	—			(1,420		)
	Sunoco acquisition	—			(1,989		)
	SUGS Contribution to Regency	(115		)	—
	Tax provision (including discontinued operations)	(111		)	(73		)
	Other	(49		)	(1		)
	Net deferred income tax liability	$	(3,881	)	$	(3,606	)
Schedule of Unrecognized Tax Benefits Rollforward [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	—			—			(1		)
	Lapse of statute	(4		)	(3		)	—
	Balance at end of year	$	429		$	27		$	2

Regulatory_Matters_Commitments1

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables)	12 Months Ended
	Dec. 31, 2013
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
Future Minimum Lease Commitments	'
	Future minimum lease commitments for such leases are:
	Years Ending December 31:
	2014	$	80
	2015	78
	2016	70
	2017	66
	2018	53
	Thereafter	420
	Future minimum lease commitments	767
	Less: Sublease rental income	(57		)
	Net future minimum lease commitments	$	710
Environmental Exit Costs by Cost [Table Text Block]	'
	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
		December 31,
		2013			2012
	Current	$	45		$	46
	Non-current	350			165
	Total environmental liabilities	$	395		$	211

Price_risk_management_assets_a1

Price risk management assets and liabilties (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]	'
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
				Years Ended December 31,
				2013				2012				2011
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	Cost of products sold		$	4			$	14			$	38
	Total			$	4			$	14			$	38
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	'
		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
				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
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	'
		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain (Loss) Recognized in Income on Derivatives
				Years Ended December 31,
				2013				2012				2011
	Derivatives not designated as hedging instruments:
	Commodity derivatives – Trading	Cost of products sold		$	(11	)		$	(7	)		$	(30	)
	Commodity derivatives – Non-trading	Cost of products sold		(12		)		(15		)		9
	Commodity contracts – Non-trading	Deferred gas purchases		(3		)		(26		)		—
	Interest rate derivatives	Gains (losses) on interest rate derivatives		44				(4		)		(77		)
	Total			$	18			$	(52	)		$	(98	)
Outstanding commodity-related derivatives	'
	The following table details our outstanding commodity-related derivatives:
		31-Dec-13					31-Dec-12
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	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.
Interest rate swaps outstanding	'
							Notional Amount Outstanding
	Entity		Term		Type(1)		31-Dec-13				31-Dec-12
	ETP		July 2013(2)		Forward-starting to pay a fixed rate of 4.03% and receive a floating rate		$	—			$	400
	ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		400				400
	ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				600
	ETP		Jun-21		Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%		400				—
	ETP		Feb-23		Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		400				—
	Southern Union(3)		Nov-16		Pay a fixed rate of 2.97% and receive a floating rate		—				75
	Southern Union(3)		Nov-21		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 termination date the same as the effective date. During the year ended December 31, 2013, we 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.
Fair Value of derivative instruments	'
	The following table provides a summary of our derivative assets and liabilities:
		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		31-Dec-13				31-Dec-12				31-Dec-13				31-Dec-12
	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	39				33				(38		)		(34		)
	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		)		(223		)
		313				200				(342		)		(382		)
	Total derivatives	$	316			$	208			$	(360	)		$	(392	)
Offsetting Assets Table Text Block [Table Text Block]	'
	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
					Asset Derivatives								Liability Derivatives
			Balance Sheet Location		December 31, 2013				December 31, 2012				December 31, 2013				December 31, 2012
	Derivatives in offsetting agreements:
	OTC contracts		Price risk management assets (liabilities)		$	41			$	28			$	(38	)		$	(27	)
	Broker cleared derivative contracts		Other current assets (liabilities)		265				150				(318		)		(228		)
					306				178				(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				153				(265		)		(169		)
	Derivatives without offsetting agreements				47				55				(95		)		(223		)
	Total derivatives				$	316			$	208			$	(360	)		$	(392	)
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]	'
		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			$	19
	Total	$	(1	)		$	8			$	19

Retirement_Benefits_Retirement

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]	'
	The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
		31-Dec-13												31-Dec-12
		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:
		31-Dec-13											31-Dec-12
		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 Net Benefit Costs [Table Text Block]	'
	Components of Net Periodic Benefit Cost
		31-Dec-13								31-Dec-12
		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 operations.  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.
Schedule of Benefit Obligations Assumptions [Table Text Block]	'
	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
		31-Dec-13						31-Dec-12
		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:
		31-Dec-13						31-Dec-12
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Discount rate	3.5	%		2.68	%		2.37	%		2.43	%
	Expected return on assets:
	Tax exempt accounts	7.5	%		6.95	%		7.63	%		7	%
	Taxable accounts	N/A			4.42	%		N/A			4.5	%
	Rate of compensation increase	N/A			N/A			3.02	%		N/A
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	'
	The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union 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 Measurements at December 31, 2013 Using Fair Value Hierarchy
		Fair Value as of 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 Measurements at December 31, 2012 Using Fair Value Hierarchy
		Fair Value as of 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 other postretirement plan assets by asset category at the dates indicated is as follows:
						Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
		Fair Value as of 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 Measurements at December 31, 2012 Using Fair Value Hierarchy
		Fair Value as of 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.
	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.
Schedule of Expected Benefit Payments [Table Text Block]	'
	Southern Union 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

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Balances For Period Presented [Table Text Block]	'
	The following table summarizes the related company balances on our consolidated balance sheets:
		December 31,
		2013		2012
	Accounts receivable from related companies:
	ETE	$	18	$	16
	Regency	53		10
	PES	7		60
	FGT	29		2
	Eastern Gulf	24		—
	Other	34		6
	Total accounts receivable from related companies:	$	165	$	94
	Accounts payable to related companies:
	ETE	$	8	$	7
	Regency	24		2
	PES	—		13
	FGT	8		—
	Other	5		2
	Total accounts payable to related companies:	$	45	$	24
Schedule Of Related Party Transactions By Related Party [Table Text Block]	'
	The following table summarizes the affiliated revenues on our consolidated statements of operations:
		Years Ended December 31,
		2013		2012		2011
	Affiliated revenues	$	1,550	$	173	$	690

Reportable_Segments_Tables

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Reportable Segments [Abstract]	'
Reportable segments	'
	The following tables present the financial information by segment:
		Years Ended December 31,
		2013			2012			2011
	Revenues:
	Intrastate transportation and storage:
	Revenues from external customers	$	2,250		$	2,012		$	2,398
	Intersegment revenues	202			179			276
		2,452			2,191			2,674
	Interstate transportation and storage:
	Revenues from external customers	1,270			1,109			447
	Intersegment revenues	39			—			—
		1,309			1,109			447
	Midstream:
	Revenues from external customers	1,307			1,757			1,082
	Intersegment revenues	942			196			401
		2,249			1,953			1,483
	NGL transportation and services:
	Revenues from external customers	2,063			619			363
	Intersegment revenues	64			31			34
		2,127			650			397
	Investment in Sunoco Logistics:
	Revenues from external customers	16,480			3,109			—
	Intersegment revenues	159			80			—
		16,639			3,189			—
	Retail marketing:
	Revenues from external customers	21,004			5,926			—
	Intersegment revenues	8			—			—
		21,012			5,926			—
	All other:
	Revenues from external customers	1,965			1,170			2,509
	Intersegment revenues	402			385			379
		2,367			1,555			2,888
	Eliminations	(1,816		)	(871		)	(1,090		)
	Total revenues	$	46,339		$	15,702		$	6,799
		Years Ended December 31,
		2013			2012			2011
	Cost of products sold:
	Intrastate transportation and storage	$	1,737		$	1,394		$	1,774
	Midstream	1,579			1,273			988
	NGL transportation and services	1,655			361			218
	Investment in Sunoco Logistics	15,574			2,885			—
	Retail marketing	20,150			5,757			—
	All other	2,309			1,496			2,274
	Eliminations	(1,800		)	(900		)	(1,079		)
	Total cost of products sold	$	41,204		$	12,266		$	4,175
		Years Ended December 31,
		2013			2012			2011
	Depreciation and amortization:
	Intrastate transportation and storage	$	122		$	122		$	120
	Interstate transportation and storage	244			209			81
	Midstream	172			168			85
	NGL transportation and services	91			53			32
	Investment in Sunoco Logistics	265			63			—
	Retail marketing	114			28			—
	All other	24			13			87
	Total depreciation and amortization	$	1,032		$	656		$	405
		Years Ended December 31,
		2013			2012			2011
	Equity in earnings (losses) of unconsolidated affiliates:
	Intrastate transportation and storage	$	—		$	4		$	2
	Interstate transportation and storage	142			120			24
	Midstream	—			(9		)	—
	NGL transportation and services	(2		)	2			—
Investment in Sunoco Logistics	18			5			—
Retail marketing	2			1			—
All other	12			19			—
Total equity in earnings of unconsolidated affiliates	$	172		$	142		$	26
	Years Ended December 31,
	2013			2012			2011
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	464		$	601		$	667
Interstate transportation and storage	1,269			1,013			373
Midstream	479			467			421
NGL transportation and services	351			209			127
Investment in Sunoco Logistics	871			219			—
Retail marketing	325			109			—
All other	194			126			193
Total Segment Adjusted EBITDA	3,953			2,744			1,781
Depreciation and amortization	(1,032		)	(656		)	(405		)
Interest expense, net of interest capitalized	(849		)	(665		)	(474		)
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	44			(4		)	(77		)
Non-cash unit-based compensation expense	(47		)	(42		)	(38		)
Unrealized gains (losses) on commodity risk management activities	51			(9		)	(11		)
LIFO valuation adjustments	3			(75		)	—
Loss on extinguishment of debt	—			(115		)	—
Non-operating environmental remediation	(168		)	—			—
Adjusted EBITDA related to discontinued operations	(76		)	(99		)	(23		)
Adjusted EBITDA related to unconsolidated affiliates	(629		)	(480		)	(56		)
Equity in earnings of unconsolidated affiliates	172			142			26
Other, net	12			22			(4		)
Income from continuing operations before income tax expense	$	832		$	1,820		$	719
	December 31,
	2013			2012			2011
Total assets:
Intrastate transportation and storage	$	4,606		$	4,691		$	4,785
Interstate transportation and storage	10,988			11,794			3,661
Midstream	3,133			4,946			2,513
NGL transportation and services	4,326			3,765			2,360
Investment in Sunoco Logistics	11,650			10,291			—
Retail marketing	3,936			3,926			—
All other	5,063			3,817			2,200
Total	$	43,702		$	43,230		$	15,519
	Years Ended December 31,
	2013			2012			2011
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis):
Intrastate transportation and storage	$	47		$	37		$	53
Interstate transportation and storage	152			133			207
Midstream	565			1,317			837
NGL transportation and services	443			1,302			325
Investment in Sunoco Logistics	1,018			139			—
Retail marketing	176			58			—
All other	54			63			62
Total	$	2,455		$	3,049		$	1,484
	December 31,
	2013			2012			2011
Advances to and investments in unconsolidated affiliates:
Intrastate transportation and storage	$	1		$	2		$	1
Interstate transportation and storage	2,040			2,142			173
Midstream	—			1			—
NGL transportation and services	29			29			27
Investment in Sunoco Logistics	125			118			—
Retail marketing	22			21			—
All other	2,219			1,189			—
Total	$	4,436		$	3,502		$	201

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Schedule of Quarterly Financial Information [Table Text Block]	'
		Quarter Ended
		31-Mar		30-Jun		September 30			December 31			Total Year
	2013:00:00
	Revenues	$	10,854	$	11,551	$	11,902		$	12,032		$	46,339
	Gross profit	1,260		1,322		1,248			1,305			5,135
	Operating income (loss)	534		632		526			(151		)	1,541
	Net income (loss)	424		413		404			(473		)	768
	Limited Partners’ interest in net income (loss)	194		165		209			(666		)	(98		)
	Basic net income (loss) per limited partner unit	$	0.63	$	0.53	$	0.55		$	(1.90	)	$	(0.18	)
	Diluted net income (loss) per limited partner unit	$	0.63	$	0.53	$	0.55		$	(1.90	)	$	(0.18	)
	The three months ended December 31, 2013 was impacted by ETP’s recognition of a goodwill impairment of $689 million. For the three months ended December 31, 2013, distributions paid for the period exceeded net income attributable to partners by $1.12 billion. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.
		Quarter Ended
		31-Mar		30-Jun		September 30			December 31			Total Year
	2012:00:00
	Revenues	$	1,323	$	1,596	$	1,802		$	10,981		$	15,702
	Gross profit	542		797		776			1,321			3,436
	Operating income	209		357		365			463			1,394
	Net income	1,088		135		64			361			1,648
	Limited Partners’ interest in net income (loss)	998		2		(80		)	188			1,108
	Basic net income (loss) per limited partner unit	$	4.36	$	0	$	(0.33	)	$	0.62		$	4.43
	Diluted net income (loss) per limited partner unit	$	4.35	$	0	$	(0.33	)	$	0.62		$	4.42

Operations_and_Organization_Na

Operations and Organization (Narrative) (Details) (USD $)	12 Months Ended				1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Apr. 30, 2013	Oct. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
	Lone Star L.L.C. [Member]	FEP [Member]	Citrus [Member]	ETE [Member]	Canyon Disposal [Member]	Fayetteville Express Pipeline, LLC [Member]	Citrus Corp [Member]
					Canyon [Member]	FEP [Member]	Citrus [Member]
Business Combination, Consideration Transferred	'	'	'	'	$207	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%	50.00%	50.00%	'	'	100.00%	100.00%
Equity interest in Holdco	'	'	'	60.00%	'	'	'

Estimates_Significant_Accounti3

Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets	'	$123,000,000	'
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	'	128,000,000	'
Goodwill impairment	689,000,000	0	0
Net increase in goodwill	-877,000,000	'	'
Goodwill, Written off Related to Sale of Business Unit	337,000,000	619,000,000	'
Long-term Debt, Fair Value	17,690,000,000	17,840,000,000	'
Goodwill acquired	156,000,000	5,138,000,000	'
GOODWILL	4,729,000,000	5,606,000,000	1,220,000,000
Long-term Debt	17,088,000,000	16,220,000,000	'
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member]	'	'	'
Useful Lives	'3 years	'	'
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member]	'	'	'
Useful Lives	'46 years	'	'
Maximum [Member] | Patents [Member]	'	'	'
Useful Lives	'9 years	'	'
Canyon [Member]	'	'	'
Depreciation and Amortization, Discontinued Operations	'	'	26,000,000
Interstate Transportation and Storage [Member]	'	'	'
Goodwill impairment	689,000,000	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Goodwill acquired	0	1,785,000,000	'
GOODWILL	1,195,000,000	1,884,000,000	99,000,000
Midstream [Member]	'	'	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	337,000,000	0	'
Goodwill acquired	0	338,000,000	'
GOODWILL	36,000,000	375,000,000	37,000,000
Retail Marketing [Member]	'	'	'
Excise Taxes Collected	2,220,000,000	573,000,000	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Goodwill acquired	156,000,000	1,272,000,000	'
GOODWILL	1,445,000,000	1,272,000,000	0
Trunkline LNG [Member]	'	'	'
GOODWILL	$873,000,000	$184,000,000	'

Estimates_Significant_Accounti4

Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'	'	'
Accounts receivable	($458)	$300	$3
Accounts receivable from related companies	-17	-50	-28
Inventories	-256	-253	68
Exchanges receivable	-24	11	3
Other current assets	-56	571	-62
Other non-current assets, net	-22	-53	7
Accounts payable	525	-979	31
Accounts payable to related companies	-122	100	6
Exchanges payable	131	0	3
Accrued and other current liabilities	152	-151	60
Other non-current liabilities	-49	-1	'
Increase (Decrease) in Other Noncurrent Liabilities	151	25	0
Price risk management assets and liabilities, net	-150	4	75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	($146)	($475)	$166

Estimates_Significant_Accounti5

Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Noncash Investing and Financing Activities [Abstract]	'	'	'
Accrued capital expenditures	$167	$359	$202
Issuance of Common Units in connection with acquisitions	0	2,295	3
Contributions received related to noncontrolling interest	13	23	0
Supplemental Cash Flow Information [Abstract]	'	'	'
Cash paid for interest, net of interest capitalized	903	678	476
Cash paid for income taxes	57	22	24
Limited Partner Common Unitholders [Member]	'	'	'
Noncash Investing and Financing Activities [Abstract]	'	'	'
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	0	6,658	4
ETP's Propane Operations [Member]	'	'	'
Noncash Investing and Financing Activities [Abstract]	'	'	'
AmeriGas limited partner interest received in exchange for contribution of Propane Business	0	1,123	0
SUGS [Member]	'	'	'
Noncash Investing and Financing Activities [Abstract]	'	'	'
AmeriGas limited partner interest received in exchange for contribution of Propane Business	961	0	0
Holdco Acquisition [Member]	'	'	'
Noncash Investing and Financing Activities [Abstract]	'	'	'
Issuance of Common Units in connection with acquisitions	2,464	0	0
Class F Units [Member]	'	'	'
Noncash Investing and Financing Activities [Abstract]	'	'	'
Issuance of Common Units in connection with acquisitions	$1,514	$0	$0

Estimates_Significant_Accounti6

Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'	'
Natural gas and NGLs	$519	$334
Crude oil	488	418
Inventory, refined products	597	572
Appliances, parts and fittings, and other	161	171
Total inventories	$1,765	$1,495

Estimates_Significant_Accounti7

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'	'
Deposits paid to vendors	$49	$41
Prepaid and other	261	293
Total other current assets	$310	$334

Estimates_Significant_Accounti8

Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Property, Plant and Equipment, Gross	$28,430		$27,412		'
Less - Accumulated depreciation	-2,483		-1,639		'
Property, plant and equipment, net	25,947		25,773		'
Depreciation expense(1)	944	[1]	615	[1]	380	[1]
Capitalized interest, excluding AFUDC	43		99		11
Land and Land Improvements [Member]	'		'		'
Property, Plant and Equipment, Gross	878		551		'
Building and Building Improvements [Member]	'		'		'
Property, Plant and Equipment, Gross	900		673		'
Pipelines and equipment[Member]	'		'		'
Property, Plant and Equipment, Gross	16,966		17,031		'
Natural gas and NGL storage [Member]	'		'		'
Property, Plant and Equipment, Gross	1,083	[1]	1,057	[1]	'
Bulk Storage, equipment and facilities [Member]	'		'		'
Property, Plant and Equipment, Gross	1,933		1,745		'
Tanks and other equipment [Member]	'		'		'
Property, Plant and Equipment, Gross	1,685		1,187		'
Retail Equipment [Member]	'		'		'
Property, Plant and Equipment, Gross	450		258		'
Vehicles [Member]	'		'		'
Property, Plant and Equipment, Gross	124		135		'
Right of way [Member]	'		'		'
Property, Plant and Equipment, Gross	1,901		2,042		'
Furniture and fixtures [Member]	'		'		'
Property, Plant and Equipment, Gross	48		65		'
Linepack [Member]	'		'		'
Property, Plant and Equipment, Gross	116		116		'
Pad gas [Member]	'		'		'
Property, Plant and Equipment, Gross	52		58		'
Property, Plant and Equipment, Other Types [Member]	'		'		'
Property, Plant and Equipment, Gross	626		806		'
Construction Work-In-Process [Member]	'		'		'
Property, Plant and Equipment, Gross	$1,668		$1,688		'
Minimum [Member] | Building and Building Improvements [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'5 years		'		'
Minimum [Member] | Pipelines and equipment[Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'5 years		'		'
Minimum [Member] | Natural gas and NGL storage [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'5 years		'		'
Minimum [Member] | Bulk Storage, equipment and facilities [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'2 years		'		'
Minimum [Member] | Tanks and other equipment [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'5 years		'		'
Minimum [Member] | Retail Facilities [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'3 years		'		'
Minimum [Member] | Vehicles [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'1 year		'		'
Minimum [Member] | Right of way [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'20 years		'		'
Minimum [Member] | Furniture and fixtures [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'2 years		'		'
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'1 year		'		'
Maximum [Member] | Building and Building Improvements [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'45 years		'		'
Maximum [Member] | Pipelines and equipment[Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'83 years		'		'
Maximum [Member] | Natural gas and NGL storage [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'46 years		'		'
Maximum [Member] | Bulk Storage, equipment and facilities [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'83 years		'		'
Maximum [Member] | Tanks and other equipment [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'40 years		'		'
Maximum [Member] | Retail Facilities [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'99 years		'		'
Maximum [Member] | Vehicles [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'25 years		'		'
Maximum [Member] | Right of way [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'83 years		'		'
Maximum [Member] | Furniture and fixtures [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'25 years		'		'
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]	'		'		'
Property, plant and equipment useful life, minimum in years	'48 years		'		'
[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_Significant_Accounti9

Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'		'		'
Depreciation expense(1)	$944	[1]	$615	[1]	$380	[1]
Capitalized interest, excluding AFUDC	$43		$99		$11
[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.

Recovered_Sheet1

Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill, Beginning Balance	$5,606	$1,220	'
Goodwill acquired	156	5,138	'
Goodwill impairment	-689	0	0
Goodwill, Written off Related to Sale of Business Unit	-337	-619	'
Other	-7	-133	'
Goodwill, Ending Balance	4,729	5,606	1,220
Intrastate Transportation And Storage [Member]	'	'	'
Goodwill, Beginning Balance	10	10	'
Goodwill acquired	0	0	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Other	0	0	'
Goodwill, Ending Balance	10	10	'
Interstate Transportation and Storage [Member]	'	'	'
Goodwill, Beginning Balance	1,884	99	'
Goodwill acquired	0	1,785	'
Goodwill impairment	-689	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Other	0	0	'
Goodwill, Ending Balance	1,195	1,884	99
Midstream [Member]	'	'	'
Goodwill, Beginning Balance	375	37	'
Goodwill acquired	0	338	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	-337	0	'
Other	-2	0	'
Goodwill, Ending Balance	36	375	'
NGL Transportation And Services [Member]	'	'	'
Goodwill, Beginning Balance	432	432	'
Goodwill acquired	0	0	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Other	0	0	'
Goodwill, Ending Balance	432	432	'
Retail Marketing [Member]	'	'	'
Goodwill, Beginning Balance	1,272	0	'
Goodwill acquired	156	1,272	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Other	17	0	'
Goodwill, Ending Balance	1,445	1,272	'
Investment in Sunoco Logistics [Member]	'	'	'
Goodwill, Beginning Balance	1,368	0	'
Goodwill acquired	0	1,368	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	0	'
Other	-22	0	'
Goodwill, Ending Balance	1,346	1,368	'
Other Segments [Member]	'	'	'
Goodwill, Beginning Balance	265	642	'
Goodwill acquired	0	375	'
Goodwill impairment	0	'	'
Goodwill, Written off Related to Sale of Business Unit	0	-619	'
Other	0	-133	'
Goodwill, Ending Balance	$265	$265	'

Recovered_Sheet2

Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Customer relationships, contracts and agreements (3 to 46 years) [Member]	'	'	'
Gross Carrying Amount	$1,393	$1,290	'
Accumulated Amortization	-164	-80	'
Patents (9 years) [Member]	'	'	'
Gross Carrying Amount	48	48	'
Accumulated Amortization	-6	-1	'
Other (10 to 15 years) [Member]	'	'	'
Gross Carrying Amount	4	4	'
Accumulated Amortization	-1	-1	'
Total Amortizable Intangible Assets [Member]	'	'	'
Gross Carrying Amount	1,445	1,342	'
Accumulated Amortization	-171	-82	'
Non-amortizable intangible assets - Trademarks [Member]	'	'	'
Gross Carrying Amount	294	301	'
Accumulated Amortization	0	0	'
Total intangible assets [Member]	'	'	'
Gross Carrying Amount	1,739	1,643	'
Accumulated Amortization	-171	-82	'
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member]	'	'	'
Useful Lives	'46 years	'	'
Maximum [Member] | Patents (9 years) [Member]	'	'	'
Useful Lives	'9 years	'	'
Maximum [Member] | Other (10 to 15 years) [Member]	'	'	'
Useful Lives	'15 years	'	'
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member]	'	'	'
Useful Lives	'3 years	'	'
Minimum [Member] | Other (10 to 15 years) [Member]	'	'	'
Useful Lives	'10 years	'	'
Depreciation And Amortization [Member]	'	'	'
Amortization of Intangible Assets	$88	$36	$24

Recovered_Sheet3

Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'
2014	$93
2015	93
2016	93
2017	93
2018	$92

Recovered_Sheet4

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified			Minimum [Member]	Maximum [Member]
			Financing Costs (3 to 30 years) [Member]	Financing Costs (3 to 30 years) [Member]
Unamortized financing costs (3 to 30 years)	$70	$54	'	'
Regulatory assets	86	87	'	'
Deferred Costs, Noncurrent	144	140	'	'
Restricted Cash and Investments, Noncurrent	378	0	'	'
Other	88	76	'	'
Total other non-current assets, net	$766	$357	'	'
Finite-Lived Intangible Assets, Useful Life, Minimum	'	'	'3 years	'30 years

Recovered_Sheet5

Estimates, Significant Accounting Policies and Balance Sheet Detials (Asset Retirement Obligations) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
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

Recovered_Sheet6

Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'	'
Interest payable	$294	$256
Customer advances and deposits	126	44
Accrued capital expenditures	166	356
Accrued wages and benefits	155	236
Taxes payable other than income taxes	214	203
Taxes Payable, Current	3	40
Income taxes payable	119	130
Other	351	297
Total accrued and other current liabilities	$1,428	$1,562

Recovered_Sheet7

Estimates, Significant Accounting Policies and Balance Sheet Detials (Assets and liabilities measured and recorded at fair value on a recurring basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Long-term Debt	$17,088	$16,220
Fair Value, Measurements, Recurring [Member]	'	'
Interest rate derivatives, Assets	47	55
Price Risk Derivative Assets, at Fair Value	227	151
Assets, Fair Value Disclosure	274	206
Interest rate derivatives, Liabilities	-95	-223
Price Risk Derivative Liabilities, at Fair Value	-223	-167
Liabilities, Fair Value Disclosure, Recurring	318	390
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	1
Price Risk Derivative Liabilities, at Fair Value	-5	-3
Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	5
Price Risk Derivative Liabilities, at Fair Value	-5	-8
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	3	27
Price Risk Derivative Liabilities, at Fair Value	-1	-27
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	'	-2
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	-1	'
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	11
Price Risk Derivative Liabilities, at Fair Value	-4	-18
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	8	3
Price Risk Derivative Liabilities, at Fair Value	-6	-2
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	201	96
Price Risk Derivative Liabilities, at Fair Value	-201	-103
Fixed Swaps Futures [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	'
Put Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	'	-1
Call Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	3
Price Risk Derivative Liabilities, at Fair Value	'	-3
Call Option [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	2
Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Interest rate derivatives, Assets	0	0
Price Risk Derivative Assets, at Fair Value	217	108
Assets, Fair Value Disclosure	217	108
Interest rate derivatives, Liabilities	0	0
Price Risk Derivative Liabilities, at Fair Value	-215	-118
Liabilities, Fair Value Disclosure, Recurring	215	118
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	1
Price Risk Derivative Liabilities, at Fair Value	-5	-3
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	-5	-1
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	'	-2
Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	0
Price Risk Derivative Liabilities, at Fair Value	0	'
Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	11
Price Risk Derivative Liabilities, at Fair Value	-4	-18
Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	1	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	201	94
Price Risk Derivative Liabilities, at Fair Value	-201	-94
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	5	'
Fair Value, Inputs, Level 1 [Member] | Put Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	0
Price Risk Derivative Liabilities, at Fair Value	'	0
Fair Value, Inputs, Level 1 [Member] | Call Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	0
Price Risk Derivative Liabilities, at Fair Value	'	0
Fair Value, Inputs, Level 1 [Member] | Call Option [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	0
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Interest rate derivatives, Assets	47	55
Price Risk Derivative Assets, at Fair Value	10	43
Assets, Fair Value Disclosure	57	98
Interest rate derivatives, Liabilities	-95	-223
Price Risk Derivative Liabilities, at Fair Value	-8	-49
Liabilities, Fair Value Disclosure, Recurring	103	272
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	4
Price Risk Derivative Liabilities, at Fair Value	0	-7
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	3	27
Price Risk Derivative Liabilities, at Fair Value	-1	-27
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	0
Price Risk Derivative Liabilities, at Fair Value	'	0
Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	-1	'
Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	7	3
Price Risk Derivative Liabilities, at Fair Value	-6	-2
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	0	2
Price Risk Derivative Liabilities, at Fair Value	0	-9
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	0	'
Fair Value, Inputs, Level 2 [Member] | Put Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	1
Price Risk Derivative Liabilities, at Fair Value	'	-1
Fair Value, Inputs, Level 2 [Member] | Call Option [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	3
Price Risk Derivative Liabilities, at Fair Value	'	-3
Fair Value, Inputs, Level 2 [Member] | Call Option [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Price Risk Derivative Assets, at Fair Value	'	$2

Recovered_Sheet8

Estimates, Significant Accounting Policies and Balance Sheet Detials (Shipping and Handling Costs) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL	'	'	'
Shipping and handling costs - recorded in operating expenses	$28	$25	$40

Recovered_Sheet9

Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) (Retail Marketing [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Retail Marketing [Member]	'	'
Excise Taxes Collected	$2,220	$573

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures (2013 Narrative) (Details) (USD $)

0 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 30, 2013

Apr. 30, 2013

Apr. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2012

Oct. 05, 2012

Dec. 31, 2013

Oct. 05, 2012

Apr. 30, 2013

Apr. 30, 2013

Apr. 30, 2013

Feb. 28, 2014

SUGS Contribution [Member]

Holdco Transaction [Member]

Holdco Transaction [Member]

Missouri Gas Energy [Member]

New England Gas Company [Member]

AmeriGas [Member]

AmeriGas [Member]

ETP [Member]

ETP [Member]

Parent Company [Member]

Parent Company [Member]

Common Units [Member]

Class F Units [Member]

Trunkline LNG Transaction [Member]

Common Units [Member]

Propane Cylinder Exchange Business [Member]

Holdco Transaction [Member]

Holdco Transaction [Member]

Regency [Member]

Regency [Member]

SUGS Contribution [Member]

SUGS Contribution [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior note interest rate

'

4.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Relinquishment of Rights of Incentive Distributions, Percentage

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

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

2.2

'

'

'

'

'

49.5

'

'

'

'

'

'

'

'

31.4

6.3

'

Guarantor Obligations, Current Carrying Value

'

$600

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Businesses

'

'

'

'

'

'

'

975

40

'

43

'

'

'

'

'

'

'

Noncash or Part Noncash Divestiture, Amount of Consideration Received

'

'

'

'

'

'

'

'

20

'

'

'

'

'

'

'

'

'

Business Acquisition Units Acquired

'

'

'

'

'

'

'

'

'

29.6

'

'

'

'

'

'

'

'

Business Combination, Consideration Transferred

'

'

'

'

463

1,400

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Closing Adjustments

'

'

'

'

'

68

'

'

'

'

'

'

'

'

'

'

'

'

Cash (paid) received from all other acquisitions

'

-405

531

-1,972

30

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interest in Holdco

'

'

'

'

'

'

'

'

'

'

'

40.00%

100.00%

60.00%

60.00%

'

'

'

Partners' Capital Account, Units, Redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18.7

Related Party Transaction, Expenses from Transactions with Related Party

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$75

Investments_in_Unconsolidated_2

Investments in Unconsolidated Affiliates (Narrative)(Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Share data in Millions, unless otherwise specified

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jan. 31, 2014

Dec. 31, 2013

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

FGT [Member]

AmeriGas [Member]

AmeriGas [Member]

SUG [Member]

SUG [Member]

Citrus Corp [Member]

Citrus [Member]

FEP [Member]

SUGS Contribution [Member]

Citrus Corp [Member]

FEP [Member]

FEP [Member]

Citrus [Member]

Citrus [Member]

AmeriGas [Member]

AmeriGas [Member]

Regency [Member]

years

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Schedule of Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Ownership Percentage

'

'

'

'

'

'

'

'

50.00%

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

Percentage Ownership Operating Facility

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Businesses, Gross

'

'

'

'

'

'

'

$1,900,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Business acquisition, cost of acquired entity, equity interest issued and issuable

'

'

'

'

'

'

'

105,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Percentage of Voting Interests Acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

'

4,436,000,000

3,502,000,000

201,000,000

'

'

'

'

'

2,000,000,000

'

'

'

'

144,000,000

159,000,000

1,890,000,000

1,980,000,000

746,000,000

1,020,000,000

1,410,000,000

GOODWILL

'

4,729,000,000

5,606,000,000

1,220,000,000

'

'

'

'

'

1,030,000,000

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition Units Acquired

'

'

'

'

'

'

29.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AmeriGas common units sold by ETP

9.2

7.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash proceeds from the sale of AmeriGas common units

'

346,000,000

0

0

'

381,000,000

346,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investments in and Advances to Affiliates, Balance, Shares

'

'

'

'

'

'

22.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Units Representing An Aggregate Limited Partner Interest

'

'

'

'

'

'

24.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on deconsolidation of Propane Business

'

0

1,057,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess investment of proportionate share of AmeriGas limited partner capital

'

'

'

'

'

'

439,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess fair value of proportionate share of AmeriGas limited partner capital Amortizable

'

'

'

'

'

'

184,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average years of amortizable portion of excess investment in AmeriGas

'

'

'

'

'

'

14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess of investment in AmeriGas treated as goodwill

'

'

'

'

'

'

255,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Consideration Transferred

'

'

'

'

'

'

'

'

'

'

'

'

463,000,000

'

'

'

'

'

'

'

'

Cash (paid) received from all other acquisitions

'

($405,000,000)

$531,000,000

($1,972,000,000)

'

'

'

'

'

'

'

'

$30,000,000

'

'

'

'

'

'

'

'

Net_Income_Per_Limited_Partner2

Net Income Per Limited Partner Unit (A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]	'	'	'
INCOME FROM CONTINUING OPERATIONS	$735	$1,757	$700
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	296	62	28
Income from continuing operations, net of noncontrolling interest	439	1,695	672
General Partner’s interest in income from continuing operations	505	463	433
Limited Partners’ interest in income (loss) from continuing operations	-66	1,232	239
Additional earnings allocated (to) from General Partner	-2	1	1
Distributions on employee unit awards, net of allocation to General Partner	-10	-9	-8
Income (loss) from continuing operations available to Limited Partners	($78)	$1,224	$232
Weighted average Limited Partner units – basic	343.4	248.3	207.2
Weighted Average Limited Partnership Units Outstanding, Basic	343.4	248.3	207.2
Basic income (loss) from continuing operations per Limited Partner unit	($0.23)	$4.93	$1.12
Dilutive effect of unvested Unit Awards	0	0.7	0.9
Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	343.4	249	208.1
Diluted income (loss) from continuing operations per Limited Partner unit	($0.23)	$4.91	$1.12
Basic income (loss) from discontinued operations per Limited Partner unit	$0.05	($0.50)	($0.02)
Diluted income (loss) from discontinued operations per Limited Partner unit	$0.05	($0.50)	($0.02)

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures (2012 Narrative) (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

9 Months Ended

1 Months Ended

Share data in Millions, unless otherwise specified

Mar. 31, 2012

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, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

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, 2009

Mar. 31, 2012

Dec. 31, 2013

Mar. 25, 2012

Mar. 31, 2012

Mar. 25, 2012

Oct. 31, 2012

Dec. 31, 2013

Oct. 05, 2012

Apr. 30, 2013

Oct. 31, 2012

Oct. 05, 2012

Dec. 31, 2013

Dec. 31, 2013

Oct. 05, 2012

Apr. 30, 2013

Oct. 05, 2012

Dec. 31, 2013

Oct. 05, 2012

Dec. 31, 2013

Dec. 31, 2013

Jan. 12, 2012

Sep. 30, 2012

Oct. 31, 2012

Southern Union Merger [Member]

Southern Union Merger [Member]

Southern Union Merger [Member]

Citrus Merger [Member]

Citrus Merger [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Holdco Transaction [Member]

Holdco Transaction [Member]

ETP [Member]

ETP [Member]

Sunoco Logistics [Member]

Parent Company [Member]

Parent Company [Member]

Sunoco [Member]

Sunoco [Member]

Sunoco [Member]

Carlyle Group [Member]

Sunoco [Member]

AmeriGas [Member]

Canyon Disposal [Member]

Canyon Disposal [Member]

Holdco Transaction [Member]

Sunoco Merger [Member]

Holdco Transaction [Member]

Class F Units [Member]

Holdco Transaction [Member]

PES Joint Venture [Member]

PES Joint Venture [Member]

Canyon [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition Units Acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

57

'

'

'

'

55

'

'

'

'

'

'

'

'

'

'

'

'

30

'

'

Business Combination, Consideration Transferred

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$3,010,000,000

'

'

$2,000,000,000

'

$2,600,000,000

'

'

$1,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

$207,000,000

Equity Method Investment, Ownership Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Businesses, Gross

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,900,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

2.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Subsidiary Interest in Joint Venture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

67.00%

'

'

'

'

Retained Interest, Fair Value Disclosure

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000,000

'

'

'

Business Combination, Acquisition Related Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38,000,000

'

'

'

'

28,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,032,000,000

11,902,000,000

11,551,000,000

10,854,000,000

10,981,000,000

1,802,000,000

1,596,000,000

1,323,000,000

'

'

'

'

'

'

46,339,000,000

15,702,000,000

6,799,000,000

'

'

1,260,000,000

'

'

'

'

5,930,000,000

'

'

'

'

'

3,110,000,000

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Attributable to Parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

456,000,000

1,569,000,000

669,000,000

'

'

39,000,000

'

'

'

'

14,000,000

'

'

'

'

'

145,000,000

'

'

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Businesses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,460,000,000

'

'

Equity interest in Holdco

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

100.00%

'

60.00%

60.00%

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

[1]

'

'

'

'

2,714,000,000

[2]

'

'

'

'

'

'

'

'

'

2,000,000,000

'

'

'

'

'

Partners' Capital Account, Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

333.8

'

'

'

301.5

'

'

'

'

'

'

'

'

'

333.8

301.5

225.5

193.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40

'

'

'

'

'

'

Relinquishment of rights of incentive distributions

'

8,750,000

8,750,000

8,750,000

8,750,000

11,250,000

11,250,000

11,250,000

11,250,000

12,500,000

12,500,000

12,500,000

12,500,000

18,000,000

18,000,000

18,000,000

18,000,000

13,000,000

13,000,000

12,500,000

12,500,000

26,500,000

26,500,000

26,500,000

26,500,000

'

'

'

'

'

'

'

'

35,000,000

45,000,000

50,000,000

72,000,000

51,000,000

106,000,000

329,000,000

'

'

'

'

'

'

220,000,000

'

'

'

'

'

210,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncash or Part Noncash Divestiture, Amount of Consideration Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

71,000,000

'

'

Business Combination, Contingent Consideration, Liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

Debt Of Subsidiary Guaranteed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$128,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$132,000,000

'

General Partner Interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.00%

'

'

'

'

'

'

'

Incentive Distribution Rights

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

Percent of total equity ownership of a subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32.00%

'

'

'

'

'

'

'

[1]

Includes ETP’s acquisition of Citrus.

[2]

ncludes amounts recorded with respect to Sunoco Logistics.

Investments_in_Unconsolidated_3

Investments in Unconsolidated Affiliates (Table) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Investments in and Advances to Affiliates [Line Items]	'	'	'
Revenue	$6,806	$4,057	$3,337
Operating income	1,043	635	681
Net income	574	338	341
Current assets	1,372	878	'
Property, plant and equipment, net	12,320	8,063	'
Other assets	6,478	2,529	'
Total assets	20,170	11,470	'
Current liabilities	1,455	1,605	'
Non-current liabilities	10,286	6,143	'
Equity	8,429	3,722	'
Total liabilities and equity	$20,170	$11,470	'

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures (2011 Narrative) (Details) (USD $)	0 Months Ended	1 Months Ended
	2-May-11	31-May-11
Energy Transfer Partners [Member]	'	'
Business Acquisition [Line Items]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%	'
Payments to Acquire Businesses, Gross	'	$1,380,000,000
Regency Energy Partners [Member]	'	'
Business Acquisition [Line Items]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	30.00%	'
LDH [Member]	'	'
Business Acquisition [Line Items]	'	'
Business Combination, Consideration Transferred	'	$1,980,000,000

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures (Summary of Preliminary Assets And LiabilityAcquired) (Details) (USD $)	Oct. 05, 2012		Mar. 25, 2012
In Millions, unless otherwise specified	Sunoco Merger [Member]		Southern Union Merger [Member]
Business Acquisition [Line Items]	'		'
Total current assets	$7,312	[1]	$556	[2]
Property, plant and equipment	6,686	[1]	6,242	[2]
Goodwill	2,641	[1]	2,497	[2]
Intangible Assets Acquired	1,361	[1]	55	[2]
Investments in unconsolidated affiliates	240	[1]	2,023	[2]
Note receivable	821	[1]	0	[2]
Other assets	128	[1]	163	[2]
Total assets acquired (excluding cash)	19,189	[1]	11,536	[2]
Total current liabilities	4,424	[1]	1,348	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	2,879	[1]	3,120	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	1,762	[1]	1,419	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	769	[1]	284	[2]
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value	3,580	[1]	0	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	13,414	[1]	6,171	[2]
Business Combination, Cost of Acquired Entity, Purchase Price	5,775	[1]	5,365	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	3,061	[1]	5,328	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	$2,714	[1]	$37	[2]
[1]	ncludes amounts recorded with respect to Sunoco Logistics.
[2]	Includes ETP’s acquisition of Citrus.

Acquisitions_and_Divestitures_6

Acquisitions and Divestitures (Pro forma Results of Operations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]	'	'
Revenues	$39,136	$36,169
Net Income	1,133	1,027
Business acquisition pro forma net income (loss) attributable to partners	$788	$745
Basic net income (loss) per Limited Partner unit	$1.33	$1.24
Diluted net income (loss) per Limited Partner unit	$1.33	$1.24

Acquisitions_and_Divestitures_7

Acquisitions and Divestitures (Discontinued operations) (Details) (Distribution [Member], USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013
Distribution [Member]	'	'
Disposal Group, Including Discontinued Operation, Revenue	$324	$415
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	$43	$65

Debt_Obligations_Narrative_Det

Debt Obligations (Narrative) (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 24, 2013

Jun. 24, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 24, 2013

Jun. 24, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Junior Subordinated Debt [Member]

Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]

Sunoco Merger [Member]

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

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

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

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

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

ETP [Member]

ETP [Member]

ETP [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

West Texas Gulf [Member]

West Texas Gulf [Member]

Acquisition Period [Member]

Minimum [Member]

Maximum [Member]

Debt Offering [Member]

Debt Offering [Member]

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

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

Line Of Credit Maturity October 27, 2016 [Member]

Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]

Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]

3.45% Senior Notes due January 2023 [Member]

3.45% Senior Notes due January 2023 [Member]

3.45% Senior Notes due January 2023 [Member]

4.95% Senior Notes due January 2043 [Member]

4.95% Senior Notes due January 2043 [Member]

4.95% Senior Notes due January 2043 [Member]

Note Payable to ETE [Member]

Note Payable to ETE [Member]

Junior Subordinated Debt [Member]

Junior Subordinated Debt [Member]

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

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

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

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

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

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

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

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

Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]

Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member]

Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member]

Sunoco Logistics [Member]

West Texas Gulf [Member]

West Texas Gulf [Member]

ETP [Member]

Sunoco Logistics [Member]

ETP [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Debt Offering [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Debt Offering [Member]

SUG [Member]

SUG [Member]

SUG [Member]

Variable Rate Portion of Debt [Member]

ETP [Member]

ETP [Member]

Debt Offering [Member]

ETP [Member]

ETP [Member]

Debt Offering [Member]

ETP [Member]

ETP [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

SUG [Member]

ETP [Member]

ETP [Member]

Unamortized Net Premiums And Fair Value Adjustments

'

$308,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt

'

17,088,000,000

16,220,000,000

'

'

'

'

'

'

'

'

'

'

'

11,213,000,000

9,073,000,000

2,503,000,000

1,732,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

221,000,000

166,000,000

'

'

'

'

'

'

'

'

'

'

Senior note principal amount

'

'

'

'

'

'

'

965,000,000

700,000,000

350,000,000

450,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

0

350,000,000

350,000,000

0

350,000,000

'

'

'

600,000,000

800,000,000

0

800,000,000

450,000,000

0

450,000,000

'

1,395,000,000

Debt Instrument, Description of Variable Rate Basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'three-month LIBOR rate plus 3.0175%

'

'

'

'

'

'

'

'

'

Senior note interest rate

'

4.50%

'

'

'

'

'

'

4.15%

4.90%

5.95%

7.60%

8.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.45%

'

3.45%

4.95%

'

4.95%

'

'

'

'

3.60%

'

'

5.15%

'

'

'

'

Senior note maturity date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15-Feb-23

'

'

15-Jan-43

'

'

25-Mar-13

'

'

'

1-Feb-23

'

'

1-Feb-43

'

'

27-Oct-16

'

Proceeds from May 2011 issuance of Senior Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

1,470,000,000

'

'

'

'

'

'

'

'

'

'

'

'

1,240,000,000

691,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility balance outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

119,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

0

93,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65,000,000

'

Amount available for future borrowings under the revolving credit facitlity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,340,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit outstanding, amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

93,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average interest rate on the total amount outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Current Borrowing Capacity

'

'

'

'

'

'

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

'

'

'

'

'

2,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum revolving credit capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

200,000,000

2,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Effective Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.32%

'

'

'

'

'

'

'

'

'

Leverage Ratio Maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed Charge Coverage Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.12

1.12

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Leverage Ratio Permitted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest and Fee Rate Bases

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.25%

'

'

'

'

'

'

'

'

'

'

'

Repayments of borrowings from affiliates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

55,000,000

'

'

'

'

'

'

'

'

'

'

'

Repayments of Long-term Debt

455,000,000

7,016,000,000

6,598,000,000

5,217,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ETP Note Exchange

'

'

'

'

$1,090,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of SUG Notes Exchanged for ETP Notes

'

'

'

'

'

91.00%

'

'

'

'

'

77.00%

89.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Covenant Minimum Fixed Charge Coverage Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

0.8

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.88

0.88

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Consolidated EBITDA ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

5.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Adjusted EBITDA Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Obligations_Debt_Instrume

Debt Obligations (Debt Instruments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-term Debt	$17,088	$16,220
Other Long-term Debt	228	32
Current maturities	-637	-609
LONG-TERM DEBT, less current maturities	16,451	15,442
Debt instrument interest rate	4.50%	'
ETP [Member]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	-34	-14
Long-term Debt	11,213	9,073
Panhandle [Member]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	107	136
Long-term Debt	1,023	1,757
Transwestern [Member]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	-1	-1
Long-term Debt	869	869
Southern Union [Member]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	48	49
Long-term Debt	217	1,519
Sunoco [Member]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	70	104
Long-term Debt	1,035	1,069
Sunoco Logistics [Member]	'	'
Revolving credit facilities	'	119
Debt Instrument, Unamortized Discount (Premium), Net	118	143
Long-term Debt	2,503	1,732
Southern Union Revolving Credit Facility, due May 20, 2016 [Member]	'	'
Debt instrument maturity date	20-May-16	'
Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]	'	'
Debt instrument maturity date	21-Aug-13	'
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]	'	'
Debt instrument maturity date	30-Apr-15	'
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]	'	'
Debt instrument maturity date	22-Aug-16	'
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] | Sunoco Logistics [Member]	'	'
Revolving credit facilities	200	0
Note Payable to ETE [Member]	'	'
Notes Payable	0	166
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] | Sunoco Logistics [Member]	'	'
Revolving credit facilities	0	93
6.0% Senior Notes, due July 1, 2013 [Member] | ETP [Member]	'	'
Senior Notes	0	350
Debt instrument interest rate	6.00%	'
Debt instrument maturity date	1-Jul-13	'
8.5% Senior Notes, due April 15, 2014 [Member] | ETP [Member]	'	'
Senior Notes	292	292
Debt instrument interest rate	8.50%	'
Debt instrument maturity date	15-Apr-14	'
5.95% Senior Notes, due February 1, 2015 [Member] | ETP [Member]	'	'
Senior Notes	750	750
Debt instrument interest rate	5.95%	'
Debt instrument maturity date	1-Feb-15	'
6.125% Senior Notes, due February 15, 2017 [Member] | ETP [Member]	'	'
Senior Notes	400	400
Debt instrument interest rate	6.13%	'
Debt instrument maturity date	15-Feb-17	'
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member]	'	'
Senior Notes	600	600
Debt instrument interest rate	6.70%	'
Debt instrument maturity date	1-Jul-18	'
9.7% Senior Notes, due March 15, 2019 [Member] | ETP [Member]	'	'
Senior Notes	400	400
Debt instrument interest rate	9.70%	'
Debt instrument maturity date	15-Mar-19	'
Senior Notes 4.65% Due June 1, 2021 [Member] | ETP [Member]	'	'
Senior Notes	800	800
Debt instrument interest rate	4.65%	'
Debt instrument maturity date	1-Jun-21	'
Senior Notes 5.20% Due February 1, 2022 [Member] | ETP [Member]	'	'
Senior Notes	1,000	1,000
Debt instrument interest rate	5.20%	'
Debt instrument maturity date	1-Feb-22	'
3.6% Senior Notes due February 1, 2023 [Member] | ETP [Member]	'	'
Senior Notes	800	0
Debt instrument interest rate	3.60%	'
Debt instrument maturity date	1-Feb-23	'
4.9% Senior Notes due February 1, 2024 [Member] | ETP [Member]	'	'
Senior Notes	350	0
Debt instrument interest rate	4.90%	'
Debt instrument maturity date	1-Feb-24	'
6.625% Senior Notes, due October 15, 2036 [Member] | ETP [Member]	'	'
Senior Notes	400	400
Debt instrument interest rate	6.63%	'
Debt instrument maturity date	15-Oct-36	'
7.5% Senior Notes, due July 1, 2038 [Member] | ETP [Member]	'	'
Senior Notes	550	550
Debt instrument interest rate	7.50%	'
Debt instrument maturity date	1-Jul-38	'
Senior Notes 6.05% Due June 1, 2041 [Member] | ETP [Member]	'	'
Senior Notes	700	700
Debt instrument interest rate	6.05%	'
Debt instrument maturity date	1-Jun-41	'
ETP Revolving Credit Facility, due October 27, 2016 [Member] | ETP [Member]	'	'
Senior Notes	'	1,395
Revolving credit facilities	65	'
Debt instrument interest rate	'	'
Debt instrument maturity date	27-Oct-16	'
5.39% Senior Unsecured Notes, due November 17, 2014 [Member]5.39% Senior Unsecured Notes, due November 17, 2014 [Member] | Transwestern [Member]	'	'
Senior Notes	88	88
Debt instrument interest rate	5.39%	'
Debt instrument maturity date	17-Nov-14	'
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] | Transwestern [Member]	'	'
Senior Notes	125	125
Debt instrument interest rate	5.54%	'
Debt instrument maturity date	17-Nov-16	'
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] | Transwestern [Member]	'	'
Senior Notes	82	82
Debt instrument interest rate	5.64%	'
Debt instrument maturity date	24-May-17	'
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]	'	'
Senior Notes	175	175
Debt instrument interest rate	5.36%	'
Debt instrument maturity date	9-Dec-20	'
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]	'	'
Senior Notes	150	150
Debt instrument interest rate	5.89%	'
Debt instrument maturity date	24-May-22	'
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]	'	'
Senior Notes	175	175
Debt instrument interest rate	5.66%	'
Debt instrument maturity date	9-Dec-24	'
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]	'	'
Senior Notes	75	75
Debt instrument interest rate	6.16%	'
Debt instrument maturity date	24-May-37	'
7.60% Senior Notes, due February 1, 2024 [Member] | ETP [Member]	'	'
Senior Notes	277	0
Debt instrument interest rate	7.60%	'
Debt instrument maturity date	1-Feb-24	'
7.60% Senior Notes, due February 1, 2024 [Member] | Southern Union [Member]	'	'
Senior Notes	82	360
Debt instrument interest rate	7.60%	'
Debt instrument maturity date	1-Feb-24	'
8.25% Senior Notes, due November 14, 2029 [Member] | ETP [Member]	'	'
Senior Notes	267	0
Debt instrument interest rate	8.25%	'
Debt instrument maturity date	15-Nov-29	'
8.25% Senior Notes, due November 14, 2029 [Member] | Southern Union [Member]	'	'
Senior Notes	33	300
Debt instrument interest rate	8.25%	'
Debt instrument maturity date	14-Nov-29	'
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETP [Member]	'	'
Junior Subordinated Notes	546	0
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | Southern Union [Member]	'	'
Junior Subordinated Notes	54	600
Southern Union Revolving Credit Facility, due May 20, 2016 [Member] | Southern Union [Member]	'	'
Revolving credit facilities	0	210
Debt instrument interest rate	'	'
6.05% Senior Notes, due August 15, 2013 [Member] | Panhandle [Member]	'	'
Senior Notes	0	250
Debt instrument interest rate	6.05%	'
Debt instrument maturity date	15-Aug-13	'
6.20% Senior Notes, due November 1, 2017 [Member] | Panhandle [Member]	'	'
Senior Notes	300	300
Debt instrument interest rate	6.20%	'
Debt instrument maturity date	1-Nov-17	'
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member]	'	'
Senior Notes	400	400
Debt instrument interest rate	7.00%	'
Debt instrument maturity date	15-Jun-18	'
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]	'	'
Senior Notes	150	150
Debt instrument interest rate	8.13%	'
Debt instrument maturity date	1-Jun-19	'
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]	'	'
Senior Notes	66	66
Debt instrument interest rate	7.00%	'
Debt instrument maturity date	15-Jul-29	'
Term Loan 2015 [Member] | Panhandle [Member]	'	'
Subordinated Debt	0	455
Debt instrument interest rate	1.84%	'
Debt instrument maturity date	23-Feb-15	'
4.875% Senior Notes, due 2014 [Member] | Sunoco [Member]	'	'
Senior Notes	250	250
Debt instrument interest rate	4.88%	'
Debt instrument maturity date	15-Oct-14	'
9.625% Senior Notes, due 2015 [Member] | Sunoco [Member]	'	'
Senior Notes	250	250
Debt instrument interest rate	9.63%	'
Debt instrument maturity date	15-Apr-15	'
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]	'	'
Senior Notes	400	400
Debt instrument interest rate	5.75%	'
Debt instrument maturity date	15-Jan-17	'
9.00% Debentures, due 2024 [Member] | Sunoco [Member]	'	'
Subordinated Debt	65	65
Debt instrument interest rate	9.00%	'
Debt instrument maturity date	1-Nov-24	'
8.75% Senior Notes, due February 15, 2014 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	175	175
Debt instrument interest rate	8.75%	'
Debt instrument maturity date	15-Feb-14	'
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	175	175
Debt instrument interest rate	6.13%	'
Debt instrument maturity date	15-May-16	'
5.50% Senior Notes, due February 15, 2020 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	250	250
Debt instrument interest rate	5.50%	'
Debt instrument maturity date	15-Feb-20	'
Senior Note 4.65% Due February 15, 2022 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	300	300
Debt instrument interest rate	4.65%	'
Debt instrument maturity date	15-Feb-22	'
6.85% Senior Notes, due February 15, 2040 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	250	250
Debt instrument interest rate	6.85%	'
Debt instrument maturity date	15-Feb-40	'
Senior Note 6.10%, due February 15, 2042 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	300	300
Debt instrument interest rate	6.10%	'
Debt instrument maturity date	15-Feb-42	'
4.95% Senior Notes due January 2043 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	350	0
Debt instrument interest rate	4.95%	'
Debt instrument maturity date	15-Jan-43	'
3.45% Senior Notes due January 2023 [Member] | Sunoco Logistics [Member]	'	'
Senior Notes	350	0
Debt instrument interest rate	3.45%	'
Debt instrument maturity date	15-Feb-23	'
Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member] | Sunoco Logistics [Member]	'	'
Revolving credit facilities	0	26
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member] | Sunoco Logistics [Member]	'	'
Revolving credit facilities	35	20
9.0% Senior Notes due April 15, 2019 [Member] | ETP [Member]	'	'
Senior Notes	450	450
Debt instrument interest rate	9.00%	'
Debt instrument maturity date	15-Apr-19	'
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]	'	'
Senior Notes	700	0
Debt instrument interest rate	4.15%	'
Debt instrument maturity date	1-Oct-20	'
Senior Notes 6.50% Due February 1, 2042 [Member] | ETP [Member]	'	'
Senior Notes	1,000	1,000
Debt instrument interest rate	6.50%	'
Debt instrument maturity date	1-Feb-42	'
5.15% Senior Notes due February 1, 2043 [Member] | ETP [Member]	'	'
Senior Notes	450	0
Debt instrument interest rate	5.15%	'
Debt instrument maturity date	1-Feb-43	'
5.95% Senior Notes due October 1, 2043 [Member] | ETP [Member]	'	'
Senior Notes	450	0
Debt instrument interest rate	5.95%	'
Debt instrument maturity date	1-Oct-43	'
Including Note Payable to Affiliate [Member]	'	'
Long-term Debt	'	16,217
LONG-TERM DEBT, less current maturities	'	$15,608

Debt_Obligations_Future_maturi

Debt Obligations (Future maturities of long-term debt) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
2014	$812	'
2015	1,047	'
2016	375	'
2017	1,220	'
2018	1,205	'
Thereafter	12,121	'
Long-term Debt	17,088	16,220
Excluding unamortized premiums and fair value adjustments [Member]	'	'
Long-term Debt	$16,780	'

Equity_Narrative_Details

Equity (Narrative) (Details) (USD $)

3 Months Ended

12 Months Ended

12 Months Ended

36 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

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, 2009

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Mar. 31, 2012

Oct. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Oct. 05, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Common Units [Member]

Common Units [Member]

Class E Units [Member]

Class E Units [Member]

Class F Units [Member]

Citrus Merger [Member]

Holdco Transaction [Member]

Class F Units [Member]

Class E Units [Member]

Class G Units [Member]

Class F Units [Member]

January 2013 [Member]

May 2013 [Member]

Equity Distribution Agreement [Member]

December 2016 [Member]

December 2017 [Member]

December 2018 [Member]

December 2019 [Member]

Sunoco [Member]

Holdco Transaction [Member]

ETP [Member]

Partners' Capital Account, Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

333,800,000

301,500,000

225,500,000

193,200,000

'

'

'

'

'

'

'

'

'

'

'

40,000,000

8,900,000

90,700,000

50,200,000

'

'

'

'

'

'

'

Class F Unit Distribution Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited Partners' Capital Account, Units Outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

333,826,372

301,485,604

8,853,832

8,853,832

90,706,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

99.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$200

$800

'

'

'

'

'

Equity Distribution Agreements, Value of Units Available to be Issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

145

'

'

145

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited Partners' Capital Account, Units Authorized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

333,826,372

301,485,604

8,853,832

8,853,832

90,706,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock Issued During Period, Shares, Dividend Reinvestment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Units issued in connection with the Distribution Reinvestment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,300,000

1,000,000

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Class E Units entitled to aggregate cash distributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Class E unit maximum distribution

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1.41

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Class F Distribution per Unit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$3.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Relinquishment of rights of incentive distributions

8.75

8.75

8.75

8.75

11.25

11.25

11.25

11.25

12.5

12.5

12.5

12.5

18

18

18

18

13

13

12.5

12.5

26.5

26.5

26.5

26.5

35

45

50

72

51

106

329

'

'

'

'

'

'

'

'

'

'

'

'

220

210

'

'

'

'

'

'

'

50

50

45

35

Allocation of Profits, Losses and Other by Sunoco, Percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.05%

'

'

'

'

'

'

'

Common Units issued in connection with the equity distribution program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16,900,000

1,600,000

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Common Stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

846

'

'

'

'

Fees and Commissions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9

'

'

'

'

Common Units to be Issued Under Distribution Reinvestment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock Issued During Period, Value, Dividend Reinvestment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$109

$43

$15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity_Change_in_Common_Units_

Equity (Change in Common Units) (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Equity [Abstract]	'	'	'	'
Number of Common Units, beginning of period	301.5	225.5	'	193.2
Common Units issued in connection with public offerings	13.8	15.5	29.4	'
Common Units issued in connection with certain acquisitions	49.5	57.4	0.1	'
Common Units Redeemed for Class H Units	-50.2	0	0	'
Common Units issued in connection with the Distribution Reinvestment Plan	2.3	1	0.4	'
Common Units issued in connection with the equity distribution program	16.9	1.6	2	'
Stock Repurchased During Period, Shares	-0.4	0	0	'
Issuance of Common Units under equity incentive plans	0.4	0.5	0.4	'
Number of Common Units, end of period	333.8	301.5	225.5	193.2

Equity_Public_Offerings_of_Com

Equity (Public Offerings of Common Units) (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 30, 2013	Jul. 31, 2012	Nov. 30, 2011	Apr. 30, 2011
				ETP [Member]	ETP [Member]	ETP [Member]	ETP [Member]
Number of Common Units	13.8	15.5	29.4	13.8	15.5	15.2	14.2
Price per Unit	'	'	'	$48.05	$44.57	$44.67	$50.52
Net Proceeds	$1,611	$791	$1,467	$657	$671	$660	$695

Equity_Quarterly_Distributions

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

3 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

Distribution Made to Limited Partner [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Date of Record

7-Feb-14

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

6-Nov-12

6-Aug-12

4-May-12

7-Feb-12

4-Nov-11

5-Aug-11

6-May-11

7-Feb-11

Distribution Made to Limited Partner, Distribution Date

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

14-Nov-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

15-Aug-11

16-May-11

14-Feb-11

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.92

$0.91

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

Equity_Incentive_Distribution_

Equity (Incentive Distribution Relinquishments) (Details) (USD $)	3 Months Ended																								12 Months Ended
In Millions, unless otherwise specified	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	$8.75	$8.75	$8.75	$8.75	$11.25	$11.25	$11.25	$11.25	$12.50	$12.50	$12.50	$12.50	$18	$18	$18	$18	$13	$13	$12.50	$12.50	$26.50	$26.50	$26.50	$26.50	$35	$45	$50	$72	$51	$106	$329

Equity_SXL_Quarterly_Distribut

Equity (SXL Quarterly Distributions) (Details) (USD $)

3 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

Distribution Made to Limited Partner [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Date of Record

7-Feb-14

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

6-Nov-12

6-Aug-12

4-May-12

7-Feb-12

4-Nov-11

5-Aug-11

6-May-11

7-Feb-11

Distribution Made to Limited Partner, Distribution Date

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

14-Nov-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

15-Aug-11

16-May-11

14-Feb-11

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.92

$0.91

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

Sunoco Logistics [Member]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Date of Record

10-Feb-14

8-Nov-13

8-Aug-13

9-May-13

8-Feb-13

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Distribution Date

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.66

$0.63

$0.60

$0.57

$0.55

'

'

'

'

'

'

'

'

Equity_Accumulated_other_compr

Equity (Accumulated other comprehensive income, net of tax) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]	'	'
Available-for-sale securities	$2	$0
Foreign currency translation adjustment	-1	0
Net loss on commodity related hedges	-4	0
Actuarial gain (loss) related to pensions and other postretirement benefits	56	-10
Equity investments, net	8	-9
Subtotal	61	-19
Amounts attributable to noncontrolling interest	0	6
Total AOCI, net of tax	$61	($13)

Equity_Tax_amounts_attributabl

Equity (Tax amounts attributable to Accumulated Other Comprehensive Income)(Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]	'	'
Other Comprehensive Income Loss Commodity Hedges Tax	$0	($1)
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)	$6

UnitBased_Compensation_Plans_N1

Unit-Based Compensation Plans (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Weighted average grant-date fair value per unit award granted	$50.54	$43.93	$48.35
Total fair value of awards vested	$26	$29	$27
Unvested unit awards outstanding	3.2	1.9	'
Employee [Member]	'	'	'
Share based compensation, vesting term	'5 years 0 months	'	'
Director [Member]	'	'	'
Share based compensation, vesting term	'5 years 0 months	'	'
Related Party Awards [Member]	'	'	'
Share based compensation, vesting term	'5 years 0 months	'	'
Share based compensation, annual vesting percentage	20.00%	'	'
Allocated Share-based Compensation Expense	1	1	2
ETP Unit-Based Compensation Plans [Member]	'	'	'
Awards remaining unvested compensation expense	116	'	'
Awards remaining unvested weighted average period, in years	'2 years 0 months 22 days	'	'
Sunoco Logistics Unit-Based Compensation Plans [Member]	'	'	'
Unvested unit awards outstanding	0.6	'	'
Awards remaining unvested compensation expense	$21	'	'
Awards remaining unvested weighted average period, in years	'2 years 9 months 25 days	'	'
Units Remaining To Be Awarded	0.6	'	'

UnitBased_Compensation_Plans_A

Unit-Based Compensation Plans (Activity of the awards granted to employees and non-employee directors) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred Compensation Arrangements [Abstract]	'	'	'
Unvested awards as of December 31, 2010 , Number of Units	1.9	'	'
Awards granted, Number of Units	2.1	'	'
Awards vested, Number of Units	-0.6	'	'
Unvested awards as of December 31, 2011, Number of Units	3.2	1.9	'
Unvested awards as of December 31, 2010, Weighted Average Grant-Date Fair Value Per Unit	$46.95	'	'
Weighted average grant-date fair value per unit award granted	$50.54	$43.93	$48.35
Awards vested, Weighted Average Grant-Date Fair Value Per Unit	$45.62	'	'
Awards forfeited, Weighted Average Grant-Date Fair Value Per Unit	$45.72	'	'
Unvested awards as of December 31, 2011, Weighted Average Grant-Date Fair Value Per Unit	$49.65	$46.95	'
Stock Granted, Value, Share-based Compensation, Forfeited	($0.20)	'	'

Income_Taxes_Narrative_Details

Income Taxes Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Contingency [Line Items]	'	'
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	'
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	1	'
Operating Loss Carryforwards	216	'
Net operating losses and alternative minimum tax credit	217	268
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	425	'
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	6	'
Amount of Deferred Gain Challenged by IRS	545	'
Deferred Gain Associated with Like Kind Exchange	690	'
Deferred Tax Assets, Valuation Allowance	74	90
Pending Tax Refund	372	'
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	372	'
Expiring 2013 to 2032 [Member]	'	'
Income Tax Contingency [Line Items]	'	'
Operating Loss Carryforwards	101	'
Holdco [Member]	'	'
Income Tax Contingency [Line Items]	'	'
Net operating losses and alternative minimum tax credit	$40	'

Income_Taxes_Compoenents_of_Fe

Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit)(Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current expense (benefit):	'	'	'
Federal	$51	($3)	($1)
State	-2	4	16
Current expense (benefit) - Total	49	1	15
Deferred expense:	'	'	'
Federal	-6	45	4
State	54	17	0
Deferred expense (benefit) - Total	48	62	4
Income tax expense from continuing operations	$97	$63	$19

Income_Taxes_Statutory_Income_

Income Taxes Statutory Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Effective Income Tax Rate Reconciliation [Line Items]	'	'	'
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	($166)	$1	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	241	0	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount	0	28	'
Income Tax Reconciliation, State and Local Income Taxes	36	16	'
Income Tax Reconciliation, Other Reconciling Items	-14	18	'
Income tax expense from continuing operations	97	63	19
Corporate Subsidiaries [Member]	'	'	'
Schedule of Effective Income Tax Rate Reconciliation [Line Items]	'	'	'
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	-166	1	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	241	0	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount	0	28	'
Income Tax Reconciliation, State and Local Income Taxes	31	9	'
Income Tax Reconciliation, Other Reconciling Items	-13	18	'
Income tax expense from continuing operations	93	56	'
Partnership [Member]	'	'	'
Schedule of Effective Income Tax Rate Reconciliation [Line Items]	'	'	'
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	0	0	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	0	0	'
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount	0	0	'
Income Tax Reconciliation, State and Local Income Taxes	5	7	'
Income Tax Reconciliation, Other Reconciling Items	-1	0	'
Income tax expense from continuing operations	$4	$7	'

Income_Taxes_Tax_Effects_of_Te

Income Taxes Tax Effects of Temporary Differences (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Deferred income tax assets:	'	'	'
Net operating losses and alternative minimum tax credit	$217	$268	'
Pension and other postretirement benefits	57	127	'
Long term debt	108	117	'
Other	104	288	'
Total deferred income tax assets	486	800	'
Valuation allowance	-74	-90	'
Net deferred income tax assets	412	710	'
Deferred income tax liabilities:	'	'	'
Properties, plants and equipment	-1,522	-1,938	'
Inventory	-302	-516	'
Investment in unconsolidated affiliates	-2,244	-1,542	'
Trademarks	-180	-192	'
Other	-45	-128	'
Total deferred income tax liabilities	-4,293	-4,316	'
Net deferred income tax liability	-3,881	-3,606	-123
Less: current portion of deferred income tax assets (liabilities)	-119	-130	'
Accumulated deferred income taxes	($3,762)	($3,476)	'

Income_Taxes_Components_of_Net

Income Taxes Components of Net Deferred Income Tax (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Net deferred income tax liability, beginning of year	($3,881)	($3,606)	($123)
Increase in Tax Liability Attributable to Southern Union	0	1,420	'
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	'
Tax provision (including discontinued operations)	-111	-73	'
Increase (Decrease) in Other Deferred Liability	($49)	($1)	'

Income_Taxes_Changes_in_Unreco

Income Taxes Changes in Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Balance at beginning of year	$27	$2	$2
Unrecognized Tax Benefits, Increases Resulting from Acquisition	0	28	0
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
Settlements	0	0	-1
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	-4	-3	0
Balance at end of year	$429	$27	$2

Regulatory_Matters_Commitments2

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Narrative) (Details) (USD $)	12 Months Ended			9 Months Ended	12 Months Ended		12 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
				FGT [Member]	FGT [Member]	AmeriGas [Member]	Southern Union [Member]	Related To Deductibles [Member]	Related To Deductibles [Member]	State and Local Jurisdiction [Member]	U.S Federal [Member]
Business Combination, Contingent Consideration, Liability	'	'	'	'	'	$1,550,000,000	'	'	'	'	'
Litigation Settlement, Amount	'	'	'	'	'	'	'	'	'	950,000	250,000
Proceeds from Legal Settlements	'	'	'	100,000,000	'	'	'	'	'	'	'
Loss Contingency, Damages Awarded, Value	'	'	'	19,000,000	1,000,000	'	'	'	'	'	'
Debt instrument interest rate	4.50%	'	'	'	'	'	'	'	'	'	'
Lease Expiration Date	31-Dec-56	'	'	'	'	'	'	'	'	'	'
Rental expense under operating lease	140,000,000	57,000,000	26,000,000	'	'	'	'	'	'	'	'
Operating Leases, Rent Expense, Contingent Rentals	22,000,000	6,000,000	'	'	'	'	'	'	'	'	'
Operating Leases, Income Statement, Sublease Revenue	24,000,000	4,000,000	'	'	'	'	'	'	'	'	'
Loss Contingency Accrual, at Carrying Value	'	'	'	'	'	'	'	46,000,000	42,000,000	'	'
Environmental Costs Recognized, Recovery Credited to Expense	19,000,000	'	'	'	'	'	'	'	'	'	'
Percentage Of Recovery	'	'	'	'	'	'	50.00%	'	'	'	'
Loss Contingency, Estimated Recovery from Third Party	'	'	'	'	'	'	'150000	'	'	'	'
Payments for Environmental Liabilities	36,000,000	12,000,000	'	'	'	'	'	'	'	'	'
Guarantor Obligations, Current Carrying Value	$600,000,000	'	'	'	'	'	'	'	'	'	'
Site Contingency, Number of Sites Needing Remediation	'	40	'	'	'	'	'	'	'	'	'

Regulatory_Matters_Commitments3

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Future minimum lease commitments) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
2014	$80
2015	78
2016	70
2017	66
2018	53
Thereafter	420
Total Future Rent Payments	767
Future Rental Income	-57
Net Future Rental Payments	$710

Regulatory_Matters_Commitments4

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Environmental Remediation Obligations [Abstract]	'	'
Accrued Environmental Loss Contingencies, Current	$45	$46
Accrued Environmental Loss Contingencies, Noncurrent	350	165
Accrual for Environmental Loss Contingencies	$395	$211

Price_risk_management_assets_a2

Price risk management assets and liabilties (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Settlement of Interest Rate Swaps	$400	'
Option Premiums	'	-7
ETP [Member]	'	'
Derivative [Line Items]	'	'
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	$4	'

Price_risk_management_assets_a3

Price risk management assets and liabilties (Outstanding commodity-related derivatives) (Details)	Dec. 31, 2013	Dec. 31, 2012
	barrels	barrels
Power [Member] | ETP [Member] | Options - Puts [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-52,800	'
Maturity, maximum	'2014	'
Refined Products [Member] | ETP [Member] | Future [Member] | Cash Flow Hedging [Member]	'	'
Notional Volume	0	-98,000
Refined Products [Member] | ETP [Member] | Future [Member] | Non Trading [Member] | Cash Flow Hedging [Member]	'	'
Maturity, maximum	'	'2013
Non Trading [Member] | Natural Gas [Member] | Fair Value Hedging [Member]	'	'
Notional Volume	50,530,000	44,272,500
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-8,195,000	27,077,500
Maturity, maximum	'	'2013
Non Trading [Member] | Natural Gas [Member] | Future [Member] | Fair Value Hedging [Member]	'	'
Notional Volume	-50,530,000	-44,272,500
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Future [Member] | Cash Flow Hedging [Member]	'	'
Notional Volume	-12,775,000	-8,212,500
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-9,690,000	-83,292,500
Maturity, maximum	'	'2013
Non Trading [Member] | Natural Gas [Member] | Basis Swap [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	570,000	150,000
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Basis Swap [Member] | Fair Value Hedging [Member]	'	'
Notional Volume	-7,352,500	-18,655,000
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Basis Swap [Member] | Cash Flow Hedging [Member]	'	'
Notional Volume	-1,825,000	0
Maturity, maximum	'2014	'
Non Trading [Member] | Natural Gas [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	5,668,559	11,689,855
Non Trading [Member] | Natural Gas [Member] | Minimum [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'
Non Trading [Member] | Natural Gas [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'
Non Trading [Member] | Natural Gas [Member] | Minimum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas [Member] | Maximum [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2015	'
Non Trading [Member] | Natural Gas [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2016	'
Non Trading [Member] | Natural Gas [Member] | Maximum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2015	'2014
Non Trading [Member] | Crude Oil [Member] | Future [Member] | Cash Flow Hedging [Member]	'	'
Notional Volume	-30,000	0
Maturity, maximum	'2014	'
Non Trading [Member] | Refined Products [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-1,133,600	-666,000
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-280,000	-30,000
Maturity, maximum	'2014	'2013
Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Cash Flow Hedging [Member]	'	'
Notional Volume	-780,000	-930,000
Maturity, maximum	'2014	'2013
Trading [Member] | Power [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-772,476	-1,509,300
Maturity, maximum	'2014	'2013
Trading [Member] | Power [Member] | Call Option [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	103,200	1,656,400
Maturity, maximum	'2014	'2013
Trading [Member] | Power [Member] | Forwards Swaps [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	351,050	19,650
Maturity, maximum	'2014	'2013
Trading [Member] | Natural Gas [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	9,457,500	0
Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	1,937,500	0
Trading [Member] | Natural Gas [Member] | Basis Swap [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	-487,500	-30,980,000
Trading [Member] | Natural Gas [Member] | Minimum [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'
Trading [Member] | Natural Gas [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'
Trading [Member] | Natural Gas [Member] | Minimum [Member] | Basis Swap [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2014	'2013
Trading [Member] | Natural Gas [Member] | Maximum [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2019	'
Trading [Member] | Natural Gas [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2016	'
Trading [Member] | Natural Gas [Member] | Maximum [Member] | Basis Swap [Member] | Mark to Market Derivatives [Member]	'	'
Maturity, maximum	'2017	'2014
Trading [Member] | Crude Oil [Member] | Future [Member] | Mark to Market Derivatives [Member]	'	'
Notional Volume	103,000	0
Maturity, maximum	'2014	'

Price_risk_management_assets_a4

Price risk management assets and liabilties (Interest rate swaps outstanding) (Details) (Derivatives not designated as hedging instruments - Interest rate derivatives [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
ETP [Member] | July 2013 [Member]	'		'
Type	'Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	[1],[2]	'
Notional amount outstanding	$0	[2]	$400	[2]
ETP [Member] | July 2014 [Member]	'		'
Type	'Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	[1],[2]	'
Notional amount outstanding	400	[2]	400	[2]
ETP [Member] | July 2018 [Member]	'		'
Type	'Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	[1]	'
Notional amount outstanding	600		600
ETP [Member] | Fixed Interest Rate of 4.25 Percent [Member]	'		'
Type	'Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	[1]	'
Notional amount outstanding	400		0
ETP [Member] | Floating Interest Rate Of 6.70 Percent [Member]	'		'
Type	'Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	[1]	'
Notional amount outstanding	400		0
Southern Union [Member] | Fixed Rate of 2.91 Percent [Member]	'		'
Type	'Pay a fixed rate of 2.97% and receive a floating rate	[1],[3]	'
Notional amount outstanding	0	[3]	75	[3]
Southern Union [Member] | Fixed Rate of 3.75 Percent [Member]	'		'
Type	'Pay a fixed rate of 3.801% and receive a floating rate	[1],[3]	'
Notional amount outstanding	$275	[3]	$450	[3]
[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(2) Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. During the year ended December 31, 2013, we 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.

Price_risk_management_assets_a5

Price risk management assets and liabilties (Fair Value of Derivative Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Total derivative assets	$316	$208
Total derivative liabilities	360	392
Designated as Hedging Instrument [Member]	'	'
Total derivative assets	3	8
Total derivative liabilities	-18	-10
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]	'	'
Total derivative assets	3	8
Total derivative liabilities	-18	-10
Not Designated as Hedging Instrument [Member]	'	'
Total derivative assets	313	200
Total derivative liabilities	-342	-382
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]	'	'
Total derivative assets	227	110
Total derivative liabilities	-209	-116
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Total derivative assets	39	33
Total derivative liabilities	-38	-34
Commodity [Member] | Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivative assets	0	1
Total derivative liabilities	0	0
Commodity [Member] | Non-Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivative assets	0	1
Total derivative liabilities	0	0
Commodity [Member] | Current Liabilities Held For Sale [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivative assets	0	0
Total derivative liabilities	0	-9
Netting [Member]	'	'
Total derivative assets	306	178
Total derivative liabilities	356	255
Derivative Asset, Fair Value, Gross Liability	-36	-25
Derivative Liability, Fair Value, Gross Asset	36	25
Derivative Asset, Fair Value, Net	269	153
Derivative Liability, Fair Value, Net	-265	-169
Netting [Member] | Asset Fair Value, Netting Offset [Member]	'	'
Collateral Paid To OTC Counterparties	0	0
Payments on Margin Deposits	-1	0
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	47	55
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	-95	-223
Netting [Member] | Bi-lateral contracts [Member]	'	'
Total derivative assets	41	28
Total derivative liabilities	38	27
Netting [Member] | Broker cleared derivative contracts [Member]	'	'
Total derivative assets	265	150
Total derivative liabilities	$318	$228

Price_risk_management_assets_a6

Price risk management assets and liabilties (Netting table) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	$316	$208
Derivative Liability, Fair Value, Gross Liability	-360	-392
Derivative Asset, Fair Value, Amount Offset Against Collateral	-37	-25
Derivative Liability, Fair Value, Amount Offset Against Collateral	91	86
Netting [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	306	178
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, Net	269	153
Derivative Liability, Fair Value, Net	-265	-169
Bi-lateral contracts [Member] | Netting [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	41	28
Derivative Liability, Fair Value, Gross Liability	-38	-27
Broker cleared derivative contracts [Member] | Netting [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	265	150
Derivative Liability, Fair Value, Gross Liability	-318	-228
Asset Fair Value, Netting Offset [Member] | Netting [Member]	'	'
Derivative [Line Items]	'	'
Collateral Paid To OTC Counterparties	0	0
Payments on Margin Deposits	-1	0
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	47	55
Liability Fair Value, Netting Offset [Member] | Netting [Member]	'	'
Derivative [Line Items]	'	'
Collateral Paid To OTC Counterparties	0	2
Payments on Margin Deposits	55	59
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	-95	-223
Not Designated as Hedging Instrument [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	313	200
Derivative Liability, Fair Value, Gross Liability	$342	$382

Price_risk_management_assets_a7

Price risk management assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]	'	'	'
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$8	$54	$34
Cost of Sales [Member] | Commodity [Member]	'	'	'
Derivative [Line Items]	'	'	'
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$8	$54	$34

Price_risk_management_assets_a8

Price risk management assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	($1)	$8	$19
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	4	14	38
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	8	54	34
Amount of Gain (Loss) Recognized In Income On Derivatives	18	-52	-98
Gains (losses) on interest rate derivatives	44	-4	-77
Commodity [Member]	'	'	'
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	-1	8	19
Commodity [Member] | Cost of Sales [Member]	'	'	'
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	4	14	38
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	8	54	34
Trading [Member] | Commodity [Member] | Cost of Sales [Member]	'	'	'
Amount of Gain (Loss) Recognized In Income On Derivatives	-11	-7	-30
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member]	'	'	'
Amount of Gain (Loss) Recognized In Income On Derivatives	-12	-15	9
Non Trading [Member] | Commodity [Member] | Deferred Gas Purchases [Member]	'	'	'
Amount of Gain (Loss) Recognized In Income On Derivatives	($3)	($26)	$0

Retirement_Benefits_Narratives

Retirement Benefits (Narratives) (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Weighted average grant-date fair value per unit award granted	'	$50.54	$43.93	$48.35
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	'	915,922	'	'
Unvested unit awards outstanding	1,900,000	3,200,000	1,900,000	'
Pretax curtailment gain	$75	'	'	'
Noncurrent refund liability	60	'	'	'
Gain on curtailment of other postretirement benefits	'	0	15	0
Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Gain on curtailment of other postretirement benefits	'	0	0	'
Large Cap US Equitiies	'	66.00%	'	'
Fixed Income Securities	'	10.00%	'	'
Other Investments - Plan Asset Allocation	'	24.00%	'	'
2014	'	23	'	'
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Gain on curtailment of other postretirement benefits	15	0	15	'
Large Cap US Equitiies	'	41.00%	'	'
Fixed Income Securities	'	48.00%	'	'
Cash Fund Investments	'	6.00%	'	'
Other Investments - Plan Asset Allocation	'	5.00%	'	'
ETP [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Contributions to the 401(k) savings plan	'	38	21	11
Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Large Cap US Equitiies	36.00%	'	36.00%	'
Fixed Income Securities	54.00%	'	54.00%	'
Other Investments - Plan Asset Allocation	10.00%	'	10.00%	'
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Large Cap US Equitiies	19.00%	'	19.00%	'
Fixed Income Securities	74.00%	'	74.00%	'
Cash Fund Investments	4.00%	'	4.00%	'
Other Investments - Plan Asset Allocation	3.00%	'	3.00%	'
Sunoco [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent	'	200	'	'
Equity [Member] | Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	'	25.00%	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	'	70.00%	'	'
Equity [Member] | Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	'	25.00%	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	'	35.00%	'	'
Equity [Member] | Sunoco [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations	'	35.00%	'	'
Fixed Income Investments [Member] | Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	'	15.00%	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	'	35.00%	'	'
Fixed Income Investments [Member] | Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	'	65.00%	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	'	75.00%	'	'
Fixed Income Investments [Member] | Sunoco [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations	'	55.00%	'	'
Alternative Assets [Member] | Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	'	10.00%	'	'
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	'	35.00%	'	'
Cash [Member] | Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	'	0.00%	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	'	10.00%	'	'
Cash [Member] | Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	'	0.00%	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	'	10.00%	'	'
Private Equity Funds [Member] | Sunoco [Member] | Pension Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations	'	10.00%	'	'
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
2014	'	$18	'	'
Sunoco Logistics Unit-Based Compensation Plans [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Awards remaining unvested weighted average period, in years	'	'2 years 9 months 25 days	'	'
Unvested unit awards outstanding	'	600,000	'	'

Retirement_Benefits_Obligation

Retirement Benefits Obligations and Funded Status (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	$0	$0	'
Change in Plan Assets, Dispositions	-27	0	'
Change in Benefit Obligations, Dispositions	-41	0	'
Pension Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Service Cost	'	3	'
Defined Benefit Plan, Interest Cost	35	15	'
Defined Benefit Plan, Plan Amendments	'	0	'
Actuarial Loss and Other	'	-9	'
Defined Benefit Plan, Actual Return on Plan Assets	'	22	'
Defined Benefit Plan, Contributions by Employer	'	14	'
Benefit obligation	'	1,195	1,257
Fair value of plan assets	'	906	941
Amount underfunded	'	289	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Non-current assets	'	0	'
Current liabilities	'	-15	'
Non-current liabilities	'	-274	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	'	-289	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	'	-1	'
Defined Benefit Plan, Benefits Paid	'	71	'
Defined Benefit Plan, Curtailments	'	0	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	'	0	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	'	-1	'
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Service Cost	0	1	'
Defined Benefit Plan, Interest Cost	6	3	'
Defined Benefit Plan, Plan Amendments	2	17	'
Actuarial Loss and Other	-14	4	'
Defined Benefit Plan, Actual Return on Plan Assets	17	5	'
Defined Benefit Plan, Contributions by Employer	8	9	'
Benefit obligation	223	296	359
Fair value of plan assets	284	312	306
Amount underfunded	-61	-16	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Non-current assets	86	59	'
Current liabilities	-2	-2	'
Non-current liabilities	-23	-41	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	61	16	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	-25	-1	'
Defined Benefit Plan, Benefits Paid	26	8	'
Defined Benefit Plan, Curtailments	0	80	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	18	16	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	-7	15	'
Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	600	906	'
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	284	312	'
Funded Plans [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	-95	'	'
Change in Plan Assets, Dispositions	-155	'	'
Change in Benefit Obligations, Dispositions	-253	'	'
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Service Cost	3	'	'
Defined Benefit Plan, Interest Cost	33	'	'
Defined Benefit Plan, Plan Amendments	0	'	'
Actuarial Loss and Other	-74	'	'
Defined Benefit Plan, Actual Return on Plan Assets	43	'	'
Defined Benefit Plan, Contributions by Employer	0	'	'
Benefit obligation	632	1,117	'
Fair value of plan assets	600	906	'
Amount underfunded	32	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Non-current assets	0	'	'
Current liabilities	0	'	'
Non-current liabilities	-32	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	-32	'	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	-86	'	'
Defined Benefit Plan, Benefits Paid	99	'	'
Defined Benefit Plan, Curtailments	0	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	-86	'	'
Unfunded Plans [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	'	'
Change in Benefit Obligations, Dispositions	0	'	'
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Service Cost	0	'	'
Defined Benefit Plan, Interest Cost	2	'	'
Defined Benefit Plan, Plan Amendments	0	'	'
Actuarial Loss and Other	-3	'	'
Benefit obligation	61	78	'
Amount underfunded	61	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Non-current assets	0	'	'
Current liabilities	-9	'	'
Non-current liabilities	-52	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	-61	'	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	-4	'	'
Defined Benefit Plan, Benefits Paid	16	'	'
Defined Benefit Plan, Curtailments	0	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	-4	'	'
Change in Plan Assets [Member] | Unfunded Plans [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	'	'
Change in Plan Assets, Dispositions	0	'	'
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Actual Return on Plan Assets	0	'	'
Defined Benefit Plan, Contributions by Employer	0	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Defined Benefit Plan, Benefits Paid	$0	'	'

Retirement_Benefits_Components

Retirement Benefits Components of Net Periodic Benefit Cost (Details) (USD $)	12 Months Ended					9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
				Pension Plans, Defined Benefit [Member]	Pension Plans, Defined Benefit [Member]	Other Postretirement Benefit Plans, Defined Benefit [Member]	Other Postretirement Benefit Plans, Defined Benefit [Member]	Other Postretirement Benefit Plans, Defined Benefit [Member]	Funded Plans [Member]
									Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'	'	'	'	'	'
Defined Benefit Plan, Service Cost	'	'	'	'	$3	'	$0	$1	$3
Defined Benefit Plan, Interest Cost	'	'	'	35	15	'	6	3	33
Defined Benefit Plan, Expected Return on Plan Assets	'	'	'	-54	-21	'	-9	-5	'
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	'	'	'	0	0	'	1	0	'
Defined Benefit Plan, Amortization of Gains (Losses)	'	'	'	-2	0	'	0	0	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	'	'	'	0	2	'	0	0	'
Gain on curtailment of other postretirement benefits	0	-15	0	0	0	-15	0	-15	'
Net Periodic Benefit Costs, Settlements	'	'	'	2	0	'	0	0	'
Net periodic benefit cost subtotal	'	'	'	-16	-1	'	-2	-16	'
Net Period Benefit Cost Regulatory Adjustment	'	'	'	5	9	'	0	2	'
Defined Benefit Plan, Net Periodic Benefit Cost	'	'	'	($11)	$8	'	($2)	($14)	'

Retirement_Benefits_Summary_fo

Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) (Southern Union [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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 Benefit Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	223	225
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	284	185
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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] | Pension Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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_WeightedAv

Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details)	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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%
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.33%	2.39%

Retirement_Benefits_Assumed_He

Retirement Benefits Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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

Retirement_Benefits_Schedule_O

Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
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 Benefit Plans, Defined Benefit [Member]	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
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_Fair_Value

Retirement Benefits Fair Value of Plan Assets (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Millions, unless otherwise specified
Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	$284		$312		$306
Large Cap US Equitiies	41.00%		'		'
Fixed Income Securities	48.00%		'		'
Cash Fund Investments	6.00%		'		'
Other Investments - Plan Asset Allocation	5.00%		'		'
Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		906		941
Large Cap US Equitiies	66.00%		'		'
Fixed Income Securities	10.00%		'		'
Other Investments - Plan Asset Allocation	24.00%		'		'
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	10		'		'
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	12		'		'
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	112		'		'
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 1 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	18		'		'
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	281		'		'
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	144		'		'
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	220		'		'
Fair Value, Inputs, Level 2 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	87		'		'
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		'		'
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	284		312		'
Large Cap US Equitiies	'		19.00%		'
Fixed Income Securities	'		74.00%		'
Cash Fund Investments	'		4.00%		'
Other Investments - Plan Asset Allocation	'		3.00%		'
Southern Union [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	600		906		'
Large Cap US Equitiies	'		36.00%		'
Fixed Income Securities	'		54.00%		'
Other Investments - Plan Asset Allocation	'		10.00%		'
Southern Union [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	10		7		'
Southern Union [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	12		25		'
Southern Union [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	130	[1]	147	[1]	'
Southern Union [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	368	[2]	516	[2]	'
Southern Union [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	144		158		'
Southern Union [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	220		354		'
Southern Union [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0	[3]	11	[3]	'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	122		133		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	12		25		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		7		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		25		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		126		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	162		179		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	501		798		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		21		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		433		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		158		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		354		'
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		11		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	0		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	87		83		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		83		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		0		'
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member] | Pension Plans, Defined Benefit [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value of plan assets	'		$0		'
[1]	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.
[2]	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.
[3]	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.

Retirement_Benefits_Expected_F

Retirement Benefits Expected Future Benefit Payments (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Plans, Defined Benefit [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
2014	$23
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
2014	31
2015	29
2016	28
2017	26
2018	24
2019 - 2022	87
Other Postretirement Benefit Plans, Defined Benefit [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
2014	18
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
2014	82
2015	77
2016	67
2017	61
2018	56
2019 - 2022	220
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
2014	9
2015	9
2016	8
2017	7
2018	7
2019 - 2022	$23

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
	bbl
Related Party Delivery of Crude	300,000
Related Party Fee	0.0167
FEP [Member]	'
Equity Method Investment, Ownership Percentage	50.00%

Related_Party_Transactions_Rel

Related Party Transactions Related Party balances on condensed consolidated balance sheets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	$165	$94
Accounts Payable, Related Parties	45	24
ETE [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	18	16
Accounts Payable, Related Parties	8	7
Regency [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	53	10
Accounts Payable, Related Parties	24	2
PES Joint Venture [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	7	60
Accounts Payable, Related Parties	0	13
FGT [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	29	2
Accounts Payable, Related Parties	8	0
Eastern Gulf [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	24	0
Other Related Parties [Member]	'	'
Related Party Transaction [Line Items]	'	'
Accounts Receivable, Related Parties	34	6
Accounts Payable, Related Parties	$5	$2

Related_Party_Transactions_Rel1

Related Party Transactions Related Party - Affiliated Revenues (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Revenue from Related Parties	$1,550	$173	$690

Reportable_Segments_Financial_

Reportable Segments (Financial information by segment) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	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
Adjusted EBITDA	'	'	'	'	'	'	'	'	$3,953	$2,744	$1,781
Depreciation and amortization	'	'	'	'	'	'	'	'	-1,032	-656	-405
Interest expense, net of interest capitalized	'	'	'	'	'	'	'	'	-849	-665	-474
Gain on deconsolidation of Propane Business	'	'	'	'	'	'	'	'	0	1,057	0
Equity Method Investment, Realized Gain (Loss) on Disposal	'	'	'	'	'	'	'	'	87	0	0
Goodwill impairment	'	'	'	'	'	'	'	'	-689	0	0
Gains (losses) on interest rate derivatives	'	'	'	'	'	'	'	'	44	-4	-77
Non-cash compensation expense	'	'	'	'	'	'	'	'	-47	-42	-38
Unrealized gains (losses) on commodity risk management activities	'	'	'	'	'	'	'	'	51	-9	-11
Inventory, LIFO Reserve, Effect on Income, Net	'	'	'	'	'	'	'	'	3	-75	0
Loss on extinguishment of debt	'	'	'	'	'	'	'	'	0	-115	0
Environmental Remediation Expense	'	'	'	'	'	'	'	'	168	0	0
Adjusted EBITDA attributable to discontinued operations	'	'	'	'	'	'	'	'	-76	-99	-23
Proportionate share of unconsolidated affiliates' interest, depreciation and allowance for equity funds used during construction	'	'	'	'	'	'	'	'	-629	-480	-56
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	172	142	26
Other, net	'	'	'	'	'	'	'	'	12	22	-4
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	'	'	'	'	'	'	'	'	832	1,820	719
Revenues	12,032	11,902	11,551	10,854	10,981	1,802	1,596	1,323	46,339	15,702	6,799
Cost of products sold	'	'	'	'	'	'	'	'	41,204	12,266	4,175
Assets	43,702	'	'	'	43,230	'	'	'	43,702	43,230	15,519
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	2,455	3,049	1,484
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,436	'	'	'	3,502	'	'	'	4,436	3,502	201
Intrastate Transportation And Storage [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	464	601	667
Depreciation and amortization	'	'	'	'	'	'	'	'	-122	-122	-120
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	0	4	2
Revenues	'	'	'	'	'	'	'	'	2,452	2,191	2,674
Cost of products sold	'	'	'	'	'	'	'	'	1,737	1,394	1,774
Assets	4,606	'	'	'	4,691	'	'	'	4,606	4,691	4,785
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	47	37	53
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	1	'	'	'	2	'	'	'	1	2	1
Intrastate Transportation And Storage [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	2,250	2,012	2,398
Intrastate Transportation And Storage [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	202	179	276
Interstate Transportation and Storage [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	1,269	1,013	373
Depreciation and amortization	'	'	'	'	'	'	'	'	-244	-209	-81
Goodwill impairment	'	'	'	'	'	'	'	'	-689	0	0
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	142	120	24
Revenues	'	'	'	'	'	'	'	'	1,309	1,109	447
Assets	10,988	'	'	'	11,794	'	'	'	10,988	11,794	3,661
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	152	133	207
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	2,040	'	'	'	2,142	'	'	'	2,040	2,142	173
Interstate Transportation and Storage [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	1,270	1,109	447
Interstate Transportation and Storage [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	39	0	0
Midstream [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	479	467	421
Depreciation and amortization	'	'	'	'	'	'	'	'	-172	-168	-85
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	0	-9	0
Revenues	'	'	'	'	'	'	'	'	2,249	1,953	1,483
Cost of products sold	'	'	'	'	'	'	'	'	1,579	1,273	988
Assets	3,133	'	'	'	4,946	'	'	'	3,133	4,946	2,513
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	565	1,317	837
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	0	'	'	'	1	'	'	'	0	1	0
Midstream [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	1,307	1,757	1,082
Midstream [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	942	196	401
NGL Transportation And Services [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	351	209	127
Depreciation and amortization	'	'	'	'	'	'	'	'	-91	-53	-32
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	-2	2	0
Revenues	'	'	'	'	'	'	'	'	2,127	650	397
Cost of products sold	'	'	'	'	'	'	'	'	1,655	361	218
Assets	4,326	'	'	'	3,765	'	'	'	4,326	3,765	2,360
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	443	1,302	325
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	29	'	'	'	29	'	'	'	29	29	27
NGL Transportation And Services [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	2,063	619	363
NGL Transportation And Services [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	64	31	34
Investment in Sunoco Logistics [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	871	219	0
Depreciation and amortization	'	'	'	'	'	'	'	'	-265	-63	0
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	18	5	0
Revenues	'	'	'	'	'	'	'	'	16,639	3,189	0
Cost of products sold	'	'	'	'	'	'	'	'	15,574	2,885	0
Assets	11,650	'	'	'	10,291	'	'	'	11,650	10,291	0
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	1,018	139	0
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	125	'	'	'	118	'	'	'	125	118	0
Investment in Sunoco Logistics [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	16,480	3,109	0
Investment in Sunoco Logistics [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	159	80	0
Retail Marketing [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	325	109	0
Depreciation and amortization	'	'	'	'	'	'	'	'	-114	-28	0
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	2	1	0
Revenues	'	'	'	'	'	'	'	'	21,012	5,926	0
Cost of products sold	'	'	'	'	'	'	'	'	20,150	5,757	0
Assets	3,936	'	'	'	3,926	'	'	'	3,936	3,926	0
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	176	58	0
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	22	'	'	'	21	'	'	'	22	21	0
Retail Marketing [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	21,004	5,926	0
Retail Marketing [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	8	0	0
Other Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Adjusted EBITDA	'	'	'	'	'	'	'	'	194	126	193
Depreciation and amortization	'	'	'	'	'	'	'	'	-24	-13	-87
Goodwill impairment	'	'	'	'	'	'	'	'	0	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	12	19	0
Revenues	'	'	'	'	'	'	'	'	2,367	1,555	2,888
Cost of products sold	'	'	'	'	'	'	'	'	2,309	1,496	2,274
Assets	5,063	'	'	'	3,817	'	'	'	5,063	3,817	2,200
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	54	63	62
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	2,219	'	'	'	1,189	'	'	'	2,219	1,189	0
Other Segments [Member] | External Customers [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	1,965	1,170	2,509
Other Segments [Member] | Intersegment [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	402	385	379
Intersegment Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	-1,816	-871	-1,090
Cost of products sold	'	'	'	'	'	'	'	'	($1,800)	($900)	($1,079)

Quarterly_Financial_Data_Detai

Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	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	$12,032	$11,902	$11,551	$10,854	$10,981	$1,802	$1,596	$1,323	$46,339	$15,702	$6,799
Gross profit	1,305	1,248	1,322	1,260	1,321	776	797	542	5,135	3,436	'
Operating income	-151	526	632	534	463	365	357	209	1,541	1,394	1,247
Net Income	-473	404	413	424	361	64	135	1,088	768	1,648	697
Limited Partners' interest in net income (loss)	-666	209	165	194	188	-80	2	998	-98	1,108	236
Basic net income (loss) per limited partner unit	($1.90)	$0.55	$0.53	$0.63	$0.62	($0.33)	$0	$4.36	($0.18)	$4.43	$1.10
Diluted net income (loss) per Limited Partner unit	($1.90)	$0.55	$0.53	$0.63	$0.62	($0.33)	$0	$4.35	($0.18)	$4.42	$1.10
Excess of distribution made above net income	$1,120	'	'	'	'	$356	$223	'	'	'	'

Quarterly_Financial_Data_Quart

Quarterly Financial Data Quarterly Narrative (Details) (USD $)	3 Months Ended			12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill impairment	'	'	'	$689	$0	$0
Excess of distribution made above net income	$1,120	$356	$223	'	'	'