Energy Transfer (ET) 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 18, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	1276187
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		538,772,023
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$22.91

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
ASSETS
Cash and cash equivalents	$847	$590
Accounts receivable, net	3,378	3,658
Accounts receivable from related companies	35	63
Inventories	1,467	1,807
Exchanges receivable	44	67
Price risk management assets	81	39
Other current assets	301	312
Total current assets	6,153	6,536
PROPERTY, PLANT AND EQUIPMENT	45,018	33,917
ACCUMULATED DEPRECIATION AND DEPLETION	-4,726	-3,235
PROPERTY, PLANT AND EQUIPMENT, net	40,292	30,682
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,659	4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	10	18
GOODWILL	7,865	5,894
INTANGIBLE ASSETS, net	5,582	2,264
OTHER NON-CURRENT ASSETS, net	908	922
Total assets	64,469	50,330
LIABILITIES AND EQUITY
Accounts payable	3,349	3,834
Accounts payable to related companies	19	14
Exchanges payable	184	284
Price risk management liabilities	21	53
Accrued and other current liabilities	2,201	1,678
Current maturities of long-term debt	1,008	637
Total current liabilities	6,782	6,500
LONG-TERM DEBT, less current maturities	29,653	22,562
DEFERRED INCOME TAXES	4,325	3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	154	73
OTHER NON-CURRENT LIABILITIES	1,193	1,019
COMMITMENTS AND CONTINGENCIES (Note 12)
REDEEMABLE NONCONTROLLING INTERESTS	15	0
PREFERRED UNITS OF SUBSIDIARY (Note 7)	33	32
Partners' Capital
General Partner	-1	-3
Limited Partners:
Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively)	648	1,066
Class D Units (1,540,000 units authorized, issued and outstanding)	22	6
Accumulated other comprehensive income (loss)	-5	9
Total partners’ capital	664	1,078
Noncontrolling interest	21,650	15,201
Total equity	22,314	16,279
Total liabilities and equity	$64,469	$50,330

Consolidated_Balance_Sheets_Ba

Consolidated Balance Sheets Balance Sheet (Paranthetical)	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Authorized	538,766,899	559,923,300
Issued	538,766,899	559,923,300
Outstanding	538,766,899	559,923,300
Class D Units [Member]
Class of Stock [Line Items]
Authorized	1,540,000	1,540,000
Issued	1,540,000	1,540,000
Outstanding	1,540,000	1,540,000

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Natural gas sales	$5,386	$3,842	$2,705
NGL sales	5,845	3,618	2,253
Crude sales	16,416	15,477	2,872
Gathering, transportation and other fees	3,733	3,097	2,386
Refined product sales	19,437	18,479	5,299
Other	4,874	3,822	1,449
Total revenues	55,691	48,335	16,964
COSTS AND EXPENSES:
Cost of products sold	48,389	42,554	13,088
Operating expenses	2,127	1,695	1,118
Depreciation, depletion and amortization	1,724	1,313	871
Selling, general and administrative	611	533	527
Goodwill impairment	-370	-689	0
Total costs and expenses	53,221	46,784	15,604
OPERATING INCOME	2,470	1,551	1,360
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	-1,369	-1,221	-1,018
Bridge loan related fees	0	0	-62
Equity in earnings of unconsolidated affiliates	332	236	212
Gain on deconsolidation of Propane Business	0	0	1,057
Gain on sale of AmeriGas common units	177	87	0
Losses on extinguishments of debt	-25	-162	-123
Gains (losses) on interest rate derivatives	-157	53	-19
Non-operating environmental remediation	0	-168	0
Other, net	-11	-1	30
Income from continuing operations before income tax expense	1,417	375	1,437
Income tax expense from continuing operations	357	93	54
INCOME FROM CONTINUING OPERATIONS	1,060	282	1,383
Income (loss) from discontinued operations	64	33	-109
NET INCOME	1,124	315	1,274
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	491	119	970
NET INCOME ATTRIBUTABLE TO PARTNERS	633	196	304
GENERAL PARTNER’S INTEREST IN NET INCOME	2	0	2
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	2	0	0
LIMITED PARTNERS’ INTEREST IN NET INCOME	$629	$196	$302
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$1.15	$0.33	$0.59
Diluted	$1.14	$0.33	$0.59
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	$1.16	$0.35	$0.57
Diluted	$1.15	$0.35	$0.57

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income	$1,124	$315	$1,274
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	3	-4	-17
Change in value of derivative instruments accounted for as cash flow hedges	0	-1	12
Change in value of available-for-sale securities	1	2	0
Actuarial gain (loss) relating to pension and other postretirement benefits	-113	66	-10
Foreign currency translation adjustment	-2	-1	0
Change in other comprehensive income from unconsolidated affiliates	-6	17	-9
Other comprehensive income (loss), net of tax, total	-117	79	-24
Comprehensive income	1,007	394	1,250
Less: Comprehensive income attributable to noncontrolling interest	388	181	959
Comprehensive income attributable to partners	$619	$213	$291

Consolidated_Statement_Of_Equi

Consolidated Statement Of Equity (USD $)	Total	General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member]
In Millions, unless otherwise specified								General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]		General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]		General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2011	$7,388	$0	$52	$0	$1	$7,335
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	-666	-2	-664	0	0	0
Distributions to noncontrolling interest	-1,017	0	0	0	0	-1,017
Units issued in Merger	2,354	0	2,354	0	0	0	2,295
Subsidiary equity offerings, net of issue costs	1,103	0	33	0	0	1,070
Subsidiary unit transactions	2,295	0	47	0	0	2,248
Non-cash compensation expense, net of units tendered by employees for tax withholdings	32	0	1	0	0	31
Capital contributions received from noncontrolling interest	42	0	0	0	0	42
ETP Holdco Transaction (see Note 3)	3,580	0	0	0	0	3,580
Other, net	-11	0	0	0	0	-11
Other comprehensive income, net of tax	-24	0	0	0	-13	-11
Net income	1,274	2	302	0	0	970
Balance at Dec. 31, 2012	16,350	0	2,125	0	-12	14,237
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	-733	-2	-731	0	0	0
Distributions to noncontrolling interest	-1,428	0	0	0	0	-1,428
Units issued in Merger	0						0
Subsidiary equity offerings, net of issue costs	1,759	0	122	0	0	1,637
Subsidiary unit transactions	0	-1	-506	0	0	507
Non-cash compensation expense, net of units tendered by employees for tax withholdings	54	0	1	6	0	47
Capital contributions received from noncontrolling interest	18	0	0	0	0	18
Other, net	-35	0	0	0	4	-39
Conversion of Regency Preferred Units for Regency Common Units	41	0	0	0	0	41
Deemed distribution related to SUGS Transaction	-141	0	-141	0	0	0
Other comprehensive income, net of tax	79	0	0	0	17	62
Net income	315	0	196	0	0	119
Balance at Dec. 31, 2013	16,279	-3	1,066	6	9	15,201
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	-821	-2	-817	-2	0	0
Distributions to noncontrolling interest	-1,905	0	0	0	0	-1,905
Units issued in Merger	0						0
Subsidiary unit transactions							5,815	0	211	0	0	5,604	0	0	-99	0	0	99	3,057	0	148	2	0	2,907
Capital contributions received from noncontrolling interest	139	0	0	0	0	139
Other, net	-3	0	30	0	0	-33
Other comprehensive income, net of tax	-117	0	0	0	-14	-103
Net income	1,124	2	629	2	0	491
Cash paid for acquisition of a noncontrolling interest	-319	0	0	0	0	-319
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	0	2	480	0	0	-482
Partners' Capital Account, Unit-based Compensation	65	0	0	14	0	51
Stock Repurchased During Period, Value	-1,000	0	-1,000	0	0	0
Balance at Dec. 31, 2014	$22,314	($1)	$648	$22	($5)	$21,650

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$1,124	$315	$1,274
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,724	1,313	871
Deferred income taxes	-50	43	51
Amortization included in interest expense	-51	-55	-13
Bridge loan related fees	0	0	62
Non-cash compensation expense	82	61	47
Gain on sale of AmeriGas common units	-177	-87	0
Gain on deconsolidation of Propane Business	0	0	1,057
Gain on curtailment of other postretirement benefit plans	0	0	15
Goodwill impairment	370	689	0
Losses on extinguishments of debt	25	162	123
Losses on disposal of assets	-1	2	4
Equity in earnings of unconsolidated affiliates	-332	-236	-212
Distributions from unconsolidated affiliates	291	313	208
Inventory valuation adjustments	473	-3	75
Other non-cash	-72	51	211
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2)	-231	-149	-551
Net cash provided by operating activities	3,175	2,419	1,078
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions	-2,367	-405	-10
Cash proceeds from contribution and sale of propane operations	0	0	1,443
Cash proceeds from the sale of AmeriGas common units	814	346	0
Proceeds from the sale of discontinued operations	77	1,008	207
Proceeds from the sale of other assets	62	89	44
Capital expenditures (excluding allowance for equity funds used during construction)	-5,381	-3,505	-3,271
Contributions in aid of construction costs	45	52	35
Contributions to unconsolidated affiliates	-334	-3	-37
Distributions from unconsolidated affiliates in excess of cumulative earnings	136	419	189
Change in restricted cash	172	-348	5
Other	-19	0	171
Net cash used in investing activities	-6,795	-2,347	-4,196
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	18,375	12,934	12,870
Repayments of long-term debt	-13,886	-11,951	-8,848
Subsidiary equity offerings, net of issue costs	3,057	1,759	1,103
Distributions to partners	-821	-733	-666
Distributions to noncontrolling interests	-1,905	-1,428	-1,017
Debt issuance costs	-77	-87	-112
Capital contributions received from noncontrolling interest	139	18	42
Redemption of Preferred Units	0	-340	0
Units repurchased under buyback program	-1,000	0	0
Other, net	-5	-26	-8
Net cash provided by financing activities	3,877	146	3,364
INCREASE IN CASH AND CASH EQUIVALENTS	257	218	246
CASH AND CASH EQUIVALENTS, beginning of period	590	372	126
CASH AND CASH EQUIVALENTS, end of period	847	590	372
SUG Merger [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions	$0	$0	($2,972)

Operations_And_Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2014
Operations And Organization [Abstract]
Operations And Organization	OPERATIONS AND ORGANIZATION:
	Financial Statement Presentation
	The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2014, 2013 and 2012, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.
	As discussed in Note 9, in January 2014, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented.
	At December 31, 2014, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:
		ETP	Regency
	Units held by wholly-owned subsidiaries:
	Common units	30.8	57.2
	ETP Class H units	50.2	—
	Units held by less than wholly-owned subsidiaries:
	Common units	—	31.4
	Regency Class F units	—	6.3
	The consolidated financial statements of ETE presented herein include the results of operations of:
	•	the Parent Company;
	•	our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);
	•	ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency; and
	•	our wholly-owned subsidiary, Lake Charles LNG. Lake Charles LNG was acquired from ETP in February 2014.
	Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
	Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.
	Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Regency, Regency GP, Regency LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco, Inc., Sunoco Logistics, Sunoco LP, Susser and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
	In 2014, our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.
	Business Operations
	The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.
	Our activities are primarily conducted through our operating subsidiaries as follows:
	•	ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries:
	•	ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
	•	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.
	•	ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:
	•	Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, 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, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.
	•	Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
	•	ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3, in October 2014, Sunoco LP acquired MACS from ETP.
	•	Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; the gathering and disposing of salt water; natural gas and NGL marketing and trading; and the management of coal and natural resource properties in the United States. Regency provides midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are located in Texas, Louisiana, Arkansas, West Virginia, Pennsylvania, Ohio, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.
	•	Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.
	Subsequent to the Lake Charles LNG Transaction in February 2014, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; Investment in Lake Charles LNG; and Corporate and Other.

Estimates_Significant_Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Estimates, Significant Accounting Policies and Balance Sheet Detail	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
	The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for 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, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.
	New Accounting Pronouncements
	In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.
	In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations.  Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results.  ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.
	Revenue Recognition
	Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
	Investment in ETP
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.
	In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.
	Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and gross margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
	ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
	ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	ETP’s retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’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 recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
	Investment in Regency
	Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
	Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.
	Investment in Lake Charles LNG
	Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
	Regulatory Accounting – Regulatory Assets and Liabilities
	ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
	Cash, Cash Equivalents and Supplemental Cash Flow Information
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
	We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
	The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
		Years Ended December 31,
		2014				2013			2012
	Accounts receivable	$	600			$	(556	)	$	267
	Accounts receivable from related companies	30				64			(9		)
	Inventories	51				(254		)	(258		)
	Exchanges receivable	18				(8		)	14
	Other current assets	133				(81		)	597
	Other non-current assets, net	(6		)		(23		)	(129		)
	Accounts payable	(850		)		541			(989		)
	Accounts payable to related companies	5				(140		)	92
	Exchanges payable	(99		)		128			—
	Accrued and other current liabilities	(59		)		192			(159		)
	Other non-current liabilities	(73		)		147			26
	Price risk management assets and liabilities, net	19				(159		)	(3		)
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(231	)		$	(149	)	$	(551	)
	Non-cash investing and financing activities and supplemental cash flow information were as follows:
		Years Ended December 31,
		2014				2013			2012
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	643			$	226		$	420
	Net gains (losses) from subsidiary common unit transactions	$	744			$	(384	)	$	80
	AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	—			$	—		$	1,123
	NON-CASH FINANCING ACTIVITIES:
	Issuance of Common Units in connection with Southern Union Merger (see Note 3)	$	—			$	—		$	2,354
	Subsidiary issuance of common units in connection with certain acquisitions	$	—			$	—		$	2,295
	Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions	$	4,281			$	—		$	—
	Subsidiary issuances of common units in connection with the Susser Merger	$	908			$	—		$	—
	Long-term debt assumed in PVR Acquisition	$	1,887			$	—		$	—
	Long-term debt exchanged in Eagle Rock Midstream Acquisition	$	499			$	—		$	—
	SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,416			$	1,256		$	997
Cash paid for income taxes	$	345			$	58		$	23
Accounts Receivable
Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.
Inventories
Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Inventories consisted of the following:
	December 31,
	2014				2013
Natural gas and NGLs	$	392			$	577
Crude oil	364				488
Refined products	392				543
Appliances, parts and fittings and other	319				199
Total inventories	$	1,467			$	1,807
During the year ended December 31, 2014, the Partnership recorded write downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs.
ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.
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,
	2014				2013
Deposits paid to vendors	$	65			$	49
Deferred income taxes	14				—
Prepaid expenses and other	222				263
Total other current assets	$	301			$	312
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
	December 31,
	2014				2013
Land and improvements	$	1,307			$	881
Buildings and improvements (1 to 45 years)	1,922				939
Pipelines and equipment (5 to 83 years)	27,149				21,494
Natural gas and NGL storage facilities (5 to 46 years)	1,214				1,083
Bulk storage, equipment and facilities (2 to 83 years)	4,010				1,933
Tanks and other equipment (5 to 40 years)	58				1,697
Retail equipment (2 to 99 years)	515				450
Vehicles (1 to 25 years)	203				156
Right of way (20 to 83 years)	2,451				2,190
Furniture and fixtures (2 to 25 years)	59				51
Linepack	119				118
Pad gas	44				52
Natural resources	454				—
Other (1 to 30 years)	999				708
Construction work-in-process	4,514				2,165
	45,018				33,917
Less – Accumulated depreciation and depletion	(4,726		)		(3,235		)
Property, plant and equipment, net	$	40,292			$	30,682
We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:
	Years Ended December 31,
	2014				2013			2012
Depreciation expense	$	1,457			$	1,128		$	801
Capitalized interest, excluding AFUDC	$	113			$	43		$	99
Depletion expense related to Regency’s natural resources operations was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by Regency’s own geologists. Regency’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, Regency carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. Regency depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. Regency determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.
Advances to and Investments in Affiliates
Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations and during the fourth quarter for reporting units within ETP’s interstate transportation and storage and liquids transportation and services operations and all others, including all of Regency’s reporting units and Lake Charles LNG.
Changes in the carrying amount of goodwill were as follows:
	Investment in ETP				Investment in Regency			Investment in Lake Charles LNG			Corporate, Other and Eliminations			Total
Balance, December 31, 2012	$	5,606			$	1,127		$	873		$	(1,172	)	$	6,434
Goodwill acquired	156				—			—			—			156
Deconsolidation of SUGS (1)	(337		)		—			—			337			—
Goodwill impairment	(689		)		—			(689		)	689			(689		)
Other	(7		)		—			—			—			(7		)
Balance, December 31, 2013	4,729				1,127			184			(146		)	5,894
Goodwill acquired	1,874				449			—			—			2,323
Lake Charles LNG Transaction (2)	(184		)		—			—			184			—
Goodwill impairment	—				(370		)	—			—			(370		)
Other	—				17			—			1			18
Balance, December 31, 2014	$	6,419			$	1,223		$	184		$	39		$	7,865
(1)	As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013 which was a transaction between entities under common control. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012. Therefore, the December 31, 2012 goodwill balance includes goodwill attributable to SUGS of $337 million in both segments that was correspondingly included in the elimination column. ETP deconsolidated SUGS on April 30, 2013.
(2)	As discussed in Note 3, ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2012 and 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $873 million and$184 million, respectively, in both the investment in ETP and investment in Lake Charles LNG segments that was correspondingly included in the elimination column. The transaction was effective January 1, 2014.
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net increase in goodwill of $1.97 billion during the year ended December 31, 2014 primarily due to the Susser Merger and PVR Acquisition where we recorded goodwill of $1.73 billion and $370 million, respectively, offset by an impairment of $370 million. The additional goodwill recorded during the years ended December 31, 2014 and 2013 is not expected to be deductible for tax purposes.
During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting unit was primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. An assessment of these factors in the fourth quarter of 2014 led to a conclusion that the estimated fair value of Regency’s Permian reporting unit was less than its carrying amount.
During the fourth quarter of 2013, ETP performed a goodwill impairment test on its Lake Charles LNG reporting unit. In accordance with GAAP, ETP performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles 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 Lake Charles 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 Lake Charles LNG reporting unit was less than its carrying amount.  ETP then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, ETP estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, ETP used current replacement costs adjusted for assumed depreciation. ETP also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. ETP adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, ETP recorded a goodwill impairment of $689 million during the fourth quarter of 2013.
No other goodwill impairments were identified or recorded for our reporting units.
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
	December 31, 2014							December 31, 2013
	Gross Carrying				Accumulated			Gross Carrying			Accumulated
	Amount				Amortization			Amount			Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	5,144			$	(485	)	$	2,135		$	(264	)
Trade names (15 to 20 years)	556				(15		)	66			(12		)
Patents (9 years)	48				(11		)	48			(6		)
Other (1 to 15 years)	36				(7		)	7			(4		)
Total amortizable intangible assets	5,784				(518		)	2,256			(286		)
Non-amortizable intangible assets:
Trademarks	316				—			294			—
Total intangible assets	$	6,100			$	(518	)	$	2,550		$	(286	)
Aggregate amortization expense of intangibles assets was as follows:
	Years Ended December 31,
	2014				2013			2012
Reported in depreciation, depletion and amortization	$	219			$	120		$	70
Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
Years Ending December 31:
2015	$	263
2016	260
2017	260
2018	259
2019	256
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,
	2014				2013
Unamortized financing costs (3 to 30 years)	$	203			$	167
Regulatory assets	85				86
Deferred charges	220				144
Restricted funds	177				378
Other	223				147
Total other non-current assets, net	$	908			$	922
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
Asset Retirement Obligations
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 certain amounts recorded by Panhandle, Sunoco Logistics and ETP’s retail marketing operations. discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2014 and 2013, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’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, Inc. has legal asset retirement obligations for several other assets at its previously owned 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, Inc. 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 segment recorded as other non-current liabilities in our consolidated balance sheets:
	December 31,
	2014				2013
Investment in ETP:
Interstate transportation and storage operations	$	58			$	55
Retail marketing operations	87				84
Investment in Sunoco Logistics	41				41
Investment in Regency	2				—
	$	188			$	180
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, 2014, 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,
	2014				2013
Interest payable	$	440			$	357
Customer advances and deposits	103				142
Accrued capital expenditures	673				260
Accrued wages and benefits	233				173
Taxes payable other than income taxes	236				211
Income taxes payable	54				4
Deferred income taxes	99				119
Other	363				412
Total accrued and other current liabilities	$	2,201			$	1,678
Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2014 was $31.68 billion and $30.66 billion, respectively. As of December 31, 2013, the aggregate fair value and carrying amount of our consolidated debt obligations was $23.97 billion and $23.20 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives, the Preferred Units, the preferred units of a subsidiary and embedded derivatives in the preferred units of a subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.
The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2014 and 2013 based on inputs used to derive their fair values:
	Fair Value Measurements  at
	31-Dec-14
	Fair Value				Level 1			Level 2			Level 3
	Total
Assets:
Interest rate derivatives	$	3			$	—		$	3		$	—
Commodity derivatives:
Condensate — Forward Swaps	36				—			36			—
Natural Gas:
Basis Swaps IFERC/NYMEX	19				19			—			—
Swing Swaps IFERC	26				1			25			—
Fixed Swaps/Futures	566				541			25			—
Forward Physical Contracts	1				—			1			—
Power:
Forwards	3				—			3			—
Futures	4				4			—			—
Natural Gas Liquids — Forwards/Swaps	69				46			23			—
Refined Products — Futures	21				21			—			—
Total commodity derivatives	745				632			113			—
Total assets	$	748			$	632		$	116		$	—
Liabilities:
Interest rate derivatives	$	(155	)		$	—		$	(155	)	$	—
Embedded derivatives in the Regency Preferred Units	(16		)		—			—			(16		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)		(18		)	—			—
Swing Swaps IFERC	(25		)		(2		)	(23		)	—
Fixed Swaps/Futures	(490		)		(490		)	—			—
Power:
Forwards	(4		)		—			(4		)	—
Futures	(2		)		(2		)	—			—
Natural Gas Liquids — Forwards/Swaps	(32		)		(32		)	—			—
Refined Products — Futures	(7		)		(7		)	—			—
Total commodity derivatives	(578		)		(551		)	(27		)	—
Total liabilities	$	(749	)		$	(551	)	$	(182	)	$	(16	)
	Fair Value Measurements  at
	31-Dec-13
	Fair Value				Level 1			Level 2			Level 3
	Total
Assets:
Interest rate derivatives	$	47			$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5				5			—			—
Swing Swaps IFERC	8				1			7			—
Fixed Swaps/Futures	203				201			2			—
Natural Gas Liquids — Forwards/Swaps	7				5			2			—
Power — Forwards	3				—			3			—
Refined Products – Futures	5				5			—			—
Total commodity derivatives	231				217			14			—
Total assets	$	278			$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)		$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)		—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)		—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)		(4		)	—			—
Swing Swaps IFERC	(6		)		—			(6		)	—
Fixed Swaps/Futures	(206		)		(201		)	(5		)	—
Forward Physical Contracts	(1		)		—			(1		)	—
Natural Gas Liquids — Forwards/Swaps	(9		)		(5		)	(4		)	—
Power — Forwards	(1		)		—			(1		)	—
Refined Products – Futures	(5		)		(5		)	—			—
Total commodity derivatives	(233		)		(215		)	(18		)	—
Total liabilities	$	(347	)		$	(215	)	$	(113	)	$	(19	)
At December 31, 2013, the fair value of the Lake Charles 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 Lake Charles 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.
The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:
	Unobservable Input		December 31, 2014
Embedded derivatives in the Regency Preferred Units	Credit Spread		4.76	%
	Volatility		35.8	%
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2014. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2014 or 2013.
Balance, December 31, 2013	$	(19	)
Net unrealized gains included in other income (expense)	3
Balance, December 31, 2014	$	(16	)
Contributions in Aid of Construction Cost
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses
Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by ETP’s retail marketing operations were $2.46 billion, $2.22 billion and $573 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2014, 2013 and 2012, 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. These corporate subsidiaries include Susser and ETP Holdco, which owns Sunoco, Inc. and Panhandle. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in gains (losses) on interest rate derivatives in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in equity or are reflected as a regulatory asset or regulatory liability for regulated entities.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

Acquisitions_and_Related_Trans

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2014
Acquisitions and Dispositions [Abstract]
Acquisitions and Related Transactions	ACQUISITIONS AND RELATED TRANSACTIONS:
	Pending Transaction
	Regency Merger
	In January 2015, ETP and Regency entered into a definitive merger agreement, as amended on February 18, 2015 (the “Merger Agreement”), pursuant to which Regency will merge with a wholly-owned subsidiary of ETP, with Regency continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders.
	In addition, ETE, which owns the general partner and 100% of the incentive distribution rights of both Regency and ETP, has agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five year period. The IDR subsidy will be $80 million in the first year post closing and $60 million per year for the following four years. The transaction is expected to close in the second quarter of 2015.
	ETP and Regency are under common control of ETE; therefore, we expect to account for the Regency Merger at historical cost as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Regency beginning May 26, 2010 (the date ETE acquired Regency’s general partner).
	2014 Transactions
	Susser Merger
	In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.
	In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
	Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
	Summary of Assets Acquired and Liabilities Assumed
	We accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.
	The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:
			Susser
	Total current assets		$	446
	Property, plant and equipment		1,069
	Goodwill(1)		1,734
	Intangible assets		611
	Other non-current assets		17
			3,877
	Total current liabilities		377
	Long-term debt, less current maturities		564
	Deferred income taxes		488
	Other non-current liabilities		39
	Noncontrolling interest		626
			2,094
	Total consideration		1,783
	Cash received		67
	Total consideration, net of cash received		$	1,716
	(1)	None of the goodwill is expected to be deductible for tax purposes.
	The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
	ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
	No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.
	MACS to Sunoco LP
	In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
	Lake Charles LNG Transaction
	On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). The transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.
	In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles 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 9.
	Panhandle Merger
	On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, 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 material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (2.2 million ETP Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.
	Regency’s Acquisition of PVR Partners, L.P.
	On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the PVR Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
	Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
	Assets	At March 21, 2014
	Current assets	$	149
	Property, plant and equipment	2,716
	Investment in unconsolidated affiliates	62
	Intangible assets (average useful life of 30 years)	2,717
	Goodwill	370
	Other non-current assets	18
	Total assets acquired	6,032
	Liabilities
	Current liabilities	168
	Long-term debt	1,788
	Premium related to senior notes	99
	Non-current liabilities	30
	Total liabilities assumed	2,085
	Net assets acquired	$	3,947
	The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
	Regency’s Acquisition of Eagle Rock’s Midstream Business
	On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Regency accounted for the Eagle Rock Midstream Acquisition 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. This acquisition complements Regency’s core gathering and processing business and further diversifies Regency’s geographic presence in the Mid-Continent region, east Texas and south Texas. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
	Regency’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
	Assets	At July 1, 2014
Current assets	$	120
Property, plant and equipment	1,295
Other non-current assets	4
Goodwill(1)	49
Total assets acquired	1,468
Liabilities
Current liabilities	116
Long-term debt	499
Other non-current liabilities	12
Total liabilities assumed	627
Net assets acquired	$	841
(1)	None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of Hoover Energy
On February 3, 2014, Regency completed its acquistion of certain subsidiaries of Hoover Energy for a total purchase price of $293 million, consisted of (i) 4.0 million Regency Common Units issued to Hoover Energy, (ii) $184 million in cash. and (iii) $2 million in asset retirement obligations assumed.
2013 Transactions
Sale of Southern Union’s Distribution Operations
In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.
In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations.
The 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, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.
ETP’s Acquisition of ETE’s ETP Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP 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 “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP 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 ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE until our contribution to ETP Holdco discussed below.
Under the terms of the merger agreement, Southern Union stockholders received a total of approximately 57 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received a total of approximately 55 million ETP Common Units and a total of approximately $2.6 billion in cash.
Sunoco, Inc. 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, Inc. 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, Inc.’s interests in Sunoco Logistics were transferred to ETP.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. 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, L.P. (“The Carlyle Group”). Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex 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, Inc. retained an approximately 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’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, Inc. 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 provides 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, Inc. 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, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’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.
ETP Holdco Transaction
Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million Class F Units representing limited partner interests in ETP (“ETP Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 9. Pursuant to a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation of the ETP Holdco Transaction.
Under the terms of the ETP Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Southern Union Merger and Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
	Sunoco, Inc.(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.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.
Propane Operations
On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.
Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to ETP’s continuing involvement in this business through their investment in AmeriGas that was transferred to ETP as consideration for the transaction.
In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, ETP sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations. 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.
Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations.
	Years Ended December 31,
	2014			2013		2012
Revenues	$	56,517		$	50,473	$	40,398
Net income	1,098			252		868
Net income attributable to partners	607			133		866
Basic net income per Limited Partner unit	$	1.12		$	0.24	$	1.55
Diluted net income per Limited Partner unit	$	1.11		$	0.24	$	1.55
The pro forma consolidated results of operations include adjustments to:
•	include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
•	include the results of PVR and Eagle Rock midstream beginning January 1, 2013;
•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and
•include incremental interest expense related to the financing of a proportionate share of the purchase price.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

Advances_to_and_Investments_in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2014
Investment In Affiliates [Abstract]
Investments In Affiliates	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
	AmeriGas
	As discussed in Note 3, on January 12, 2012, ETP received approximately 29.6 million AmeriGas common units in connection with the contribution of its propane operations. In the year ended 2013, ETP sold 7.5 million AmeriGas common units for net proceeds of $346 million, and in the year ended 2014, ETP sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
	Citrus
	On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
	ETP recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of ETP’s investment in Citrus was $1.82 billion and $1.89 billion at December 31, 2014 and 2013, respectively, and was reflected in ETP’s interstate transportation and storage operations.
	FEP
	ETP has a 50% interest in FEP, a 50/50 joint venture with Kinder Morgan, Inc. FEP owns the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The carrying amount of ETP’s investment in FEP was $130 million and $144 million as of December 31, 2014 and 2013, respectively, and was reflected in ETP’s interstate transportation and storage operations.
	Midcontinent Express Pipeline LLC
	Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. The carrying amount of Regency’s investment in MEP was $695 million and $548 million as of December 31, 2014 and 2013, respectively, and was reflected in Regency’s natural gas transportation operations.
	RIGS Haynesville Partnership Co.
	Regency owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. The carrying amount of Regency’s investment in HPC was $422 million and $442 million as of December 31, 2014 and 2013, respectively, and was reflected in Regency’s natural gas transportation operations.
	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).
		December 31,
		2014		2013
	Current assets	$	889	$	1,028
	Property, plant and equipment, net	10,520		10,778
	Other assets	2,687		2,664
	Total assets	$	14,096	$	14,470
	Current liabilities	$	1,983	$	1,039
	Non-current liabilities	7,359		8,139
	Equity	4,754		5,292
	Total liabilities and equity	$	14,096	$	14,470
		Years Ended December 31,
		2014		2013		2012
	Revenue	$	4,925	$	4,695	$	4,492
	Operating income	1,071		1,197		863
	Net income	577		699		491
	In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Net Income Per Limited Partner Unit	NET INCOME PER LIMITED PARTNER UNIT:
	Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of our Preferred Units, see Note 7. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Regency that would have resulted assuming the incremental units related to ETP’s or Regency’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
	The calculation below for the year ended December 31, 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units were redeemed April 1, 2013 as discussed in Note 7.
	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
		Years Ended December 31,
		2014			2013		2012
	Income from continuing operations	$	1,060		$	282	$	1,383
	Less: Income from continuing operations attributable to noncontrolling interest	434			99		1,070
	Income from continuing operations, net of noncontrolling interest	626			183		313
	Less: General Partner’s interest in income from continuing operations	2			—		1
	Less: Class D Unitholder’s interest in income from continuing operations	2			—		—
	Income from continuing operations available to Limited Partners	$	622		$	183	$	312
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	544.3			560.9		533.4
	Basic income from continuing operations per Limited Partner unit	$	1.15		$	0.33	$	0.59
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.01		$	0.02	$	(0.02	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	622		$	183	$	312
	Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(2		)	—		(1		)
	Diluted income from continuing operations available to Limited Partners	620			183		311
	Weighted average limited partner units	544.3			560.9		533.4
	Dilutive effect of unconverted unit awards	1.1			—		—
	Weighted average limited partner units, assuming dilutive effect of unvested unit awards	545.4			560.9		533.4
	Diluted income from continuing operations per Limited Partner unit	$	1.14		$	0.33	$	0.59
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.01		$	0.02	$	(0.02	)

Debt_Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2014
Debt Obligations [Abstract]
Debt Obligations	DEBT OBLIGATIONS:
	Our debt obligations consist of the following:
		December 31,
		2014			2013
	Parent Company Indebtedness:
	7.50% Senior Notes, due October 15, 2020	$	1,187		$	1,187
	5.875% Senior Notes, due January 15, 2024	1,150			450
	ETE Senior Secured Term Loan, due December 2, 2019	1,400			1,000
	ETE Senior Secured Revolving Credit Facility due December 18, 2018	940			171
	Unamortized premiums, discounts and fair value adjustments, net	3			(7		)
		4,680			2,801
	Subsidiary Indebtedness:
	ETP Debt
	8.5% Senior Notes due April 15, 2014	—			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			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			800
	4.9% Senior Notes due February 1, 2024	350			350
	7.6% Senior Notes due February 1, 2024	277			277
	8.25% Senior Notes due November 15, 2029	267			267
	6.625% Senior Notes due October 15, 2036	400			400
	7.5% Senior Notes due July 1, 2038	550			550
	6.05% Senior Notes due June 1, 2041	700			700
	6.5% Senior Notes due February 1, 2042	1,000			1,000
	5.15% Senior Notes due February 1, 2043	450			450
	5.95% Senior Notes due October 1, 2043	450			450
	Floating Rate Junior Subordinated Notes due November 1, 2066	546			546
	ETP $2.5 billion Revolving Credit Facility due October 27, 2019	570			65
	Unamortized premiums, discounts and fair value adjustments, net	(1		)	(34		)
		11,459			11,213
	Panhandle Debt(1)
	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
	7.60% Senior Notes due February 1, 2024	82			82
	7.00% Senior Notes due July 15, 2029	66			66
	8.25% Senior Notes due November 14, 2029	33			33
	Floating Rate Junior Subordinated Notes due November 1, 2066	54			54
	Unamortized premiums, discounts and fair value adjustments, net	99			155
		1,184			1,240
	Regency Debt
	6.875% Senior Notes due December 1, 2018	—			600
	5.75% Senior Notes due September 1, 2020	400			400
	6.5% Senior Notes due July 15, 2021	500			500
	5.875% Senior Notes due March 1, 2022	900			—
	5.5% Senior Notes due April 15, 2023	700			700
	4.5% Senior Notes due November 1, 2023	600			600
	8.375% Senior Notes due June 1, 2020	390			—
	6.5% Senior Notes due May 15, 2021	400			—
	8.375% Senior Notes due June 1, 2019	499			—
	5.0% Senior Notes due October 1, 2022	700			—
	Regency $1.2 billion Revolving Credit Facility due November 25, 2019	1,504			510
	Unamortized premiums, discounts and fair value adjustments, net	48			—
		6,641			3,310
	Sunoco, Inc. Debt
	4.875% Senior Notes due October 15, 2014	—			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	35			70
	750			1,035
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014(2)	—			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			350
4.25% Senior Notes due April 1, 2024	500			—
6.85% Senior Notes due February 1, 2040	250			250
6.10% Senior Notes due February 15, 2042	300			300
4.95% Senior Notes due January 15, 2043	350			350
5.30% Senior Notes due April 1, 2044	700			—
5.35% Senior Notes due May 15, 2045	800			—
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3)	35			35
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018	150			200
Unamortized premiums, discounts and fair value adjustments, net	100			118
	4,260			2,503
Sunoco LP Debt
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	683			—
	683			—
Transwestern Debt
5.39% Senior Notes due November 17, 2014	—			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		)
	781			869
Other	223			228
	30,661			23,199
Less: current maturities	1,008			637
	$	29,653		$	22,562
(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.
(3)	The Sunoco Logistics $35 million credit facility outstanding amounts were classified as long-term debt as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $283 million in unamortized premiums and fair value adjustments, net:
2015	$	1,050
2016	314
2017	1,228
2018	2,095
2019	5,662
Thereafter	20,029
Total	$	30,378
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
Notes and Debentures
ETE Senior Notes
The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.
The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.
As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP and Regency constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP and Regency are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein.
The Parent Company’s interests in ETP GP, ETE Common Holdings, LLC, ETE GP Acquirer LLC, and Regency GP LP (collectively, the “Non-Reporting Entities”) also constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting Entities would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities has substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP, Regency and/or the consolidated subsidiaries of ETP and Regency. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP and Regency, as applicable:
•	ETP GP owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $11.9 billion and $11.3 billion as of December 31, 2014 and 2013, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders and Class H unitholders) of $823 million, $(50) million and $1.11 billion for the years ended December 31, 2014, 2013 and 2012, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.
•	ETE Common Holdings, LLC (“ETE Common Holdings”) owns 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owns 30.9 million Regency Common Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. ETE Common Holdings does not own the general partner interests in ETP or Regency; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP and Regency. The carrying values of ETE Common Holdings’ investments in ETP and Regency were $1.72 billion and $760 million, respectively, as of December 31, 2014 and $1.66 billion and zero, respectively, as of December 31, 2013. ETE Common Holdings’ equity in earnings (losses) from its investments in ETP and Regency were $292 million and $(9) million, respectively, for the year ended December 31, 2014 and $134 million and zero, respectively, for the period from April 26, 2013 (inception of ETE Common Holdings) to December 31, 2013.
•	ETE GP Acquirer LLC (“ETE GP Acquirer”) owns 100% of Regency GP, which owns 100% of the general partner interest in Regency. Neither ETE GP Acquirer nor Regency GP own limited partner interests in Regency; therefore, the limited partner interests in Regency, which had a carrying value of $8.7 billion and $4.0 billion as of December 31, 2014 and 2013, respectively, would be reflected as noncontrolling interests on ETE GP Acquirer’s and Regency GP’s balance sheets. Likewise, Regency’s income (loss) attributable to limited partners and preferred unitholders, which totaled $(188) million, $8 million and $23 million for the years ended December 31, 2014, 3013 and 2012, respectively, would be reflected as income attributable to noncontrolling interest in ETE GP Acquirer’s and Regency GP’s statements of operations.
ETP’s general partner interest, Common Units and Class H Units are reflected separately in ETP’s financial statements, and Regency’s general partner interest and Common Units are reflected separately in Regency’s financial statements. As a result, the financial statements of the Non-Reporting Entities would substantially duplicate information that is available in the financial statements of ETP and Regency. Therefore, the financial statements of the Non-Reporting Entities have been excluded from this Annual Report on Form 10-K.
ETP as Co-Obligor of Sunoco, Inc. Debt
In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $715 million as of December 31, 2014.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s 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 $54 million at an effective interest rate of 3.26% at December 31, 2014.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP 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 ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’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 payable semi-annually.
Sunoco Logistics Senior Notes Offerings
In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044.
In November 2014, Sunoco Logistics issued an additional $200 million under the April 2024 senior notes and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
Regency Senior Notes
The Regency senior notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency senior notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency senior notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.
In February 2014, Regency issued $900 million aggregate principal amount of 5.875% senior notes due March 1, 2022.
In March 2014, as part of the PVR Acquisition, Regency assumed the outstanding senior notes of PVR with an aggregate notional amount of $1.2 billion. The PVR senior notes consisted of $300 million principal amount of 8.25% senior notes due April 15, 2018, $400 million principal amount of 6.5% senior notes due May 15, 2021, and $473 million principal amount of 8.375% senior notes due June 1, 2020. In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million, including $8 million of accrued interest and redemption premium.
In July 2014, Regency exchanged $499 million aggregate principal amount of 8.375% senior notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% senior notes due 2019 issued by Regency and its wholly-owned subsidiary.
In July 2014, Regency issued $700 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.
In December 2014, Regency redeemed all of the outstanding $600 million senior notes due 2018, for a total price of $621 million.
Term Loans and Credit Facilities
ETE Term Loan Facility
The Parent Company has a Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”), which has a scheduled maturity date of December 2, 2019, with an option to extend the term subject to the terms and conditions set forth therein. Pursuant to the ETE Term Credit Agreement, the lenders have provided senior secured financing in an aggregate principal amount of $1.0 billion (the “ETE Term Loan Facility”). The Parent Company shall not be required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances, the Partnership is required to repay the term loan in connection with dispositions of (a) incentive distribution rights in ETP or Regency, (b) general partnership interests in Regency or (c) equity interests of any Person which owns, directly or indirectly, incentive distribution rights in ETP or Regency or general partnership interests in Regency, in each case, yielding net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Term Loan Facility initially is not guaranteed by any of the Parent Company’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The applicable margin for LIBOR rate loans is 2.50% and the applicable margin for base rate loans is 1.50%.
In April 2014, the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement, including maturity date and interest rate.
ETE Revolving Credit Facility
The Parent Company has a credit agreement (the “Revolving Credit Agreement”) which has a scheduled maturity date of December 2, 2018, with an option for the Partnership to extend the term subject to the terms and conditions set forth therein.
Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $600 million at any one time outstanding (the “ETE Revolving Credit Facility”), and the Parent Company has the option to request increases in the aggregate commitments provided that the aggregate commitments never exceed $1.0 billion. In February 2014, the Partnership increased the capacity on the ETE Revolving Credit Facility to $800 million. In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. In February 2015, the Parent Company amended its revolving credit facility to increase the capacity to $1.5 billion.
As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit.
Under the Revolver Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments.
ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt. ETP uses the ETP Credit Facility to provide temporary financing for ETP’s growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
As of December 31, 2014, the ETP Credit Facility had $570 million outstanding, and the amount available for future borrowings was $1.81 billion after taking into account letters of credit of $121 million. The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 1.66%.
Regency Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $2.0 billion, with a $500 million incremental facility. The maturity date of the Regency Credit Facility is November 25, 2019.
As of December 31, 2014, Regency had a balance of $1.50 billion outstanding under the Regency Credit Facility in revolving credit loans and approximately $23 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2014, which is reduced by any letters of credit, was approximately $473 million. The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 2.17%.
The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.0%. The applicable margin ranges from 0.63% to 1.5% for base rate loans and 1.63% to 2.5% for Eurodollar loans.
Regency pays (i) a commitment fee ranging between 0.3% and 0.45% per annum for the unused portion of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 1.63% and 2.5% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.2% per annum of the average daily amount of its letter of credit exposure. In December 2011, Regency amended its credit facility to allow for additional investments in its joint ventures.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2014, the Sunoco Logistics Credit Facility had $150 million of outstanding borrowings.
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. At December 31, 2014, this credit facility had $35 million of outstanding borrowings.
Sunoco LP Credit Facility
In September 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (the “Sunoco LP Credit Facility”), which matures in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of December 31, 2014, the Sunoco LP Credit Facility had $683 million of outstanding borrowings.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The ETE Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The ETE Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:
•	Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to EBITDA (as defined in the agreements) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and
•	EBITDA to interest expense of not less than 1.5 to 1.
Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the ETP’s and certain of the ETP’s subsidiaries’ ability to, among other things:
•	incur indebtedness;
•	grant liens;
•	enter into mergers;
•	dispose of assets;
•	make certain investments;
•	make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);
•	engage in business substantially different in nature than the business currently conducted by ETP and its subsidiaries;
•	engage in transactions with affiliates; and
•	enter into restrictive agreements.
The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Regency
The Regency senior notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to:
•	incur additional indebtedness;
•	pay distributions on, or repurchase or redeem equity interests;
•	make certain investments;
•	incur liens;
•	enter into certain types of transactions with affiliates; and
•	sell assets, consolidate or merge with or into other companies.
If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to these covenants except that the lien covenant will continue to be applicable. ETP has advised Regency that it intends to provide an ETP guarantee with respect to the outstanding Regency senior notes upon the closing of the Regency Merger, and it is expected that this will result in the Regency senior notes being upgraded an investment grade rating by both Moody’s and SAP.
The Regency Credit Facility contains the following financial covenants:
•	Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.00 to 1.
•	Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 to 1.
•	Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.25 to 1.
The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:
•	incur indebtedness;
•	grant liens;
•	enter into sale and leaseback transactions;
•	make certain investments, loans and advances;
•	dissolve or enter into a merger or consolidation;
•	enter into asset sales or make acquisitions;
•	enter into transactions with affiliates;
•	prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);
•	issue capital stock or create subsidiaries; or
•	engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.
Covenants Related to Panhandle
Panhandle 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 Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle 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 Panhandle 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 Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’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 Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle 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 Panhandle’s cash management program; and limitations on Panhandle’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 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.
The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. 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 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility requires Sunoco LP to maintain a leverage ratio of not more than 5.50 to 1. The maximum leverage ratio is subject to upwards adjustment of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or a joint venture for a purchase price of not less than $50 million. Indebtedness under the Sunoco LP Credit Facility is secured by a security interest in, among other things, all of the Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing the Sunoco LP Credit Facility will be released.
Compliance With Our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2014.

Redeemable_Preferred_Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2014
Preferred Units, Preferred Partners' Capital Account [Abstract]
Redeemable Preferred Units	REDEEMABLE PREFERRED UNITS:
	ETE Preferred Units
	In connection with ETE’s acquisition of Regency’s general partner in 2010, ETE issued 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million. The Preferred Units were issued in a private placement at a stated price of $100 per unit and were entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit.
	On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units. Prior to the Redemption, on March 28, 2013, ETE paid the holder of the Preferred Units $40 million in cash in exchange for the holder relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.
	Prior to the April 1, 2013 Redemption, we recorded non-cash charges of approximately $9 million to increase the carrying value of the Preferred Units to the estimated fair value. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million.
	Preferred Units of Subsidiary
	Holders may elect to convert Regency Preferred Units to Regency Common Units at any time. In July 2013, certain holders of the Regency Preferred Units exercised their right to convert an aggregate 2,459,017 Series A Preferred Units into Regency Common Units. Concurrent with this transaction, a gain of $26 million was recognized in other income, net, related to the embedded derivative and reclassified $41 million from the Regency Preferred Units into Regency Common Units. As of December 31, 2014, the remaining Regency Preferred Units were convertible into 2,064,805 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon. The Regency Preferred Units received fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of Regency’s common unit distributions. Holders can elect to convert Regency Preferred Units into Regency Common Units into common units at any time in accordance with the partnership agreement.
	The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
		Regency		Amount
		Preferred
		Units
	Balance, January 1, 2013	4.4		$	73
	Regency Preferred Units converted into Regency Common Units	(2.5	)	(41		)
	Balance, December 31, 2013	1.9		$	32		(1	)
	Accretion to redemption value	N/A		1
	Balance, December 31, 2014	1.9		33
	(1)	This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Redeemable_Noncontrolling_Inte

Redeemable Noncontrolling Interest (Notes)	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interest [Abstract]
Redeemable Noncontrolling Interest [Table Text Block]	REDEEMABLE NONCONTROLLING INTERESTS:
	The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.

Equity

Equity	12 Months Ended
	Dec. 31, 2014
Partners' Capital Notes [Abstract]
Equity	EQUITY:
	Limited Partner Units
	Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”
	As of December 31, 2014, there were issued and outstanding 538.8 million Common Units representing an aggregate 99.46% limited partner interest in the Partnership.
	Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
	Common Units
	The change in ETE Common Units during the years ended December 31, 2014, 2013 and 2012 was as follows:
		Years Ended December 31,
		2014			2013			2012
	Number of Common Units, beginning of period	559.9			559.9			445.9
	Repurchase of common units under buyback program	(21.1	)		—			—
	Issuance of common units in connection with Southern Union Merger (See Note 3)	—			—			114
	Number of Common Units, end of period	538.8			559.9			559.9
	Common Unit Split
	On December 23, 2013, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “Unit Split”). The Unit Split was completed on January 27, 2014. The Unit Split was effected by a distribution of one ETE Common Unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014.
	Repurchase Program
	In December 2013, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 21.1 million ETE Common Units under this program through May 23, 2014, and the program was completed.
	In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements.
	Class D Units
	On May 1, 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 1,500,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 1,500,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate of 1,540,000 Class D Units of ETE, which number of Class D Units includes an additional 40,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.
	Under the terms of the Class D Unit Agreement, 30% of the Class D Units will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date.
	Sale of Common Units by Subsidiaries
	The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.
	Sale of Common Units by ETP
	The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
	Date		Number of			Price per ETP			Net Proceeds
			ETP Common			Unit
			Units
	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.
	ETP’s Equity Distribution Program
	From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
	In January 2013 and May 2013, ETP entered into equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the year ended December 31, 2014, ETP issued approximately 2.7 million units for $144 million, net of commissions of $2 million. No amounts of ETP Common Units remain available to be issued under the January 2013 and May 2013 equity distribution agreements.
	In May 2014 and November 2014, ETP entered into equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion, respectively. During the year ended December 31, 2014, ETP issued approximately 18.8 million units for $1.08 billion, net of commissions of $11 million. As of December 31, 2014, approximately $1.41 billion of ETP Common Units remained available to be issued under ETP’s currently effective equity distribution agreements.
	ETP’s Equity Incentive Plan Activity
	As discussed in Note 10, ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.
	ETP’s Distribution Reinvestment Program
	ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
	During the years ended December 31, 2014, 2013 and 2012, aggregate distributions of approximately $155 million, $109 million and $43 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.1 million ETP Common Units.
	As of December 31, 2014, a total of 7.3 million ETP Common Units remain available to be issued under the existing registration statement.
	ETP Class E Units
	These ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other than the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements.
	ETP Class G Units
	In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million ETP Class F Units issued in exchange for cash contributed by Sunoco, Inc. to ETP immediately prior to or concurrent with the closing of the Sunoco Merger. The ETP Class F Units generally did not have any voting rights. The ETP Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries (other than ETP Holdco) and available for distribution, up to a maximum of $3.75 per ETP Class F Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G Units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements.
	ETP Class H Units and Class I Units
	Currently Outstanding
	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.
	Pending Transaction
	In December 2014, ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP will also issue 100 ETP Class I Units, as described below. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016.
	In connection with the transaction, ETP will also issue 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the ETP Class I Units in an amount equal to the excess of the distribution amount set forth in the ETP Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “ETP Quarterly Distributions of Available Cash” in the column titled “Pro Forma for ETP Class H and Class I Units.”
	Sale of Common Units by Regency
	The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
	Date		Number of			Price per			Net Proceeds
			Regency Common			Regency Unit
			Units
	Mar-12		12.7			$	24.47		$	297
	Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	Regency issued 4.0 million, 140.4 million and 8.2 million Regency Common Units in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively.
	In June 2014, Regency sold 14.4 million Regency Common Units to a wholly-owned subsidiary of ETE for approximately $400 million. Proceeds from the issuance were used to pay down borrowings on the Regency Credit Facility, to redeem certain Regency senior notes and for general partnership purposes. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.
	Regency’s Equity Distribution Program
	From time to time, Regency has sold Regency Common Units through an equity distribution agreement. Such sales of Regency 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 June 2012, Regency entered into an equity distribution agreement with Citigroup Global Markets Inc. under which Regency may offer and sell Regency Common Units, representing limited partner interests, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. For the years ended December 31, 2014 and 2013, Regency received net proceeds of $34 million and $149 million, respectively, from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.
	In May 2014, Regency entered into an equity distribution agreement with a group of banks and investment companies under which Regency may offer and sell Regency Common Units, representing limited partner interests, for an aggregate offering price of up to $400 million, from time to time through this group of institutions, as sales agent for Regency. For the year ended December 31, 2014, Regency received net proceeds of $395 million from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remained available to be issued under this agreement and it is no longer effective.
In January 2015, Regency entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which Regency may offer and sell Regency Common Units for an aggregate offering price of up to $1 billion, from time to time through the Managers, as sales agent for Regency. Regency intends to use the net proceeds from the sale of Regency Common Units for general partnership purposes.
Sales of Common Units by Sunoco Logistics
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. During the year ended December 31, 2014, Sunoco Logistics received proceeds of $477 million, net of commissions of $5 million, from the issuance of 10.3 million common units pursuant to the equity distribution agreement, which were used for general partnership purposes.
Additionally, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facility and for general partnership purposes.
Sales of Common Units by Sunoco LP
In October 2014 and November 2014, Sunoco LP issued an aggregate total of 9.1 million common units in an underwritten public offering. Aggregate net proceeds of $405 million from the offering were used to repay amounts outstanding under the $1.25 billion Sunoco LP Credit Facility and for general partnership purposes.
Contributions to Subsidiaries
The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.
The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP. Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest. Regency GP’s interest in Regency’s distributions is reduced if Regency issues additional units and Regency GP does not contribute a proportionate amount of capital to Regency to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared during the years ended December 31, 2014, 2013 and 2012 were as follows:
Quarter Ended		Record Date		Payment Date		Rate
31-Dec-11		7-Feb-12		17-Feb-12		$	0.3125
31-Mar-12		May 4, 2012		May 18, 2012		0.3125
30-Jun-12		August 6, 2012		August 17, 2012		0.3125
30-Sep-12		November 6, 2012		November 16, 2012		0.3125
31-Dec-12		7-Feb-13		19-Feb-13		0.3175
31-Mar-13		6-May-13		17-May-13		0.3225
30-Jun-13		5-Aug-13		19-Aug-13		0.3275
30-Sep-13		November 4, 2013		November 19, 2013		0.3363
31-Dec-13		7-Feb-14		19-Feb-14		0.3463
31-Mar-14		5-May-14		19-May-14		0.3588
30-Jun-14		4-Aug-14		19-Aug-14		0.38
30-Sep-14		3-Nov-14		19-Nov-14		0.415
31-Dec-14		February 6, 2015		February 19, 2015		0.45
ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.
ETP’s distributions declared during the periods presented below were as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						ETP Common Unit
31-Dec-11		February 7, 2012		February 14, 2012		$	0.8938
31-Mar-12		May 4, 2012		May 15, 2012		0.8938
30-Jun-12		August 6, 2012		August 14, 2012		0.8938
30-Sep-12		November 6, 2012		November 14, 2012		0.8938
31-Dec-12		February 7, 2013		February 14, 2013		0.8938
31-Mar-13		May 6, 2013		May 15, 2013		0.8938
30-Jun-13		August 5, 2013		August 14, 2013		0.8938
30-Sep-13		November 4, 2013		November 14, 2013		0.905
31-Dec-13		7-Feb-14		14-Feb-14		0.92
31-Mar-14		5-May-14		15-May-14		0.935
30-Jun-14		4-Aug-14		14-Aug-14		0.955
30-Sep-14		3-Nov-14		14-Nov-14		0.975
31-Dec-14		February 6, 2015		February 13, 2015		0.995
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional ETP Class H Units and ETP Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
Years Ending December 31,		Currently Effective				Pro Forma for			Pro Forma for Regency Merger(2)
						ETP Class H and
						Class I Units(1)
2015		$	86			$	31		$	91
2016		107				77			142
2017		85				85			145
2018		80				80			140
2019		70				70			130
2020		35				35			50
2021		35				35			35
2022		35				35			35
2023		35				35			35
2024		18				18			18
(1)	Pro forma amounts reflect the IDR subsidies, as adjusted for the pending issuance of additional ETP Class H Units and ETP Class I Units discussed above, as well as distributions on the ETP Class I Units. The issuance of additional ETP Class H Units and ETP Class I Units is expected to close in March 2015.
(2)	Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional ETP Class H Units and ETP Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of 2015 distribution payment and prior to the record date for the second quarter 2015 distribution payment.
The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.
Regency’s Quarterly Distributions of Available Cash
Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General Partner within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
Distributions declared by Regency during the years ended December 31, 2014, 2013 and 2012 were as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						Regency Common
						Unit
31-Dec-11		February 6, 2012		February 13, 2012		$	0.46
31-Mar-12		May 7, 2012		May 14, 2012		0.46
30-Jun-12		August 6, 2012		August 14, 2012		0.46
30-Sep-12		November 6, 2012		November 14, 2012		0.46
31-Dec-12		7-Feb-13		14-Feb-13		0.46
31-Mar-13		6-May-13		13-May-13		0.46
30-Jun-13		5-Aug-13		14-Aug-13		0.465
30-Sep-13		4-Nov-13		14-Nov-13		0.47
31-Dec-13		7-Feb-14		14-Feb-14		0.475
31-Mar-14		8-May-14		15-May-14		0.48
30-Jun-14		7-Aug-14		14-Aug-14		0.49
30-Sep-14		4-Nov-14		14-Nov-14		0.5025
31-Dec-14		February 6, 2015		February 13, 2015		0.5025
In conjunction with Southern Union’s contributions of SUGS to Regency, ETE agreed to relinquish incentive distributions on the 31.4 million Regency Common Units issued for twenty-four months subsequent to the transaction closing.
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared by Sunoco Logistics during the years ended December 31, 2014, 2013 and 2012 were as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						Sunoco Logistics
						Common Unit
December 31, 2012		February 8, 2013		February 14, 2013		$	0.2725
March 31, 2013		May 9, 2013		May 15, 2013		0.2863
June 30, 2013		8-Aug-13		14-Aug-13		0.3
September 30, 2013		8-Nov-13		14-Nov-13		0.315
December 31, 2013		10-Feb-14		14-Feb-14		0.3312
31-Mar-14		9-May-14		15-May-14		0.3475
30-Jun-14		8-Aug-14		14-Aug-14		0.365
30-Sep-14		7-Nov-14		14-Nov-14		0.3825
31-Dec-14		9-Feb-15		13-Feb-15		0.4
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.
Sunoco LP Quarterly Distributions of Available Cash
Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						Sunoco LP
						Common Unit
30-Sep-14		18-Nov-14		28-Nov-14		$	0.5457
31-Dec-14		17-Feb-15		27-Feb-15		0.6
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
	December 31,
	2014				2013
Available-for-sale securities	$	3			$	2
Foreign currency translation adjustment	(3		)		(1		)
Net losses on commodity related hedges	(1		)		(4		)
Actuarial gain (loss) related to pensions and other postretirement benefits	(57		)		56
Investments in unconsolidated affiliates, net	2				8
Subtotal	(56		)		61
Amounts attributable to noncontrolling interest	51				(52		)
Total AOCI included in partners’ capital, net of tax	$	(5	)		$	9
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):
	December 31,
	2014				2013
Available-for-sale securities	$	(1	)		$	(1	)
Foreign currency translation adjustment	2				1
Actuarial gain relating to pension and other postretirement benefits	(37		)		(39		)
Total	$	(36	)		$	(39	)

UnitBased_Compensation_Plans

Unit-Based Compensation Plans	12 Months Ended
	Dec. 31, 2014
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Unit-Based Compensation Plans	UNIT-BASED COMPENSATION PLANS:
	We, ETP, Sunoco Logistics and Regency have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
	ETE Long-Term Incentive Plan
	The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 6,000,000 units. As of December 31, 2014, 5,690,101 units remain available to be awarded under the plan.
	In December 2013, 1,540,000 Class D Units were granted to an ETE employee, Jamie Welch. Under the terms of the Class D Unit Agreement, 30% of the Class D Units granted to Welch will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. See further discussion at Note 9 to our consolidated financial statements.
	During 2014, no awards were granted to ETE employees and 3,687 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.
	During 2014, a total of 30,034 ETE Common Units vested, with a total fair value of $1.5 million as of the vesting date. As of December 31, 2014, excluding Class D units, a total of 34,340 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of less than $1 million in compensation over a weighted average period of 2.1 years. As of December 31, 2014, a total of 1,540,000 Class D Units granted to Mr. Welch remain outstanding, for which we expect to recognize a total of $23 million in compensation over a weighted average period of 3.0 years.
	ETP Unit-Based Compensation Plans
	Restricted Units
	ETP has granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.” Under ETP’s equity incentive plans, ETP’s non-employee directors each receive grants with a five-year service vesting requirement.
	The following table shows the activity of the ETP awards granted to employees and non-employee directors:
		Number of		Weighted Average
		ETP Units		Grant-Date Fair Value
				Per ETP Unit
	Unvested awards as of December 31, 2013	3.2		$	49.65
	Awards granted	1		60.85
	Awards vested	(0.5	)	48.12
	Awards forfeited	(0.1	)	32.36
	Unvested awards as of December 31, 2014	3.6		53.83
	During the years ended December 31, 2014, 2013 and 2012, the weighted average grant-date fair value per unit award granted was $60.85, $50.54 and $43.93, respectively. The total fair value of awards vested was $26 million, $29 million and $29 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2014, a total of 3.6 million unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over a weighted average period of 2.0 years.
	Cash Restricted Units
	ETP has also granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2014, a total of 0.4 million unvested cash restricted units units were outstanding.
	Based on the trading price of ETP Common Units at December 31, 2014, ETP expects to recognize $24 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.8 years.
	Sunoco Logistics Unit-Based Compensation Plan
	Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco, Inc. common units. As of December 31, 2014, a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted-average period of 2.9 years.
	Regency Unit-Based Compensation Plans
	Regency has the following awards outstanding as of December 31, 2014:
	•	107,650 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $22.68 per unit option; and
	•	2,167,719 Regency Phantom Units, with a weighted average grant date fair value of $24.31 per Phantom Unit.
	Regency expects to recognize $42 million of compensation expense related to the Regency Phantom Units over a period of 3.9 years.
	Cash Restricted Units
	Regency began granting cash restricted units in 2014. These awards are service condition (time-based) grants which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Regency Common Unit upon vesting. Regency has 379,328 cash restricted units outstanding at December 31, 2014.
	Based on the trading price of Regency Common Units at December 31, 2014, Regency expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES:
	As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
		Years Ended December 31,
		2014			2013			2012
	Current expense (benefit):
	Federal	$	321		$	51		$	(3	)
	State	86			(1		)	6
	Total	407			50			3
	Deferred expense (benefit):
	Federal	(53		)	(14		)	41
	State	3			57			10
	Total	(50		)	43			51
	Total income tax expense from continuing operations	$	357		$	93		$	54
	Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (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, 2014 and 2013 is as follows:
		31-Dec-14									31-Dec-13
		Corporate Subsidiaries(1)			Partnership(2)			Consolidated			Corporate Subsidiaries(1)			Partnership(2)			Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	212		$	—		$	212		$	(172	)	$	—		$	(172	)
	Increase (reduction) in income taxes resulting from:
	Nondeductible goodwill	—			—			—			241			—			241
	Nondeductible goodwill included in the Lake Charles LNG Transaction	105			—			105			—			—			—
	Premium on debt retirement	(10		)	—			(10		)	—			—			—
	Foreign taxes	(8		)	—			(8		)	—			—			—
	State income taxes (net of federal income tax effects)	9			46			55			31			10			41
	Other	3			—			3			(16		)	(1		)	(17		)
	Income tax from continuing operations	$	311		$	46		$	357		$	84		$	9		$	93
	(1)	Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of ETP Holdco.
	(2)	Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes.
	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
		December 31,
		2014			2013
	Deferred income tax assets:
	Net operating losses and alternative minimum tax credit	$	116		$	217
	Pension and other postretirement benefits	47			57
	Long term debt	53			108
	Other	111			104
	Total deferred income tax assets	327			486
	Valuation allowance	(84		)	(74		)
	Net deferred income tax assets	243			412
	Deferred income tax liabilities:
	Properties, plants and equipment	(1,583		)	(1,624		)
	Inventory	(153		)	(302		)
	Investments in unconsolidated affiliates	(2,530		)	(2,245		)
	Trademarks	(355		)	(180		)
	Other	(32		)	(45		)
	Total deferred income tax liabilities	(4,653		)	(4,396		)
	Net deferred income tax liability	(4,410		)	(3,984		)
	Less: current portion of deferred income tax liabilities, net	(85		)	(119		)
	Accumulated deferred income taxes	$	(4,325	)	$	(3,865	)
	The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (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,
		2014			2013
	Net deferred income tax liability, beginning of year	$	(3,984	)	$	(3,696	)
	Susser acquisition	(488		)	—
	SUGS Contribution to Regency	—			(115		)
	Tax provision (including discontinued operations)	62			(124		)
	Other	—			(49		)
	Net deferred income tax liability	$	(4,410	)	$	(3,984	)
	ETP Holdco, Susser and other corporate subsidiaries have gross federal net operating loss carryforwards of $5 million, all of which will expire in 2032 and 2033. Our corporate subsidiaries had less than $1 million of federal alternative minimum tax credits at December 31, 2014. Our corporate subsidiaries have state net operating loss carryforward benefits of $111 million, net of federal tax, which expire between 2014 and 2033. The valuation allowance of $84 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods.
	The following table sets forth the changes in unrecognized tax benefits:
		Years Ended December 31,
		2014			2013			2012
	Balance at beginning of year	$	429		$	27		$	2
	Additions attributable to acquisitions	—			—			28
	Additions attributable to tax positions taken in the current year	20			—			—
Additions attributable to tax positions taken in prior years	(1		)	406			—
Settlements	(5		)	—			—
Lapse of statute	(3		)	(4		)	(3		)
Balance at end of year	$	440		$	429		$	27
As of December 31, 2014, we have $439 million ($425 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 $4 million ($2 million, net of federal tax) within the next twelve months due to settlement of certain positions.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 open statute years, Sunoco, Inc. has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco, Inc. is fully successful with its claims, it will receive tax refunds of approximately $372 million. However, due to the uncertainty surrounding the claims, a reserve of $372 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2014.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2014, we recognized interest and penalties of less than $1 million. At December 31, 2014, we have interest and penalties accrued of $6 million, net of tax.
In general, ETE and its subsidiaries are no longer subject to examination by the IRS for 2010 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007, and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to and 2004. Regency and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2012. However, the statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statue, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2014, 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 have vigorously defended this tax position and believe we have reached a tentative settlement with the IRS which will not have a material impact on our consolidated financial position or results of operations. Regency is also under examination by the IRS for the 2007 and 2008 tax years. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. The proposed adjustments with respect to Regency would not have a material impact upon our financial statements.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory_Matters_Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2014

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

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

PEPL Holdings Guarantee of Collection

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

NGL Pipeline Regulation

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 Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not 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.

Transwestern Rate Case

On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers.  On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.

FGT Rate Case

On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.

Commitments

In the normal course of business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

Years Ended December 31,

2014

2013

2012

Rental expense(1)

$

159

$

151

$

60

Less: Sublease rental income

(26

)

(24

)

(4

)

Rental expense, net

$

133

$

127

$

56

(1)

Includes contingent rentals totaling $24 million, $22 million and $6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Future minimum lease commitments for such leases are:

Years Ending December 31:

2015

$

151

2016

129

2017

118

2018

108

2019

102

Thereafter

829

Future minimum lease commitments

1,437

Less: Sublease rental income

(34

)

Net future minimum lease commitments

$

1,403

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

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil 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.

MTBE Litigation

Sunoco, Inc., 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, 2014, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, 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. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont and Pennsylvania cases assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of 19 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, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Litigation Relating to the PVR Merger

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

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

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

Eagle Rock Shareholder Litigation

Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.

Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise has filed a notice of appeal. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.

Other Litigation and Contingencies

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, 2014 and 2013, accruals of approximately $37 million and $46 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.

No amounts have been recorded in our December 31, 2014 or 2013 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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 Massachusetts Department of Public Utilities (“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. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Air Quality Control

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

Compliance Orders from the New Mexico Environmental Department

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

Environmental Matters

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

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

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

Environmental Remediation

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

•

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

•

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

•

Currently operating Sunoco, Inc. retail sites.

•

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

•

Sunoco, Inc. 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, 2014, Sunoco, Inc. had been named as a PRP at approximately 51 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’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. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. 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,

2014

2013

Current

$

41

$

47

Non-current

360

356

Total environmental liabilities

$

401

$

403

In 2013, we 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, 2014 and 2013, the Partnership recorded $48 million and $41 million, respectively, of expenditures related to environmental cleanup programs.

On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act 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 U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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

Price_Risk_Management_Assets_A

Price Risk Management Assets And Liabilities	12 Months Ended
	Dec. 31, 2014
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Price Risk Management Assets And Liabilities	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
	Commodity Price Risk
	We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by operating entity.
	ETP
	ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
	ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales on its interstate transportation and storage operations. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in its midstream operations whereby its subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	ETP may use derivatives in ETP’s liquids transportation and services operations to manage ETP’s storage facilities and the purchase and sale of purity NGLs.
	Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.
	ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of the hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.
	ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to its transportation and storage operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading activities related to power and natural gas in its other operations which are also netted in cost of products sold. As a result of its trading activities and the use of derivative financial instruments in its transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to its risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’s commodity risk management policy.
	The following table details ETP’s outstanding commodity-related derivatives:
		December 31, 2014					December 31, 2013
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	(232,500	)		2015		9,457,500			2014-2019
	Basis Swaps IFERC/NYMEX (1)	(13,907,500	)		2015 - 2016		(487,500	)		2014-2017
	Swing Swaps	—			—		1,937,500			2014-2016
	Options – Calls	5,000,000			2015		—			—
	Power (Megawatt):
	Forwards	288,775			2015		351,050			2014
	Futures	(156,000	)		2015		(772,476	)		2014
	Options — Puts	(72,000	)		2015		(52,800	)		2014
	Options — Calls	198,556			2105		103,200			2014
	Crude (Bbls) – Futures	—			—		103,000			2014
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	57,500			2015		570,000			2014
	Swing Swaps IFERC	46,150,000			2015		(9,690,000	)		2014-2016
	Fixed Swaps/Futures	(8,779,000	)		2015 - 2016		(8,195,000	)		2014-2015
	Forward Physical Contracts	(9,116,777	)		2015		5,668,559			2014-2015
	Natural Gas Liquid (Bbls) – Forwards/Swaps	(2,179,400	)		2015		(1,133,600	)		2014
	Refined Products (Bbls) – Futures	13,745,755			2015		(280,000	)		2014
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(39,287,500	)		2015		(7,352,500	)		2014
	Fixed Swaps/Futures	(39,287,500	)		2015		(50,530,000	)		2014
	Hedged Item — Inventory	39,287,500			2015		50,530,000			2014
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	—			—		(1,825,000	)		2014
	Fixed Swaps/Futures	—			—		(12,775,000	)		2014
	Natural Gas Liquid (Bbls) – Forwards/Swaps	—			—		(780,000	)		2014
	Crude (Bbls) – Futures	—			—		(30,000	)		2014
	(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
	Regency
	Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
	Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.
	Through its natural gas marketing activity, Regency has credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.
	Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
	Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.
	The following table details Regency’s outstanding commodity-related derivatives:
		December 31, 2014					December 31, 2013
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu) — Fixed Swaps/Futures	(25,525,000	)		2015		(24,455,000	)		2014-2015
	Propane (Gallons) — Forwards/Swaps	(29,148,000	)		2015		(52,122,000	)		2014-2015
NGLs (Barrels) — Forwards/Swaps	(292,000	)		2015		(438,000	)		2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,252,000	)		2015-2016		(521,000	)		2014
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and 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 anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes:
						Notional Amount Outstanding
Entity		Term		Type(1)		December 31,				December 31,
						2014				2013
ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		$	—			$	400
ETP		July 2015(2)		Forward-starting to pay a fixed rate of 3.38% and receive a floating rate		200				—
ETP		July 2016(3)		Forward-starting to pay a fixed rate of 3.80% and receive a floating rate		200				—
ETP		July 2017(4)		Forward-starting to pay a fixed rate of 3.84% and receive a floating rate		300				—
ETP		July 2018(4)		Forward-starting to pay a fixed rate of 4.00% and receive a floating rate		200				—
ETP		July 2019(4)		Forward-starting to pay a fixed rate of 3.19% and receive a floating rate		300				—
ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		—				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 1.73% and receive a fixed rate of 3.60%		200				400
Panhandle		Nov-21		Pay a fixed rate of 3.82% and receive a floating rate		—				275
(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.
(3)	Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
(4)	Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
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 ETP’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, ETP may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETP also implements 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, ETP utilizes master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
ETP has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives, and ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of December 31, 2014 would be $82 million, which would be reduced by less than $1 million due to the netting feature. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.
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-14				31-Dec-13				31-Dec-14				31-Dec-13
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	43			$	3			$	—			$	(18	)
	43				3				—				(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	617			$	227			$	(577	)		$	(209	)
Commodity derivatives	107				43				(23		)		(48		)
Interest rate derivatives	3				47				(155		)		(95		)
Embedded derivatives in Regency Preferred Units	—				—				(16		)		(19		)
	727				317				(771		)		(371		)
Total derivatives	$	770			$	320			$	(771	)		$	(389	)
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, 2014				December 31, 2013				December 31, 2014				December 31, 2013
Derivatives in offsetting agreements:
OTC contracts		Price risk management assets (liabilities)		$	23			$	42			$	(23	)		$	(38	)
Broker cleared derivative contracts		Other current assets		674				264				(574		)		(318		)
				697				306				(597		)		(356		)
Offsetting agreements:
Counterparty netting		Price risk management assets (liabilities)		(19		)		(36		)		19				36
Payments on margin deposit		Other current assets		5				(1		)		(22		)		55
				(14		)		(37		)		(3		)		91
Net derivatives with offsetting agreements				683				269				(600		)		(265		)
Derivatives without offsetting agreements				87				51				(171		)		(124		)
Total derivatives				$	770			$	320			$	(771	)		$	(389	)
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,
	2014				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—			$	(1	)		$	8
Total	$	—			$	(1	)		$	8
	Location of		Amount of Gain/(Loss) Reclassified from
	Gain/(Loss) Reclassified		AOCI into Income (Effective Portion)
	from AOCI into Income		Years Ended December 31,
	(Effective Portion)		2014				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold		$	(3	)		$	4			$	14
Total			$	(3	)		$	4			$	14
	Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income
	Recognized in		Representing Hedge Ineffectiveness and
	Income on Derivatives		Amount Excluded from the Assessment of
			Effectiveness
			Years Ended December 31,
			2014				2013				2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold		$	(8	)		$	8			$	54
Total			$	(8	)		$	8			$	54
	Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized
			in Income on Derivatives
			Years Ended December 31,
			2014				2013				2012
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold		$	(6	)		$	(11	)		$	(7	)
Commodity derivatives – Non-trading	Cost of products sold		199				(21		)		26
Commodity contracts – Non-trading	Deferred gas purchases		—				(3		)		(26		)
Interest rate derivatives	Gains (losses) on interest rate derivatives		(157		)		53				(19		)
Embedded derivatives	Other income		3				6				14
Total			$	39			$	24			$	(12	)

Retirement_Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	RETIREMENT BENEFITS:
	Savings and Profit Sharing Plans
	We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Regency and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $59 million, $47 million and $30 million to the 401(k) savings plan for the years ended December 31, 2014, 2013 and 2012, respectively.
	Pension and Other Postretirement Benefit Plans
	Panhandle
	Panhandle offered postretirement health care and life insurance plans that were available to substantially all of its employees, pending the retiree meeting certain age and service requirements.
	Sunoco, Inc.
	Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan and anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporation and the IRS, in the fourth quarter of 2015.
	Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’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-14												31-Dec-13
		Pension Benefits												Pension Benefits
		Funded Plans				Unfunded Plans				Other Postretirement Benefits				Funded Plans				Unfunded Plans				Other Postretirement Benefits
	Change in benefit obligation:
	Benefit obligation at beginning of period	$	632			$	61			$	223			$	1,117			$	78			$	296
	Service cost	—				—				—				3				—				—
	Interest cost	28				3				5				33				2				6
	Amendments	—				—				1				—				—				2
	Benefits paid, net	(45		)		(9		)		(28		)		(99		)		(16		)		(26		)
	Actuarial (gain) loss and other	130				10				2				(74		)		(3		)		(14		)
	Settlements	(27		)		—				—				(95		)		—				—
	Dispositions	—				—				—				(253		)		—				(41		)
	Benefit obligation at end of period	$	718			$	65			$	203			$	632			$	61			$	223
	Change in plan assets:
	Fair value of plan assets at beginning of period	600				—				284				906				—				312
	Return on plan assets and other	70				—				7				43				—				17
	Employer contributions	—				—				9				—				—				8
	Benefits paid, net	(45		)		—				(28		)		(99		)		—				(26		)
	Settlements	(27		)		—				—				(95		)		—				—
	Dispositions	—				—				—				(155		)		—				(27		)
	Fair value of plan assets at end of period	$	598			$	—			$	272			$	600			$	—			$	284
	Amount underfunded (overfunded) at end of period	$	120			$	65			$	(69	)		$	32			$	61			$	(61	)
	Amounts recognized in the consolidated balance sheets consist of:
	Non-current assets	$	—			$	—			$	96			$	—			$	—			$	86
	Current liabilities	—				(9		)		(2		)		—				(9		)		(2		)
	Non-current liabilities	(120		)		(56		)		(25		)		(32		)		(52		)		(23		)
		$	(120	)		$	(65	)		$	69			$	(32	)		$	(61	)		$	61
	Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
	Net actuarial gain	$	18			$	7			$	(21	)		$	(86	)		$	(4	)		$	(25	)
	Prior service cost	—				—				18				—				—				18
		$	18			$	7			$	(3	)		$	(86	)		$	(4	)		$	(7	)
	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
		31-Dec-14											31-Dec-13
		Pension Benefits											Pension Benefits
		Funded Plans				Unfunded Plans				Other Postretirement Benefits			Funded Plans				Unfunded Plans			Other Postretirement Benefits
	Projected benefit obligation	$	718			$	65			N/A			$	632			61			N/A
	Accumulated benefit obligation	718				65				203			632				61			$	223
	Fair value of plan assets	598				—				272			600				—			284
	Components of Net Periodic Benefit Cost
		31-Dec-14								31-Dec-13
		Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	—			$	—			$	3			$	—
	Interest cost	31				5				35				6
	Expected return on plan assets	(40		)		(8		)		(54		)		(9		)
	Prior service cost amortization	—				1				—				1
	Actuarial loss amortization	(1		)		(1		)		2				—
	Settlements	(4		)		—				(2		)		—
		(14		)		(3		)		(16		)		(2		)
	Regulatory adjustment(1)	—				—				5				—
	Net periodic benefit cost	$	(14	)		$	(3	)		$	(11	)		$	(2	)
	(1)	Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operation.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
	December 31, 2014						31-Dec-13
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Discount rate	3.62	%		2.24	%		4.65	%		2.33	%
Rate of compensation increase	N/A			N/A			N/A			N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
	December 31, 2014						31-Dec-13
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Discount rate	4.65	%		3.02	%		3.5	%		2.68	%
Expected return on assets:
Tax exempt accounts	7.5	%		7	%		7.5	%		6.95	%
Taxable accounts	N/A			4.5	%		N/A			4.42	%
Rate of compensation increase	N/A			N/A			N/A			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 Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
	December 31,
	2014			2013
Health care cost trend rate	7.09	%		7.57	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.41	%		5.42	%
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 Panhandle 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 other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%.
The investment strategy of Sunoco, Inc. 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 and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
						Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy
		Fair Value as of December 31, 2014				Level 1				Level 2				Level 3
Asset Category:
Cash and cash equivalents		$	25			$	25			$	—			$	—
Mutual funds (1)		110				—				110				—
Fixed income securities		463				—				463				—
Total		$	598			$	25			$	573			$	—
-1	Comprised of 100% equities as of December 31, 2014.
						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 41% equities, 45% fixed income securities, and 14% in other investments as of December 31, 2013.
The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
						Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy
		Fair Value as of December 31, 2014				Level 1				Level 2				Level 3
Asset Category:
Cash and Cash Equivalents		$	9			$	9			$	—			$	—
Mutual funds (1)		138				138				—				—
Fixed income securities		125				—				125				—
Total		$	272			$	147			$	125			$	—
-1	Primarily comprised of approximately 53% equities, 41% fixed income securities, 6% cash as of December 31, 2014.
						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.
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 $129 million to pension plans and approximately $10 million to other postretirement plans in 2015.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’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)
2015		$	717			$	9			$	28
2016		—				8				26
2017		—				7				25
2018		—				7				23
2019		—				6				22
2020 – 2024		—				23				65
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.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS:
	The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.
	In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 16).
	In addition, subsidiaries of ETE recorded sales with affiliates of $965 million, $1.44 billion and $189 million during the years ended December 31, 2014, 2013 and 2012, respectively.

Reportable_Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2014
Reportable Segments [Abstract]
Reportable Segments	REPORTABLE SEGMENTS:
	As a result of the Lake Charles LNG Transaction in 2014, our reportable segments were re-evaluated and currently reflect the following reportable segments, which conduct their business exclusively in the United States, as follows:
	•	Investment in ETP, including the consolidated operations of ETP;
	•	Investment in Regency, including the consolidated operations of Regency;
	•	Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
	•	Corporate and Other, including the following:
	•	activities of the Parent Company; and
	•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
	Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
	We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, 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 and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
	Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.
	Eliminations in the tables below include the following:
	•	ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.
	•	ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.
	•	ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the years ended December 31, 2013 and 2012 beginning March 26, 2012. Therefore, the results of Lake Charles LNG were included in eliminations for 2013 and 2012.
		Years Ended December 31,
		2014			2013			2012
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	50,989		$	46,210		$	15,671
	Intersegment revenues	169			129			31
		51,158			46,339			15,702
	Investment in Regency:
	Revenues from external customers	4,597			2,404			1,986
	Intersegment revenues	354			117			14
		4,951			2,521			2,000
	Investment in Lake Charles LNG:
	Revenues from external customers	216			216			166
	Adjustments and Eliminations:	(634		)	(741		)	(904		)
	Total revenues	$	55,691		$	48,335		$	16,964
	Costs of products sold:
	Investment in ETP	$	45,540		$	41,204		$	12,266
	Investment in Regency	3,452			1,793			1,387
	Adjustments and Eliminations	(603		)	(443		)	(565		)
	Total costs of products sold	$	48,389		$	42,554		$	13,088
	Depreciation, depletion and amortization:
	Investment in ETP	1,130			1,032			656
	Investment in Regency	541			287			252
	Investment in Lake Charles LNG	39			39			30
	Corporate and Other	17			16			14
	Adjustments and Eliminations	(3		)	(61		)	(81		)
	Total depreciation, depletion and amortization	$	1,724		$	1,313		$	871
		Years Ended December 31,
		2014			2013			2012
	Equity in earnings of unconsolidated affiliates:
	Investment in ETP	$	234		$	172		$	142
	Investment in Regency	195			135			105
	Adjustments and Eliminations	(97		)	(71		)	(35		)
	Total equity in earnings of unconsolidated affiliates	$	332		$	236		$	212
		Years Ended December 31,
		2014			2013			2012
	Segment Adjusted EBITDA:
	Investment in ETP	$	4,829		$	3,953		$	2,744
	Investment in Regency	1,172			608			517
	Investment in Lake Charles LNG	195			187			135
	Corporate and Other	(97		)	(43		)	(52		)
	Adjustments and Eliminations	(259		)	(338		)	(239		)
	Total Segment Adjusted EBITDA	5,840			4,367			3,105
	Depreciation, depletion and amortization	(1,724		)	(1,313		)	(871		)
	Interest expense, net of interest capitalized	(1,369		)	(1,221		)	(1,018		)
	Bridge loan related fees	—			—			(62		)
	Gain on deconsolidation of Propane Business	—			—			1,057
	Gain on sale of AmeriGas common units	177			87			—
	Goodwill impairment	(370		)	(689		)	—
Gains (losses) on interest rate derivatives	(157		)	53			(19		)
Non-cash unit-based compensation expense	(82		)	(61		)	(47		)
Unrealized gains on commodity risk management activities	116			48			10
Losses on extinguishments of debt	(25		)	(162		)	(123		)
Inventory valuation adjustments	(473		)	3			(75		)
Adjusted EBITDA related to discontinued operations	(27		)	(76		)	(99		)
Adjusted EBITDA related to unconsolidated affiliates	(748		)	(727		)	(647		)
Equity in earnings of unconsolidated affiliates	332			236			212
Non-operating environmental remediation	—			(168		)	—
Other, net	(73		)	(2		)	14
Income from continuing operations before income tax expense	$	1,417		$	375		$	1,437
	December 31,
	2014			2013			2012
Total assets:
Investment in ETP	$	48,221		$	43,702		$	43,230
Investment in Regency	17,103			8,782			8,123
Investment in Lake Charles LNG	1,210			1,338			1,917
Corporate and Other	1,153			720			707
Adjustments and Eliminations	(3,218		)	(4,212		)	(5,073		)
Total	$	64,469		$	50,330		$	48,904
	Years Ended December 31,
	2014			2013			2012
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	4,478		$	2,455		$	3,049
Investment in Regency	1,112			1,011			599
Investment in Lake Charles LNG	1			2			4
Adjustments and Eliminations	(32		)	(126		)	(135		)
Total	$	5,559		$	3,342		$	3,517
	December 31,
	2014			2013			2012
Advances to and investments in affiliates:
Investment in ETP	$	3,840		$	4,436		$	3,502
Investment in Regency	2,418			2,097			2,214
Adjustments and Eliminations	(2,599		)	(2,519		)	(979		)
Total	$	3,659		$	4,014		$	4,737
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Regency.
Investment in ETP
	Years Ended December 31,
	2014			2013			2012
Intrastate Transportation and Storage	$	2,652		$	2,250		$	2,012
Interstate Transportation and Storage	1,057			1,270			1,109
Midstream	1,210			1,307			1,757
Liquids Transportation and Services	3,790			2,063			619
Investment in Sunoco Logistics	17,920			16,480			3,109
Retail Marketing	22,484			21,004			5,926
All Other	2,045			1,965			1,170
Total revenues	51,158			46,339			15,702
Less: Intersegment revenues	169			129			31
Revenues from external customers	$	50,989		$	46,210		$	15,671
Investment in Regency
	Years Ended December 31,
	2014			2013			2012
Gathering and Processing	$	4,570		$	2,287		$	1,797
Contract Services	307			215			183
Natural Gas Transportation	—			1			1
Natural Resources	58			—			—
Corporate and others	16			18			19
Total revenues	4,951			2,521			2,000
Less: Intersegment revenues	354			117			14
Revenues from external customers	$	4,597		$	2,404		$	1,986
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $216 million, $216 million and $166 million for the year ended December 31, 2014, 2013 and 2012, respectively, were related to LNG terminalling.

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED):
	Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
		Quarters Ended
		March 31		June 30		September 30		December 31			Total Year
	2014:00:00
	Revenues	$	13,080	$	14,143	$	14,987	$	13,481		$	55,691
	Gross margin	1,638		1,792		1,972		1,900			7,302
	Operating income	710		773		822		165			2,470
	Net income (loss)	448		500		470		(294		)	1,124
	Limited Partners’ interest in net income	167		163		188		111			629
	Basic net income per limited partner unit	$	0.3	$	0.3	$	0.35	$	0.21		$	1.16
	Diluted net income per limited partner unit	$	0.3	$	0.3	$	0.35	$	0.21		$	1.15
		Quarters Ended
		March 31		June 30		September 30		December 31			Total Year
	2013:00:00
	Revenues	$	11,179	$	12,063	$	12,486	$	12,607		$	48,335
	Gross margin	1,372		1,498		1,422		1,489			5,781
	Operating income (loss)	531		644		529		(153		)	1,551
	Net income (loss)	322		338		356		(701		)	315
	Limited Partners’ interest in net income (loss)	90		127		150		(171		)	196
	Basic net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
	Diluted net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
	The three months ended December 31, 2014 reflected the unfavorable impacts of $456 million related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and Regency’s recognition of a goodwill impairment of $370 million. The three months ended December 31, 2013 reflected ETP’s recognition of a goodwill impairment of $689 million.

Supplemental_Financial_Stateme

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2014
Supplemental Financial Statement Information
Supplemental Financial Statement Information	SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
	Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
	BALANCE SHEETS
		December 31,
		2014			2013
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	2		$	8
	Accounts receivable from related companies	14			5
	Other current assets	1			—
	Total current assets	17			13
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,390			3,841
	INTANGIBLE ASSETS, net	10			14
	GOODWILL	9			9
	OTHER NON-CURRENT ASSETS, net	46			41
	Total assets	$	5,472		$	3,918
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable to related companies	$	11		$	11
	Interest payable	58			24
	Accrued and other current liabilities	3			3
	Total current liabilities	72			38
	LONG-TERM DEBT, less current maturities	4,680			2,801
	NOTE PAYABLE TO AFFILIATE	54			—
	OTHER NON-CURRENT LIABILITIES	2			1
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	(1		)	(3		)
	Limited Partners:
	Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively)	648			1,066
	Class D Units (1,540,000 units authorized, issued and outstanding)	22			6
	Accumulated other comprehensive income (loss)	(5		)	9
	Total partners’ capital	664			1,078
	Total liabilities and partners’ capital	$	5,472		$	3,918
	STATEMENTS OF OPERATIONS
		Years Ended December 31,
		2014			2013			2012
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(111	)	$	(56	)	$	(53	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized	(205		)	(210		)	(235		)
	Bridge loan related fees	—			—			(62		)
	Equity in earnings of unconsolidated affiliates	955			617			666
	Gains (losses) on interest rate derivatives	—			9			(15		)
	Loss on extinguishment of debt	—			(157		)	—
	Other, net	(5		)	(8		)	(4		)
	INCOME BEFORE INCOME TAXES	634			195			297
	Income tax expense (benefit)	1			(1		)	(7		)
	NET INCOME	633			196			304
	GENERAL PARTNER’S INTEREST IN NET INCOME	2			—			2
	CLASS D UNITHOLDER’S INTEREST IN NET INCOME	2			—			—
	LIMITED PARTNERS’ INTEREST IN NET INCOME	$	629		$	196		$	302
	STATEMENTS OF CASH FLOWS
		Years Ended December 31,
		2014			2013			2012
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	816		$	768		$	555
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Cash paid for acquisitions	—			—			(1,113		)
	Proceeds from ETP Holdco Transaction	—			1,332			—
	Contributions to unconsolidated affiliates	(118		)	(8		)	(487		)
	Purchase of additional interest in Regency	(800		)	—			—
	Note payable to affiliate	54			—			—
	Note receivable from affiliate	—			—			(221		)
	Payments received on note receivable from affiliate	—			166			55
	Net cash provided by (used in) investing activities	(864		)	1,490			(1,766		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	3,020			2,080			2,108
Principal payments on debt	(1,142		)	(3,235		)	(162		)
Distributions to partners	(821		)	(733		)	(666		)
Redemption of Preferred Units	—			(340		)	—
Units repurchased under buyback program	(1,000		)	—			—
Debt issuance costs	(15		)	(31		)	(78		)
Net cash provided by (used in) financing activities	42			(2,259		)	1,202
DECREASE IN CASH AND CASH EQUIVALENTS	(6		)	(1		)	(9		)
CASH AND CASH EQUIVALENTS, beginning of period	8			9			18
CASH AND CASH EQUIVALENTS, end of period	$	2		$	8		$	9

Estimates_Significant_Accounti1

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
	The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for 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, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements
	In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.
	In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations.  Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results.  ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.
Revenue Recognition	Revenue Recognition
	Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
	Investment in ETP
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.
	In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.
	Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and gross margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
	ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
	ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	ETP’s retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’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 recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
	Investment in Regency
	Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
	Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.
	Investment in Lake Charles LNG
	Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities
	ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	Cash, Cash Equivalents and Supplemental Cash Flow Information
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
	We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable	Accounts Receivable
	Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.
Inventories	Inventories
	Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Exchanges	Exchanges
	Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Property, Plant and Equipment	Property, Plant and Equipment
	Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
	We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
	Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Equity and Cost Method Investments, Policy [Policy Text Block]	Advances to and Investments in Affiliates
	Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Goodwill	Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized
Intangible Assets	We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
	Intangible Assets
	Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Other Non-Current Assets, net	Other Non-Current Assets, net
	Other non-current assets, net are stated at cost less accumulated amortization.
Asset Retirement Obligation	Asset Retirement Obligations
	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 certain amounts recorded by Panhandle, Sunoco Logistics and ETP’s retail marketing operations. discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2014 and 2013, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’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, Inc. has legal asset retirement obligations for several other assets at its previously owned 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, Inc. 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 segment recorded as other non-current liabilities in our consolidated balance sheets:
		December 31,
		2014		2013
	Investment in ETP:
	Interstate transportation and storage operations	$	58	$	55
	Retail marketing operations	87		84
	Investment in Sunoco Logistics	41		41
	Investment in Regency	2		—
		$	188	$	180
	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.
Accrued and Other Current Liabilities Policy [Text Block]	Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Environmental 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	Fair Value of Financial Instruments
	The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
	Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2014 was $31.68 billion and $30.66 billion, respectively. As of December 31, 2013, the aggregate fair value and carrying amount of our consolidated debt obligations was $23.97 billion and $23.20 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
	We have commodity derivatives, interest rate derivatives, the Preferred Units, the preferred units of a subsidiary and embedded derivatives in the preferred units of a subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.
Contributions In Aid Of Construction Costs Policy Text Block	Contributions in Aid of Construction Cost
	On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs	Shipping and Handling Costs
	Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses	Costs and Expenses
	Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
	We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss).
Issuances of Subsidiary Units	Issuances of Subsidiary Units
	We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes	Income Taxes
	ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
	As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2014, 2013 and 2012, 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. These corporate subsidiaries include Susser and ETP Holdco, which owns Sunoco, Inc. and Panhandle. 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 the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
	Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
	If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
	We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in gains (losses) on interest rate derivatives in the consolidated statements of operations.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Unit-Based Compensation
	For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
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 entities.
Allocation of Income (Loss)	Allocation of Income
	For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

Operations_And_Organization_Ta

Operations And Organization (Tables)	12 Months Ended
	Dec. 31, 2014
Operations And Organization [Abstract]
Schedule Of Equity Interests	At December 31, 2014, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:
		ETP	Regency
	Units held by wholly-owned subsidiaries:
	Common units	30.8	57.2
	ETP Class H units	50.2	—
	Units held by less than wholly-owned subsidiaries:
	Common units	—	31.4
	Regency Class F units	—	6.3

Estimates_Significant_Accounti2

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill
	Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations and during the fourth quarter for reporting units within ETP’s interstate transportation and storage and liquids transportation and services operations and all others, including all of Regency’s reporting units and Lake Charles LNG.
Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities	The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
		Years Ended December 31,
		2014				2013			2012
	Accounts receivable	$	600			$	(556	)	$	267
	Accounts receivable from related companies	30				64			(9		)
	Inventories	51				(254		)	(258		)
	Exchanges receivable	18				(8		)	14
	Other current assets	133				(81		)	597
	Other non-current assets, net	(6		)		(23		)	(129		)
	Accounts payable	(850		)		541			(989		)
	Accounts payable to related companies	5				(140		)	92
	Exchanges payable	(99		)		128			—
	Accrued and other current liabilities	(59		)		192			(159		)
	Other non-current liabilities	(73		)		147			26
	Price risk management assets and liabilities, net	19				(159		)	(3		)
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(231	)		$	(149	)	$	(551	)
Schedule Of Non-Cash Investing And Financing Activities	Non-cash investing and financing activities and supplemental cash flow information were as follows:
		Years Ended December 31,
		2014				2013			2012
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	643			$	226		$	420
	Net gains (losses) from subsidiary common unit transactions	$	744			$	(384	)	$	80
	AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	—			$	—		$	1,123
	NON-CASH FINANCING ACTIVITIES:
	Issuance of Common Units in connection with Southern Union Merger (see Note 3)	$	—			$	—		$	2,354
	Subsidiary issuance of common units in connection with certain acquisitions	$	—			$	—		$	2,295
	Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions	$	4,281			$	—		$	—
	Subsidiary issuances of common units in connection with the Susser Merger	$	908			$	—		$	—
	Long-term debt assumed in PVR Acquisition	$	1,887			$	—		$	—
	Long-term debt exchanged in Eagle Rock Midstream Acquisition	$	499			$	—		$	—
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	1,416			$	1,256		$	997
	Cash paid for income taxes	$	345			$	58		$	23
Schedule of Inventory	Inventories consisted of the following:
		December 31,
		2014				2013
	Natural gas and NGLs	$	392			$	577
	Crude oil	364				488
	Refined products	392				543
	Appliances, parts and fittings and other	319				199
	Total inventories	$	1,467			$	1,807
Other Current Assets	Other current assets consisted of the following:
		December 31,
		2014				2013
	Deposits paid to vendors	$	65			$	49
	Deferred income taxes	14				—
	Prepaid expenses and other	222				263
	Total other current assets	$	301			$	312
Property, Plant and Equipment	Components and useful lives of property, plant and equipment were as follows:
		December 31,
		2014				2013
	Land and improvements	$	1,307			$	881
	Buildings and improvements (1 to 45 years)	1,922				939
	Pipelines and equipment (5 to 83 years)	27,149				21,494
	Natural gas and NGL storage facilities (5 to 46 years)	1,214				1,083
	Bulk storage, equipment and facilities (2 to 83 years)	4,010				1,933
	Tanks and other equipment (5 to 40 years)	58				1,697
	Retail equipment (2 to 99 years)	515				450
	Vehicles (1 to 25 years)	203				156
	Right of way (20 to 83 years)	2,451				2,190
	Furniture and fixtures (2 to 25 years)	59				51
	Linepack	119				118
	Pad gas	44				52
	Natural resources	454				—
	Other (1 to 30 years)	999				708
	Construction work-in-process	4,514				2,165
		45,018				33,917
	Less – Accumulated depreciation and depletion	(4,726		)		(3,235		)
	Property, plant and equipment, net	$	40,292			$	30,682
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:
		Years Ended December 31,
		2014				2013			2012
	Depreciation expense	$	1,457			$	1,128		$	801
	Capitalized interest, excluding AFUDC	$	113			$	43		$	99
Schedule of Goodwill	Changes in the carrying amount of goodwill were as follows:
		Investment in ETP				Investment in Regency			Investment in Lake Charles LNG			Corporate, Other and Eliminations			Total
	Balance, December 31, 2012	$	5,606			$	1,127		$	873		$	(1,172	)	$	6,434
	Goodwill acquired	156				—			—			—			156
	Deconsolidation of SUGS (1)	(337		)		—			—			337			—
	Goodwill impairment	(689		)		—			(689		)	689			(689		)
	Other	(7		)		—			—			—			(7		)
	Balance, December 31, 2013	4,729				1,127			184			(146		)	5,894
	Goodwill acquired	1,874				449			—			—			2,323
	Lake Charles LNG Transaction (2)	(184		)		—			—			184			—
	Goodwill impairment	—				(370		)	—			—			(370		)
	Other	—				17			—			1			18
	Balance, December 31, 2014	$	6,419			$	1,223		$	184		$	39		$	7,865
Components And Useful Lives Of Intangibles And Other Assets	Components and useful lives of intangible assets were as follows:
		December 31, 2014							December 31, 2013
		Gross Carrying				Accumulated			Gross Carrying			Accumulated
		Amount				Amortization			Amount			Amortization
	Amortizable intangible assets:
	Customer relationships, contracts and agreements (3 to 46 years)	$	5,144			$	(485	)	$	2,135		$	(264	)
	Trade names (15 to 20 years)	556				(15		)	66			(12		)
	Patents (9 years)	48				(11		)	48			(6		)
	Other (1 to 15 years)	36				(7		)	7			(4		)
	Total amortizable intangible assets	5,784				(518		)	2,256			(286		)
	Non-amortizable intangible assets:
	Trademarks	316				—			294			—
	Total intangible assets	$	6,100			$	(518	)	$	2,550		$	(286	)
Aggregate Amortization Expense Of Intangibles And Other Assets	Aggregate amortization expense of intangibles assets was as follows:
		Years Ended December 31,
		2014				2013			2012
	Reported in depreciation, depletion and amortization	$	219			$	120		$	70
Estimated Aggregate Amortization Expense	Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
	Years Ending December 31:
	2015	$	263
	2016	260
	2017	260
	2018	259
	2019	256
Schedule of Other Non-Current Assets, net	Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
		December 31,
		2014				2013
	Unamortized financing costs (3 to 30 years)	$	203			$	167
	Regulatory assets	85				86
	Deferred charges	220				144
	Restricted funds	177				378
	Other	223				147
	Total other non-current assets, net	$	908			$	922
Schedule of Asset Retirement Obligations [Table Text Block]
		December 31,
		2014				2013
	Investment in ETP:
	Interstate transportation and storage operations	$	58			$	55
	Retail marketing operations	87				84
	Investment in Sunoco Logistics	41				41
	Investment in Regency	2				—
		$	188			$	180
Accrued and Other Current Liabilities	Accrued and other current liabilities consisted of the following:
		December 31,
		2014				2013
	Interest payable	$	440			$	357
	Customer advances and deposits	103				142
	Accrued capital expenditures	673				260
	Accrued wages and benefits	233				173
	Taxes payable other than income taxes	236				211
	Income taxes payable	54				4
	Deferred income taxes	99				119
	Other	363				412
	Total accrued and other current liabilities	$	2,201			$	1,678
Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2014 and 2013 based on inputs used to derive their fair values:
		Fair Value Measurements  at
		31-Dec-14
		Fair Value				Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	3			$	—		$	3		$	—
	Commodity derivatives:
	Condensate — Forward Swaps	36				—			36			—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	19				19			—			—
	Swing Swaps IFERC	26				1			25			—
	Fixed Swaps/Futures	566				541			25			—
	Forward Physical Contracts	1				—			1			—
	Power:
	Forwards	3				—			3			—
	Futures	4				4			—			—
	Natural Gas Liquids — Forwards/Swaps	69				46			23			—
	Refined Products — Futures	21				21			—			—
	Total commodity derivatives	745				632			113			—
	Total assets	$	748			$	632		$	116		$	—
	Liabilities:
	Interest rate derivatives	$	(155	)		$	—		$	(155	)	$	—
	Embedded derivatives in the Regency Preferred Units	(16		)		—			—			(16		)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(18		)		(18		)	—			—
	Swing Swaps IFERC	(25		)		(2		)	(23		)	—
	Fixed Swaps/Futures	(490		)		(490		)	—			—
	Power:
	Forwards	(4		)		—			(4		)	—
	Futures	(2		)		(2		)	—			—
	Natural Gas Liquids — Forwards/Swaps	(32		)		(32		)	—			—
	Refined Products — Futures	(7		)		(7		)	—			—
	Total commodity derivatives	(578		)		(551		)	(27		)	—
	Total liabilities	$	(749	)		$	(551	)	$	(182	)	$	(16	)
		Fair Value Measurements  at
		31-Dec-13
		Fair Value				Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	47			$	—		$	47		$	—
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	5				5			—			—
	Swing Swaps IFERC	8				1			7			—
	Fixed Swaps/Futures	203				201			2			—
	Natural Gas Liquids — Forwards/Swaps	7				5			2			—
	Power — Forwards	3				—			3			—
	Refined Products – Futures	5				5			—			—
	Total commodity derivatives	231				217			14			—
	Total assets	$	278			$	217		$	61		$	—
	Liabilities:
	Interest rate derivatives	$	(95	)		$	—		$	(95	)	$	—
	Embedded derivatives in the Regency Preferred Units	(19		)		—			—			(19		)
	Commodity derivatives:
	Condensate — Forward Swaps	(1		)		—			(1		)	—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(4		)		(4		)	—			—
	Swing Swaps IFERC	(6		)		—			(6		)	—
	Fixed Swaps/Futures	(206		)		(201		)	(5		)	—
	Forward Physical Contracts	(1		)		—			(1		)	—
	Natural Gas Liquids — Forwards/Swaps	(9		)		(5		)	(4		)	—
	Power — Forwards	(1		)		—			(1		)	—
Refined Products – Futures	(5		)		(5		)	—			—
Total commodity derivatives	(233		)		(215		)	(18		)	—
Total liabilities	$	(347	)		$	(215	)	$	(113	)	$	(19	)
Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block]	The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:
		Unobservable Input		December 31, 2014
	Embedded derivatives in the Regency Preferred Units	Credit Spread		4.76	%
		Volatility		35.8	%
Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis	The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2014. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2014 or 2013.
	Balance, December 31, 2013	$	(19	)
	Net unrealized gains included in other income (expense)	3
	Balance, December 31, 2014	$	(16	)

Acquisitions_and_Related_Trans1

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [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
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
		Sunoco, Inc.(1)			Southern Union(2)
	Current assets	$	7,312		$	556
	Property, plant and equipment	6,686			6,242
	Goodwill	2,641			2,497
	Intangible assets	1,361			55
	Investments in unconsolidated affiliates	240			2,023
	Note receivable	821			—
	Other assets	128			163
		19,189			11,536
	Current liabilities	4,424			1,348
	Long-term debt obligations, less current maturities	2,879			3,120
	Deferred income taxes	1,762			1,419
	Other non-current liabilities	769			284
	Noncontrolling interest	3,580			—
		13,414			6,171
	Total consideration	5,775			5,365
	Cash received	2,714			37
	Total consideration, net of cash received	$	3,061		$	5,328
	-1	Includes amounts recorded with respect to Sunoco Logistics.
	-2	Includes ETP’s acquisition of Citrus.
Pro Forma Results Of Operations	Pro Forma Results of Operations
	The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations.
		Years Ended December 31,
		2014			2013		2012
	Revenues	$	56,517		$	50,473	$	40,398
	Net income	1,098			252		868
	Net income attributable to partners	607			133		866
	Basic net income per Limited Partner unit	$	1.12		$	0.24	$	1.55
	Diluted net income per Limited Partner unit	$	1.11		$	0.24	$	1.55
	The pro forma consolidated results of operations include adjustments to:
	•	include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
	•	include the results of PVR and Eagle Rock midstream beginning January 1, 2013;
	•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and
	•include incremental interest expense related to the financing of a proportionate share of the purchase price.
	The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
PVR Acquisition [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Regency’s Acquisition of Eagle Rock’s Midstream Business
	On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Regency accounted for the Eagle Rock Midstream Acquisition 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. This acquisition complements Regency’s core gathering and processing business and further diversifies Regency’s geographic presence in the Mid-Continent region, east Texas and south Texas. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
	Regency’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
	Assets	At July 1, 2014
	Current assets	$	120
	Property, plant and equipment	1,295
	Other non-current assets	4
	Goodwill(1)	49
	Total assets acquired	1,468
	Liabilities
	Current liabilities	116
	Long-term debt	499
	Other non-current liabilities	12
	Total liabilities assumed	627
	Net assets acquired	$	841
	(1)	None of the goodwill is expected to be deductible for tax purposes.
	Regency’s Acquisition of PVR Partners, L.P.
	On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the PVR Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
	Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
	Assets	At March 21, 2014
	Current assets	$	149
	Property, plant and equipment	2,716
	Investment in unconsolidated affiliates	62
	Intangible assets (average useful life of 30 years)	2,717
	Goodwill	370
	Other non-current assets	18
	Total assets acquired	6,032
	Liabilities
	Current liabilities	168
	Long-term debt	1,788
	Premium related to senior notes	99
	Non-current liabilities	30
	Total liabilities assumed	2,085
	Net assets acquired	$	3,947
Susser Merger [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Summary of Assets Acquired and Liabilities Assumed
	We accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.
	The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:
			Susser
	Total current assets		$	446
	Property, plant and equipment		1,069
	Goodwill(1)		1,734
	Intangible assets		611
	Other non-current assets		17
			3,877
	Total current liabilities		377
	Long-term debt, less current maturities		564
	Deferred income taxes		488
	Other non-current liabilities		39
	Noncontrolling interest		626
			2,094
	Total consideration		1,783
	Cash received		67
	Total consideration, net of cash received		$	1,716
	(1)	None of the goodwill is expected to be deductible for tax purposes.

Advances_to_and_Investments_in1

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2014
Investment In Affiliates [Abstract]
Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).
		December 31,
		2014		2013
	Current assets	$	889	$	1,028
	Property, plant and equipment, net	10,520		10,778
	Other assets	2,687		2,664
	Total assets	$	14,096	$	14,470
	Current liabilities	$	1,983	$	1,039
	Non-current liabilities	7,359		8,139
	Equity	4,754		5,292
	Total liabilities and equity	$	14,096	$	14,470
		Years Ended December 31,
		2014		2013		2012
	Revenue	$	4,925	$	4,695	$	4,492
	Operating income	1,071		1,197		863
	Net income	577		699		491
	In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Reconciliation Of Net Income (Loss) And Weighted Average Units	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
		Years Ended December 31,
		2014			2013		2012
	Income from continuing operations	$	1,060		$	282	$	1,383
	Less: Income from continuing operations attributable to noncontrolling interest	434			99		1,070
	Income from continuing operations, net of noncontrolling interest	626			183		313
	Less: General Partner’s interest in income from continuing operations	2			—		1
	Less: Class D Unitholder’s interest in income from continuing operations	2			—		—
	Income from continuing operations available to Limited Partners	$	622		$	183	$	312
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	544.3			560.9		533.4
	Basic income from continuing operations per Limited Partner unit	$	1.15		$	0.33	$	0.59
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.01		$	0.02	$	(0.02	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	622		$	183	$	312
	Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(2		)	—		(1		)
	Diluted income from continuing operations available to Limited Partners	620			183		311
	Weighted average limited partner units	544.3			560.9		533.4
	Dilutive effect of unconverted unit awards	1.1			—		—
	Weighted average limited partner units, assuming dilutive effect of unvested unit awards	545.4			560.9		533.4
	Diluted income from continuing operations per Limited Partner unit	$	1.14		$	0.33	$	0.59
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.01		$	0.02	$	(0.02	)

Debt_Obligations_Debt_Obligati

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Obligations [Abstract]
Schedule of debt obligations	Our debt obligations consist of the following:
		December 31,
		2014			2013
	Parent Company Indebtedness:
	7.50% Senior Notes, due October 15, 2020	$	1,187		$	1,187
	5.875% Senior Notes, due January 15, 2024	1,150			450
	ETE Senior Secured Term Loan, due December 2, 2019	1,400			1,000
	ETE Senior Secured Revolving Credit Facility due December 18, 2018	940			171
	Unamortized premiums, discounts and fair value adjustments, net	3			(7		)
		4,680			2,801
	Subsidiary Indebtedness:
	ETP Debt
	8.5% Senior Notes due April 15, 2014	—			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			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			800
	4.9% Senior Notes due February 1, 2024	350			350
	7.6% Senior Notes due February 1, 2024	277			277
	8.25% Senior Notes due November 15, 2029	267			267
	6.625% Senior Notes due October 15, 2036	400			400
	7.5% Senior Notes due July 1, 2038	550			550
	6.05% Senior Notes due June 1, 2041	700			700
	6.5% Senior Notes due February 1, 2042	1,000			1,000
	5.15% Senior Notes due February 1, 2043	450			450
	5.95% Senior Notes due October 1, 2043	450			450
	Floating Rate Junior Subordinated Notes due November 1, 2066	546			546
	ETP $2.5 billion Revolving Credit Facility due October 27, 2019	570			65
	Unamortized premiums, discounts and fair value adjustments, net	(1		)	(34		)
		11,459			11,213
	Panhandle Debt(1)
	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
	7.60% Senior Notes due February 1, 2024	82			82
	7.00% Senior Notes due July 15, 2029	66			66
	8.25% Senior Notes due November 14, 2029	33			33
	Floating Rate Junior Subordinated Notes due November 1, 2066	54			54
	Unamortized premiums, discounts and fair value adjustments, net	99			155
		1,184			1,240
	Regency Debt
	6.875% Senior Notes due December 1, 2018	—			600
	5.75% Senior Notes due September 1, 2020	400			400
	6.5% Senior Notes due July 15, 2021	500			500
	5.875% Senior Notes due March 1, 2022	900			—
	5.5% Senior Notes due April 15, 2023	700			700
	4.5% Senior Notes due November 1, 2023	600			600
	8.375% Senior Notes due June 1, 2020	390			—
	6.5% Senior Notes due May 15, 2021	400			—
	8.375% Senior Notes due June 1, 2019	499			—
	5.0% Senior Notes due October 1, 2022	700			—
	Regency $1.2 billion Revolving Credit Facility due November 25, 2019	1,504			510
	Unamortized premiums, discounts and fair value adjustments, net	48			—
		6,641			3,310
	Sunoco, Inc. Debt
	4.875% Senior Notes due October 15, 2014	—			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	35			70
	750			1,035
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014(2)	—			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			350
4.25% Senior Notes due April 1, 2024	500			—
6.85% Senior Notes due February 1, 2040	250			250
6.10% Senior Notes due February 15, 2042	300			300
4.95% Senior Notes due January 15, 2043	350			350
5.30% Senior Notes due April 1, 2044	700			—
5.35% Senior Notes due May 15, 2045	800			—
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3)	35			35
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018	150			200
Unamortized premiums, discounts and fair value adjustments, net	100			118
	4,260			2,503
Sunoco LP Debt
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	683			—
	683			—
Transwestern Debt
5.39% Senior Notes due November 17, 2014	—			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		)
	781			869
Other	223			228
	30,661			23,199
Less: current maturities	1,008			637
	$	29,653		$	22,562
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 $283 million in unamortized premiums and fair value adjustments, net:
	2015	$	1,050
	2016	314
	2017	1,228
	2018	2,095
	2019	5,662
	Thereafter	20,029
	Total	$	30,378

Redeemable_Preferred_Units_Tab

Redeemable Preferred Units (Tables)	12 Months Ended
	Dec. 31, 2014
Preferred Units, Preferred Partners' Capital Accounts [Abstract]
Schedule of Redeemable Preferred Units	The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
		Regency		Amount
		Preferred
		Units
	Balance, January 1, 2013	4.4		$	73
	Regency Preferred Units converted into Regency Common Units	(2.5	)	(41		)
	Balance, December 31, 2013	1.9		$	32		(1	)
	Accretion to redemption value	N/A		1
	Balance, December 31, 2014	1.9		33
	(1)	This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]	In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional ETP Class H Units and ETP Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
	Years Ending December 31,		Currently Effective				Pro Forma for			Pro Forma for Regency Merger(2)
							ETP Class H and
							Class I Units(1)
	2015		$	86			$	31		$	91
	2016		107				77			142
	2017		85				85			145
	2018		80				80			140
	2019		70				70			130
	2020		35				35			50
	2021		35				35			35
	2022		35				35			35
	2023		35				35			35
	2024		18				18			18
	(1)	Pro forma amounts reflect the IDR subsidies, as adjusted for the pending issuance of additional ETP Class H Units and ETP Class I Units discussed above, as well as distributions on the ETP Class I Units. The issuance of additional ETP Class H Units and ETP Class I Units is expected to close in March 2015.
	(2)	Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional ETP Class H Units and ETP Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of 2015 distribution payment and prior to the record date for the second quarter 2015 distribution payment.
Schedule Of Common Units Sold In Public Offering	The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
	Date		Number of			Price per			Net Proceeds
			Regency Common			Regency Unit
			Units
	Mar-12		12.7			$	24.47		$	297
	Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
	Date		Number of			Price per ETP			Net Proceeds
			ETP Common			Unit
			Units
	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.
Change In ETE Common Units	The change in ETE Common Units during the years ended December 31, 2014, 2013 and 2012 was as follows:
		Years Ended December 31,
		2014			2013			2012
	Number of Common Units, beginning of period	559.9			559.9			445.9
	Repurchase of common units under buyback program	(21.1	)		—			—
	Issuance of common units in connection with Southern Union Merger (See Note 3)	—			—			114
	Number of Common Units, end of period	538.8			559.9			559.9
Accumulated Other Comprehensive Income (Loss)	The following table presents the components of AOCI, net of tax:
		December 31,
		2014				2013
	Available-for-sale securities	$	3			$	2
	Foreign currency translation adjustment	(3		)		(1		)
	Net losses on commodity related hedges	(1		)		(4		)
	Actuarial gain (loss) related to pensions and other postretirement benefits	(57		)		56
	Investments in unconsolidated affiliates, net	2				8
	Subtotal	(56		)		61
	Amounts attributable to noncontrolling interest	51				(52		)
	Total AOCI included in partners’ capital, net of tax	$	(5	)		$	9
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):
		December 31,
		2014				2013
	Available-for-sale securities	$	(1	)		$	(1	)
	Foreign currency translation adjustment	2				1
	Actuarial gain relating to pension and other postretirement benefits	(37		)		(39		)
	Total	$	(36	)		$	(39	)
Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared during the years ended December 31, 2014, 2013 and 2012 were as follows:
	Quarter Ended		Record Date		Payment Date		Rate
	31-Dec-11		7-Feb-12		17-Feb-12		$	0.3125
	31-Mar-12		May 4, 2012		May 18, 2012		0.3125
	30-Jun-12		August 6, 2012		August 17, 2012		0.3125
	30-Sep-12		November 6, 2012		November 16, 2012		0.3125
	31-Dec-12		7-Feb-13		19-Feb-13		0.3175
	31-Mar-13		6-May-13		17-May-13		0.3225
	30-Jun-13		5-Aug-13		19-Aug-13		0.3275
	30-Sep-13		November 4, 2013		November 19, 2013		0.3363
	31-Dec-13		7-Feb-14		19-Feb-14		0.3463
	31-Mar-14		5-May-14		19-May-14		0.3588
	30-Jun-14		4-Aug-14		19-Aug-14		0.38
	30-Sep-14		3-Nov-14		19-Nov-14		0.415
	31-Dec-14		February 6, 2015		February 19, 2015		0.45
ETP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	ETP’s distributions declared during the periods presented below were as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							ETP Common Unit
	31-Dec-11		February 7, 2012		February 14, 2012		$	0.8938
	31-Mar-12		May 4, 2012		May 15, 2012		0.8938
	30-Jun-12		August 6, 2012		August 14, 2012		0.8938
	30-Sep-12		November 6, 2012		November 14, 2012		0.8938
	31-Dec-12		February 7, 2013		February 14, 2013		0.8938
	31-Mar-13		May 6, 2013		May 15, 2013		0.8938
	30-Jun-13		August 5, 2013		August 14, 2013		0.8938
	30-Sep-13		November 4, 2013		November 14, 2013		0.905
	31-Dec-13		7-Feb-14		14-Feb-14		0.92
	31-Mar-14		5-May-14		15-May-14		0.935
	30-Jun-14		4-Aug-14		14-Aug-14		0.955
	30-Sep-14		3-Nov-14		14-Nov-14		0.975
	31-Dec-14		February 6, 2015		February 13, 2015		0.995
Regency [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions declared by Regency during the years ended December 31, 2014, 2013 and 2012 were as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							Regency Common
							Unit
	31-Dec-11		February 6, 2012		February 13, 2012		$	0.46
	31-Mar-12		May 7, 2012		May 14, 2012		0.46
	30-Jun-12		August 6, 2012		August 14, 2012		0.46
	30-Sep-12		November 6, 2012		November 14, 2012		0.46
	31-Dec-12		7-Feb-13		14-Feb-13		0.46
	31-Mar-13		6-May-13		13-May-13		0.46
	30-Jun-13		5-Aug-13		14-Aug-13		0.465
	30-Sep-13		4-Nov-13		14-Nov-13		0.47
	31-Dec-13		7-Feb-14		14-Feb-14		0.475
	31-Mar-14		8-May-14		15-May-14		0.48
	30-Jun-14		7-Aug-14		14-Aug-14		0.49
	30-Sep-14		4-Nov-14		14-Nov-14		0.5025
	31-Dec-14		February 6, 2015		February 13, 2015		0.5025
Sunoco Logistics [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Sunoco Logistics Quarterly Distributions of Available Cash
	Distributions declared by Sunoco Logistics during the years ended December 31, 2014, 2013 and 2012 were as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							Sunoco Logistics
							Common Unit
	December 31, 2012		February 8, 2013		February 14, 2013		$	0.2725
	March 31, 2013		May 9, 2013		May 15, 2013		0.2863
	June 30, 2013		8-Aug-13		14-Aug-13		0.3
	September 30, 2013		8-Nov-13		14-Nov-13		0.315
	December 31, 2013		10-Feb-14		14-Feb-14		0.3312
	31-Mar-14		9-May-14		15-May-14		0.3475
	30-Jun-14		8-Aug-14		14-Aug-14		0.365
	30-Sep-14		7-Nov-14		14-Nov-14		0.3825
	31-Dec-14		9-Feb-15		13-Feb-15		0.4
Sunoco LP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Sunoco LP Quarterly Distributions of Available Cash
	Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							Sunoco LP
							Common Unit
	30-Sep-14		18-Nov-14		28-Nov-14		$	0.5457
	31-Dec-14		17-Feb-15		27-Feb-15		0.6

UnitBased_Compensation_Plans_U

Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	The following table shows the activity of the ETP awards granted to employees and non-employee directors:
		Number of		Weighted Average
		ETP Units		Grant-Date Fair Value
				Per ETP Unit
	Unvested awards as of December 31, 2013	3.2		$	49.65
	Awards granted	1		60.85
	Awards vested	(0.5	)	48.12
	Awards forfeited	(0.1	)	32.36
	Unvested awards as of December 31, 2014	3.6		53.83

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Federal and State Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
		Years Ended December 31,
		2014			2013			2012
	Current expense (benefit):
	Federal	$	321		$	51		$	(3	)
	State	86			(1		)	6
	Total	407			50			3
	Deferred expense (benefit):
	Federal	(53		)	(14		)	41
	State	3			57			10
	Total	(50		)	43			51
	Total income tax expense from continuing operations	$	357		$	93		$	54
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (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, 2014 and 2013 is as follows:
		31-Dec-14									31-Dec-13
		Corporate Subsidiaries(1)			Partnership(2)			Consolidated			Corporate Subsidiaries(1)			Partnership(2)			Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35 percent	$	212		$	—		$	212		$	(172	)	$	—		$	(172	)
	Increase (reduction) in income taxes resulting from:
	Nondeductible goodwill	—			—			—			241			—			241
	Nondeductible goodwill included in the Lake Charles LNG Transaction	105			—			105			—			—			—
	Premium on debt retirement	(10		)	—			(10		)	—			—			—
	Foreign taxes	(8		)	—			(8		)	—			—			—
	State income taxes (net of federal income tax effects)	9			46			55			31			10			41
	Other	3			—			3			(16		)	(1		)	(17		)
	Income tax from continuing operations	$	311		$	46		$	357		$	84		$	9		$	93
	(1)	Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of ETP Holdco.
	(2)	Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes.
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	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,
		2014			2013
	Deferred income tax assets:
	Net operating losses and alternative minimum tax credit	$	116		$	217
	Pension and other postretirement benefits	47			57
	Long term debt	53			108
	Other	111			104
	Total deferred income tax assets	327			486
	Valuation allowance	(84		)	(74		)
	Net deferred income tax assets	243			412
	Deferred income tax liabilities:
	Properties, plants and equipment	(1,583		)	(1,624		)
	Inventory	(153		)	(302		)
	Investments in unconsolidated affiliates	(2,530		)	(2,245		)
	Trademarks	(355		)	(180		)
	Other	(32		)	(45		)
	Total deferred income tax liabilities	(4,653		)	(4,396		)
	Net deferred income tax liability	(4,410		)	(3,984		)
	Less: current portion of deferred income tax liabilities, net	(85		)	(119		)
	Accumulated deferred income taxes	$	(4,325	)	$	(3,865	)
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits:
		Years Ended December 31,
		2014			2013			2012
	Balance at beginning of year	$	429		$	27		$	2
	Additions attributable to acquisitions	—			—			28
	Additions attributable to tax positions taken in the current year	20			—			—
	Additions attributable to tax positions taken in prior years	(1		)	406			—
	Settlements	(5		)	—			—
	Lapse of statute	(3		)	(4		)	(3		)
	Balance at end of year	$	440		$	429		$	27
Summary of Deferred Tax Liability Not Recognized [Table Text Block]	The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (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,
		2014			2013
	Net deferred income tax liability, beginning of year	$	(3,984	)	$	(3,696	)
	Susser acquisition	(488		)	—
	SUGS Contribution to Regency	—			(115		)
	Tax provision (including discontinued operations)	62			(124		)
	Other	—			(49		)
	Net deferred income tax liability	$	(4,410	)	$	(3,984	)

Regulatory_Matters_Commitments1

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Schedule of Rent Expense [Table Text Block]	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
			Years Ended December 31,
			2014				2013			2012
	Rental expense(1)		$	159			$	151		$	60
	Less: Sublease rental income		(26		)		(24		)	(4		)
	Rental expense, net		$	133			$	127		$	56
	(1)	Includes contingent rentals totaling $24 million, $22 million and $6 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Environmental Exit Costs by Cost [Table Text Block]
		December 31,
		2014				2013
	Current	$	41			$	47
	Non-current	360				356
	Total environmental liabilities	$	401			$	403
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum lease commitments for such leases are:
	Years Ending December 31:
	2015	$	151
	2016	129
	2017	118
	2018	108
	2019	102
	Thereafter	829
	Future minimum lease commitments	1,437
	Less: Sublease rental income	(34		)
	Net future minimum lease commitments	$	1,403

Price_Risk_Management_Assets_A1

Price Risk Management Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Offsetting Assets [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, 2014				December 31, 2013				December 31, 2014				December 31, 2013
	Derivatives in offsetting agreements:
	OTC contracts		Price risk management assets (liabilities)		$	23			$	42			$	(23	)		$	(38	)
	Broker cleared derivative contracts		Other current assets		674				264				(574		)		(318		)
					697				306				(597		)		(356		)
	Offsetting agreements:
	Counterparty netting		Price risk management assets (liabilities)		(19		)		(36		)		19				36
	Payments on margin deposit		Other current assets		5				(1		)		(22		)		55
					(14		)		(37		)		(3		)		91
	Net derivatives with offsetting agreements				683				269				(600		)		(265		)
	Derivatives without offsetting agreements				87				51				(171		)		(124		)
	Total derivatives				$	770			$	320			$	(771	)		$	(389	)
Interest Rate Swaps Outstanding	The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes:
							Notional Amount Outstanding
	Entity		Term		Type(1)		December 31,				December 31,
							2014				2013
	ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		$	—			$	400
	ETP		July 2015(2)		Forward-starting to pay a fixed rate of 3.38% and receive a floating rate		200				—
	ETP		July 2016(3)		Forward-starting to pay a fixed rate of 3.80% and receive a floating rate		200				—
	ETP		July 2017(4)		Forward-starting to pay a fixed rate of 3.84% and receive a floating rate		300				—
	ETP		July 2018(4)		Forward-starting to pay a fixed rate of 4.00% and receive a floating rate		200				—
	ETP		July 2019(4)		Forward-starting to pay a fixed rate of 3.19% and receive a floating rate		300				—
	ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		—				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 1.73% and receive a fixed rate of 3.60%		200				400
	Panhandle		Nov-21		Pay a fixed rate of 3.82% and receive a floating rate		—				275
	(1)	Floating rates are based on 3-month LIBOR.
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-14				31-Dec-13				31-Dec-14				31-Dec-13
	Derivatives designated as hedging instruments:
	Commodity derivatives (margin deposits)	$	43			$	3			$	—			$	(18	)
		43				3				—				(18		)
	Derivatives not designated as hedging instruments:
	Commodity derivatives (margin deposits)	$	617			$	227			$	(577	)		$	(209	)
	Commodity derivatives	107				43				(23		)		(48		)
	Interest rate derivatives	3				47				(155		)		(95		)
	Embedded derivatives in Regency Preferred Units	—				—				(16		)		(19		)
		727				317				(771		)		(371		)
	Total derivatives	$	770			$	320			$	(771	)		$	(389	)
Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives	The following tables summarize the amounts recognized with respect to our derivative financial instruments:
		Change in Value Recognized in OCI
		on Derivatives (Effective Portion)
		Years Ended December 31,
		2014				2013				2012
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	$	—			$	(1	)		$	8
	Total	$	—			$	(1	)		$	8
Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized
		Location of		Amount of Gain/(Loss) Reclassified from
		Gain/(Loss) Reclassified		AOCI into Income (Effective Portion)
		from AOCI into Income		Years Ended December 31,
		(Effective Portion)		2014				2013				2012
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	Cost of products sold		$	(3	)		$	4			$	14
	Total			$	(3	)		$	4			$	14
		Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income
		Recognized in		Representing Hedge Ineffectiveness and
		Income on Derivatives		Amount Excluded from the Assessment of
				Effectiveness
				Years Ended December 31,
				2014				2013				2012
	Derivatives in fair value hedging relationships (including hedged item):
	Commodity derivatives	Cost of products sold		$	(8	)		$	8			$	54
	Total			$	(8	)		$	8			$	54
		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized
				in Income on Derivatives
				Years Ended December 31,
				2014				2013				2012
	Derivatives not designated as hedging instruments:
	Commodity derivatives – Trading	Cost of products sold		$	(6	)		$	(11	)		$	(7	)
	Commodity derivatives – Non-trading	Cost of products sold		199				(21		)		26
	Commodity contracts – Non-trading	Deferred gas purchases		—				(3		)		(26		)
	Interest rate derivatives	Gains (losses) on interest rate derivatives		(157		)		53				(19		)
	Embedded derivatives	Other income		3				6				14
	Total			$	39			$	24			$	(12	)
ETP [Member]
Outstanding Commodity-Related Derivatives	The following table details ETP’s outstanding commodity-related derivatives:
		December 31, 2014					December 31, 2013
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	(232,500	)		2015		9,457,500			2014-2019
	Basis Swaps IFERC/NYMEX (1)	(13,907,500	)		2015 - 2016		(487,500	)		2014-2017
	Swing Swaps	—			—		1,937,500			2014-2016
	Options – Calls	5,000,000			2015		—			—
	Power (Megawatt):
	Forwards	288,775			2015		351,050			2014
	Futures	(156,000	)		2015		(772,476	)		2014
	Options — Puts	(72,000	)		2015		(52,800	)		2014
	Options — Calls	198,556			2105		103,200			2014
	Crude (Bbls) – Futures	—			—		103,000			2014
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	57,500			2015		570,000			2014
	Swing Swaps IFERC	46,150,000			2015		(9,690,000	)		2014-2016
	Fixed Swaps/Futures	(8,779,000	)		2015 - 2016		(8,195,000	)		2014-2015
	Forward Physical Contracts	(9,116,777	)		2015		5,668,559			2014-2015
	Natural Gas Liquid (Bbls) – Forwards/Swaps	(2,179,400	)		2015		(1,133,600	)		2014
	Refined Products (Bbls) – Futures	13,745,755			2015		(280,000	)		2014
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(39,287,500	)		2015		(7,352,500	)		2014
	Fixed Swaps/Futures	(39,287,500	)		2015		(50,530,000	)		2014
	Hedged Item — Inventory	39,287,500			2015		50,530,000			2014
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	—			—		(1,825,000	)		2014
	Fixed Swaps/Futures	—			—		(12,775,000	)		2014
	Natural Gas Liquid (Bbls) – Forwards/Swaps	—			—		(780,000	)		2014
	Crude (Bbls) – Futures	—			—		(30,000	)		2014
	(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Regency [Member]
Outstanding Commodity-Related Derivatives	The following table details Regency’s outstanding commodity-related derivatives:
		December 31, 2014					December 31, 2013
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu) — Fixed Swaps/Futures	(25,525,000	)		2015		(24,455,000	)		2014-2015
	Propane (Gallons) — Forwards/Swaps	(29,148,000	)		2015		(52,122,000	)		2014-2015
	NGLs (Barrels) — Forwards/Swaps	(292,000	)		2015		(438,000	)		2014
	WTI Crude Oil (Barrels) — Forwards/Swaps	(1,252,000	)		2015-2016		(521,000	)		2014

Retirement_Benefits_Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	Obligations and Funded Status
	Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.
	The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
		31-Dec-14												31-Dec-13
		Pension Benefits												Pension Benefits
		Funded Plans				Unfunded Plans				Other Postretirement Benefits				Funded Plans				Unfunded Plans				Other Postretirement Benefits
	Change in benefit obligation:
	Benefit obligation at beginning of period	$	632			$	61			$	223			$	1,117			$	78			$	296
	Service cost	—				—				—				3				—				—
	Interest cost	28				3				5				33				2				6
	Amendments	—				—				1				—				—				2
	Benefits paid, net	(45		)		(9		)		(28		)		(99		)		(16		)		(26		)
	Actuarial (gain) loss and other	130				10				2				(74		)		(3		)		(14		)
	Settlements	(27		)		—				—				(95		)		—				—
	Dispositions	—				—				—				(253		)		—				(41		)
	Benefit obligation at end of period	$	718			$	65			$	203			$	632			$	61			$	223
	Change in plan assets:
	Fair value of plan assets at beginning of period	600				—				284				906				—				312
	Return on plan assets and other	70				—				7				43				—				17
	Employer contributions	—				—				9				—				—				8
	Benefits paid, net	(45		)		—				(28		)		(99		)		—				(26		)
	Settlements	(27		)		—				—				(95		)		—				—
	Dispositions	—				—				—				(155		)		—				(27		)
	Fair value of plan assets at end of period	$	598			$	—			$	272			$	600			$	—			$	284
	Amount underfunded (overfunded) at end of period	$	120			$	65			$	(69	)		$	32			$	61			$	(61	)
	Amounts recognized in the consolidated balance sheets consist of:
	Non-current assets	$	—			$	—			$	96			$	—			$	—			$	86
	Current liabilities	—				(9		)		(2		)		—				(9		)		(2		)
	Non-current liabilities	(120		)		(56		)		(25		)		(32		)		(52		)		(23		)
		$	(120	)		$	(65	)		$	69			$	(32	)		$	(61	)		$	61
	Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
	Net actuarial gain	$	18			$	7			$	(21	)		$	(86	)		$	(4	)		$	(25	)
	Prior service cost	—				—				18				—				—				18
		$	18			$	7			$	(3	)		$	(86	)		$	(4	)		$	(7	)
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-14											31-Dec-13
		Pension Benefits											Pension Benefits
		Funded Plans				Unfunded Plans				Other Postretirement Benefits			Funded Plans				Unfunded Plans			Other Postretirement Benefits
	Projected benefit obligation	$	718			$	65			N/A			$	632			61			N/A
	Accumulated benefit obligation	718				65				203			632				61			$	223
	Fair value of plan assets	598				—				272			600				—			284
Schedule of Benefit Obligations Assumptions [Table Text Block]	Assumptions
	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
		December 31, 2014						31-Dec-13
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Discount rate	3.62	%		2.24	%		4.65	%		2.33	%
	Rate of compensation increase	N/A			N/A			N/A			N/A
Schedule or Description of Weighted Average Discount Rate [Table Text Block]	The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
		December 31, 2014						31-Dec-13
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Discount rate	4.65	%		3.02	%		3.5	%		2.68	%
	Expected return on assets:
	Tax exempt accounts	7.5	%		7	%		7.5	%		6.95	%
	Taxable accounts	N/A			4.5	%		N/A			4.42	%
	Rate of compensation increase	N/A			N/A			N/A			N/A
Schedule of Health Care Cost Trend Rates [Table Text Block]	The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
		December 31,
		2014			2013
	Health care cost trend rate	7.09	%		7.57	%
	Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.41	%		5.42	%
	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, 2014 Using Fair Value Hierarchy
			Fair Value as of December 31, 2014				Level 1				Level 2				Level 3
	Asset Category:
	Cash and cash equivalents		$	25			$	25			$	—			$	—
	Mutual funds (1)		110				—				110				—
	Fixed income securities		463				—				463				—
	Total		$	598			$	25			$	573			$	—
	-1	Comprised of 100% equities as of December 31, 2014.
							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 41% equities, 45% fixed income securities, and 14% in other investments as of December 31, 2013.
	The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
							Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy
			Fair Value as of December 31, 2014				Level 1				Level 2				Level 3
	Asset Category:
	Cash and Cash Equivalents		$	9			$	9			$	—			$	—
	Mutual funds (1)		138				138				—				—
	Fixed income securities		125				—				125				—
	Total		$	272			$	147			$	125			$	—
	-1	Primarily comprised of approximately 53% equities, 41% fixed income securities, 6% cash as of December 31, 2014.
							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.
	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]	Benefit Payments
	Panhandle’s and Sunoco, Inc.’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)
	2015		$	717			$	9			$	28
	2016		—				8				26
	2017		—				7				25
	2018		—				7				23
	2019		—				6				22
	2020 – 2024		—				23				65
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost
		31-Dec-14								31-Dec-13
		Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	—			$	—			$	3			$	—
	Interest cost	31				5				35				6
	Expected return on plan assets	(40		)		(8		)		(54		)		(9		)
	Prior service cost amortization	—				1				—				1
	Actuarial loss amortization	(1		)		(1		)		2				—
	Settlements	(4		)		—				(2		)		—
		(14		)		(3		)		(16		)		(2		)
	Regulatory adjustment(1)	—				—				5				—
	Net periodic benefit cost	$	(14	)		$	(3	)		$	(11	)		$	(2	)
	(1)	Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operation.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Reportable_Segments_Tables

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2014
Financial Information By Segment
		Years Ended December 31,
		2014			2013			2012
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	50,989		$	46,210		$	15,671
	Intersegment revenues	169			129			31
		51,158			46,339			15,702
	Investment in Regency:
	Revenues from external customers	4,597			2,404			1,986
	Intersegment revenues	354			117			14
		4,951			2,521			2,000
	Investment in Lake Charles LNG:
	Revenues from external customers	216			216			166
	Adjustments and Eliminations:	(634		)	(741		)	(904		)
	Total revenues	$	55,691		$	48,335		$	16,964
	Costs of products sold:
	Investment in ETP	$	45,540		$	41,204		$	12,266
	Investment in Regency	3,452			1,793			1,387
	Adjustments and Eliminations	(603		)	(443		)	(565		)
	Total costs of products sold	$	48,389		$	42,554		$	13,088
	Depreciation, depletion and amortization:
	Investment in ETP	1,130			1,032			656
	Investment in Regency	541			287			252
	Investment in Lake Charles LNG	39			39			30
	Corporate and Other	17			16			14
	Adjustments and Eliminations	(3		)	(61		)	(81		)
	Total depreciation, depletion and amortization	$	1,724		$	1,313		$	871
		Years Ended December 31,
		2014			2013			2012
	Equity in earnings of unconsolidated affiliates:
	Investment in ETP	$	234		$	172		$	142
	Investment in Regency	195			135			105
	Adjustments and Eliminations	(97		)	(71		)	(35		)
	Total equity in earnings of unconsolidated affiliates	$	332		$	236		$	212
		Years Ended December 31,
		2014			2013			2012
	Segment Adjusted EBITDA:
	Investment in ETP	$	4,829		$	3,953		$	2,744
	Investment in Regency	1,172			608			517
	Investment in Lake Charles LNG	195			187			135
	Corporate and Other	(97		)	(43		)	(52		)
	Adjustments and Eliminations	(259		)	(338		)	(239		)
	Total Segment Adjusted EBITDA	5,840			4,367			3,105
	Depreciation, depletion and amortization	(1,724		)	(1,313		)	(871		)
	Interest expense, net of interest capitalized	(1,369		)	(1,221		)	(1,018		)
	Bridge loan related fees	—			—			(62		)
	Gain on deconsolidation of Propane Business	—			—			1,057
	Gain on sale of AmeriGas common units	177			87			—
	Goodwill impairment	(370		)	(689		)	—
	Gains (losses) on interest rate derivatives	(157		)	53			(19		)
	Non-cash unit-based compensation expense	(82		)	(61		)	(47		)
	Unrealized gains on commodity risk management activities	116			48			10
	Losses on extinguishments of debt	(25		)	(162		)	(123		)
	Inventory valuation adjustments	(473		)	3			(75		)
	Adjusted EBITDA related to discontinued operations	(27		)	(76		)	(99		)
	Adjusted EBITDA related to unconsolidated affiliates	(748		)	(727		)	(647		)
	Equity in earnings of unconsolidated affiliates	332			236			212
	Non-operating environmental remediation	—			(168		)	—
	Other, net	(73		)	(2		)	14
	Income from continuing operations before income tax expense	$	1,417		$	375		$	1,437
		December 31,
		2014			2013			2012
	Total assets:
Investment in ETP	$	48,221		$	43,702		$	43,230
Investment in Regency	17,103			8,782			8,123
Investment in Lake Charles LNG	1,210			1,338			1,917
Corporate and Other	1,153			720			707
Adjustments and Eliminations	(3,218		)	(4,212		)	(5,073		)
Total	$	64,469		$	50,330		$	48,904
	Years Ended December 31,
	2014			2013			2012
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	4,478		$	2,455		$	3,049
Investment in Regency	1,112			1,011			599
Investment in Lake Charles LNG	1			2			4
Adjustments and Eliminations	(32		)	(126		)	(135		)
Total	$	5,559		$	3,342		$	3,517
	December 31,
	2014			2013			2012
Advances to and investments in affiliates:
Investment in ETP	$	3,840		$	4,436		$	3,502
Investment in Regency	2,418			2,097			2,214
Adjustments and Eliminations	(2,599		)	(2,519		)	(979		)
Total	$	3,659		$	4,014		$	4,737
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Regency.
Investment in ETP
	Years Ended December 31,
	2014			2013			2012
Intrastate Transportation and Storage	$	2,652		$	2,250		$	2,012
Interstate Transportation and Storage	1,057			1,270			1,109
Midstream	1,210			1,307			1,757
Liquids Transportation and Services	3,790			2,063			619
Investment in Sunoco Logistics	17,920			16,480			3,109
Retail Marketing	22,484			21,004			5,926
All Other	2,045			1,965			1,170
Total revenues	51,158			46,339			15,702
Less: Intersegment revenues	169			129			31
Revenues from external customers	$	50,989		$	46,210		$	15,671
Investment in Regency
	Years Ended December 31,
	2014			2013			2012
Gathering and Processing	$	4,570		$	2,287		$	1,797
Contract Services	307			215			183
Natural Gas Transportation	—			1			1
Natural Resources	58			—			—
Corporate and others	16			18			19
Total revenues	4,951			2,521			2,000
Less: Intersegment revenues	354			117			14
Revenues from external customers	$	4,597		$	2,404		$	1,986
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $216 million, $216 million and $166 million for the year ended December 31, 2014, 2013 and 2012, respectively, were related to LNG terminalling.

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information
		Quarters Ended
		March 31		June 30		September 30		December 31			Total Year
	2014:00:00
	Revenues	$	13,080	$	14,143	$	14,987	$	13,481		$	55,691
	Gross margin	1,638		1,792		1,972		1,900			7,302
	Operating income	710		773		822		165			2,470
	Net income (loss)	448		500		470		(294		)	1,124
	Limited Partners’ interest in net income	167		163		188		111			629
	Basic net income per limited partner unit	$	0.3	$	0.3	$	0.35	$	0.21		$	1.16
	Diluted net income per limited partner unit	$	0.3	$	0.3	$	0.35	$	0.21		$	1.15
		Quarters Ended
		March 31		June 30		September 30		December 31			Total Year
	2013:00:00
	Revenues	$	11,179	$	12,063	$	12,486	$	12,607		$	48,335
	Gross margin	1,372		1,498		1,422		1,489			5,781
	Operating income (loss)	531		644		529		(153		)	1,551
	Net income (loss)	322		338		356		(701		)	315
	Limited Partners’ interest in net income (loss)	90		127		150		(171		)	196
	Basic net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
	Diluted net income (loss) per limited partner unit	$	0.16	$	0.23	$	0.27	$	(0.31	)	$	0.35
	The three months ended December 31, 2014 reflected the unfavorable impacts of $456 million related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and Regency’s recognition of a goodwill impairment of $370 million. The three months ended December 31, 2013 reflected ETP’s recognition of a goodwill impairment of $689 million.

Supplemental_Financial_Stateme1

Supplemental Financial Statement Information (Tables) (Parent Company [Member])	12 Months Ended
	Dec. 31, 2014
Parent Company [Member]
Schedule Of Balance Sheets	BALANCE SHEETS
		December 31,
		2014			2013
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	2		$	8
	Accounts receivable from related companies	14			5
	Other current assets	1			—
	Total current assets	17			13
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,390			3,841
	INTANGIBLE ASSETS, net	10			14
	GOODWILL	9			9
	OTHER NON-CURRENT ASSETS, net	46			41
	Total assets	$	5,472		$	3,918
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable to related companies	$	11		$	11
	Interest payable	58			24
	Accrued and other current liabilities	3			3
	Total current liabilities	72			38
	LONG-TERM DEBT, less current maturities	4,680			2,801
	NOTE PAYABLE TO AFFILIATE	54			—
	OTHER NON-CURRENT LIABILITIES	2			1
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	(1		)	(3		)
	Limited Partners:
	Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively)	648			1,066
	Class D Units (1,540,000 units authorized, issued and outstanding)	22			6
	Accumulated other comprehensive income (loss)	(5		)	9
	Total partners’ capital	664			1,078
	Total liabilities and partners’ capital	$	5,472		$	3,918
Schedule Of Statements Of Operations	STATEMENTS OF OPERATIONS
		Years Ended December 31,
		2014			2013			2012
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(111	)	$	(56	)	$	(53	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized	(205		)	(210		)	(235		)
	Bridge loan related fees	—			—			(62		)
	Equity in earnings of unconsolidated affiliates	955			617			666
	Gains (losses) on interest rate derivatives	—			9			(15		)
	Loss on extinguishment of debt	—			(157		)	—
	Other, net	(5		)	(8		)	(4		)
	INCOME BEFORE INCOME TAXES	634			195			297
	Income tax expense (benefit)	1			(1		)	(7		)
	NET INCOME	633			196			304
	GENERAL PARTNER’S INTEREST IN NET INCOME	2			—			2
	CLASS D UNITHOLDER’S INTEREST IN NET INCOME	2			—			—
	LIMITED PARTNERS’ INTEREST IN NET INCOME	$	629		$	196		$	302
Schedule Of Statements Of Cash Flows	STATEMENTS OF CASH FLOWS
		Years Ended December 31,
		2014			2013			2012
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	816		$	768		$	555
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Cash paid for acquisitions	—			—			(1,113		)
	Proceeds from ETP Holdco Transaction	—			1,332			—
	Contributions to unconsolidated affiliates	(118		)	(8		)	(487		)
	Purchase of additional interest in Regency	(800		)	—			—
	Note payable to affiliate	54			—			—
	Note receivable from affiliate	—			—			(221		)
	Payments received on note receivable from affiliate	—			166			55
	Net cash provided by (used in) investing activities	(864		)	1,490			(1,766		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from borrowings	3,020			2,080			2,108
	Principal payments on debt	(1,142		)	(3,235		)	(162		)
	Distributions to partners	(821		)	(733		)	(666		)
	Redemption of Preferred Units	—			(340		)	—
	Units repurchased under buyback program	(1,000		)	—			—
	Debt issuance costs	(15		)	(31		)	(78		)
	Net cash provided by (used in) financing activities	42			(2,259		)	1,202
	DECREASE IN CASH AND CASH EQUIVALENTS	(6		)	(1		)	(9		)
	CASH AND CASH EQUIVALENTS, beginning of period	8			9			18
	CASH AND CASH EQUIVALENTS, end of period	$	2		$	8		$	9

Operations_And_Organization_Sc

Operations And Organization (Schedule Of Equity Interests (Details)	Dec. 31, 2014	Oct. 05, 2012
In Millions, unless otherwise specified
Incentive Distribution Rights		100.00%
ETP [Member]
Incentive Distribution Rights	100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	30.8
Regency [Member]
Incentive Distribution Rights		100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	57.2
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.	31.4
Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	50.2
Class F Units [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.	6.3

Operations_And_Organization_Na

Operations And Organization (Narrative) (Details)	12 Months Ended	9 Months Ended
	Dec. 31, 2014	Sep. 30, 2013	Oct. 05, 2012	Mar. 25, 2012
Incentive Distribution Rights			100.00%
LNG Storage Capacity	9
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
FEP [Member] | Fayetteville Express Pipeline, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
FEP [Member] | FGT [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Regency [Member]
Incentive Distribution Rights			100.00%
Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%
Interest ownership	30.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Interest ownership	50.00%
ETP [Member]
Incentive Distribution Rights	100.00%
Sunoco LP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	42.80%
Citrus Merger [Member]
Interest ownership				50.00%

Estimates_Significant_Accounti3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 25, 2012		Oct. 05, 2012		Aug. 29, 2014	Mar. 21, 2014
Inventory Write-down	$473,000,000
Long-term Debt, Fair Value	31,680,000,000	23,970,000,000
Goodwill, Period Increase (Decrease)	1,970,000,000
Goodwill impairment	370,000,000	689,000,000	0
Goodwill acquired	2,323,000,000	156,000,000
GOODWILL	7,865,000,000	5,894,000,000	6,434,000,000
Long-term Debt	30,661,000,000	23,199,000,000
Retail Marketing [Member]
Excise Taxes Collected	2,460,000,000	2,220,000,000	573,000,000
Lake Charles LNG [Member]
GOODWILL	873,000,000	184,000,000
Southern Union Merger [Member]
Goodwill				2,497,000,000	[1]
Sunoco Merger [Member]
Goodwill						2,641,000,000	[2]
Susser Merger [Member]
Goodwill								1,734,000,000
PVR Acquisition [Member]
Goodwill								370,000,000	370,000,000
Investment In Regency [Member]
Goodwill impairment	370,000,000	0
Goodwill acquired	449,000,000	0
GOODWILL	1,223,000,000	1,127,000,000	1,127,000,000
Lake Charles LNG [Member]
Goodwill impairment	0	689,000,000
Goodwill acquired	0	0
GOODWILL	$184,000,000	$184,000,000	$873,000,000
[1]	Includes ETP’s acquisition of Citrus.
[2]	Includes amounts recorded with respect to Sunoco Logistics.

Estimates_Schedule_Of_Net_Chan

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Accounts receivable	$600	($556)	$267
Accounts receivable from related companies	30	64	-9
Inventories	51	-254	-258
Exchanges receivable	18	-8	14
Increase (Decrease) in Other Current Assets	-133	81	-597
Other non-current assets, net	-6	-23	-129
Accounts payable	-850	541	-989
Accounts payable to related companies	5	-140	92
Exchanges payable	-99	128	0
Accrued and other current liabilities	-59	192	-159
Other non-current liabilities	-73	147	26
Price risk management assets and liabilities, net	19	-159	-3
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	($231)	($149)	($551)

Estimates_Schedule_Of_NonCash_

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$643	$226	$420
Net gains (losses) from subsidiary common unit transactions	744	-384	80
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	0	0	1,123
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	0	2,354
Long term debt exchanged in connection with acquisitions	499	0	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,416	1,256	997
Cash paid for income taxes	345	58	23
Subsidiary units issued in certain acquisitions [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	0	2,295
Subsidiary units issued in PVR, Hoover and Eagle Rock Midstream Acquisitions [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	4,281	0	0
Subsidiary units issued in Susser Merger [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	908	0	0
PVR Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$1,887	$0	$0

Estimates_Schedule_of_Inventor

Estimates (Schedule of Inventory) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Inventory, Net [Abstract]
Natural gas and NGLs	$392	$577
Energy Related Inventory, Crude Oil, Products and Merchandise	364	488
Inventory, refined products	392	543
Appliances, parts and fittings and other	319	199
Total inventories	$1,467	$1,807

Estimates_Other_Current_Assets

Estimates (Other Current Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Information [Abstract]
Deposits paid to vendors	$65	$49
Deferred Tax Assets, Net, Current	14	0
Prepaid expenses and other	222	263
Total other current assets	$301	$312

Estimates_Property_Plant_and_E

Estimates (Property, Plant and Equipment) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$45,018	$33,917
Less - Accumulated depreciation	-4,726	-3,235
PROPERTY, PLANT AND EQUIPMENT, net	40,292	30,682
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,307	881
Building and Building Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,922	939
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	27,149	21,494
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,214	1,083
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	4,010	1,933
Tanks and other equipment (5 to 40 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	58	1,697
Retail Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	515	450
Vehicles [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	203	156
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,451	2,190
Furniture and fixtures (2 to 25 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	59	51
Linepack [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	119	118
Pad gas [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	44	52
Natural Resources [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	454	0
Other (1 to 30 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	999	708
Construction work-in-process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$4,514	$2,165

Estimates_Schedule_Of_Property

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Depreciation expense	$1,457	$1,128	$801
Capitalized interest, excluding AFUDC	$113	$43	$99

Estimates_Schedule_Of_Goodwill

Estimates (Schedule Of Goodwill) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Apr. 30, 2013
Goodwill [Roll Forward]
Goodwill	$5,894		$6,434
Goodwill acquired	2,323		156
Goodwill	7,865		5,894		6,434
Goodwill impairment	-370		-689		0
Goodwill, Other Changes	18		-7
Goodwill, Written off Related to Sale of Business Unit	0	[1]	0	[2]
Investment In ETP [Member]
Goodwill [Roll Forward]
Goodwill	4,729		5,606
Goodwill acquired	1,874		156
Goodwill	6,419		4,729
Goodwill impairment	0		-689
Goodwill, Other Changes	0		-7
Goodwill, Written off Related to Sale of Business Unit	-184	[1]	-337	[2]
Investment In Regency [Member]
Goodwill [Roll Forward]
Goodwill	1,127		1,127
Goodwill acquired	449		0
Goodwill	1,223		1,127
Goodwill impairment	-370		0
Goodwill, Other Changes	17		0
Goodwill, Written off Related to Sale of Business Unit	0	[1]	0	[2]
Lake Charles LNG [Member]
Goodwill [Roll Forward]
Goodwill	184		873
Goodwill acquired	0		0
Goodwill	184		184
Goodwill impairment	0		-689
Goodwill, Other Changes	0		0
Goodwill, Written off Related to Sale of Business Unit	0	[1]	0	[2]
Corporate And Others [Member]
Goodwill [Roll Forward]
Goodwill	-146		-1,172
Goodwill acquired	0		0
Goodwill	39		-146
Goodwill impairment	0		689
Goodwill, Other Changes	1		0
Goodwill, Written off Related to Sale of Business Unit	184	[1]	337	[2]
SUGS [Member]
Goodwill [Roll Forward]
Goodwill						337
Goodwill						$337
[1]	As discussed in Note 3, ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2012 and 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $873 million and$184 million, respectively, in both the investment in ETP and investment in Lake Charles LNG segments that was correspondingly included in the elimination column. The transaction was effective January 1, 2014.
[2]	As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013 which was a transaction between entities under common control. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012. Therefore, the December 31, 2012 goodwill balance includes goodwill attributable to SUGS of $337 million in both segments that was correspondingly included in the elimination column. ETP deconsolidated SUGS on April 30, 2013.

Estimates_Components_And_Usefu

Estimates (Components And Useful Lives Of Intangibles And Other Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Total Intangible Assets [Member]
Gross Carrying Amount	$6,100	$2,550
Accumulated Amortization	518	286
Customer Contracts [Member]
Gross Carrying Amount	5,144	2,135
Accumulated Amortization	485	264
Trade names [Member]
Gross Carrying Amount	556	66
Accumulated Amortization	15	12
Patents [Member]
Gross Carrying Amount	48	48
Accumulated Amortization	11	6
Other [Member]
Gross Carrying Amount	36	7
Accumulated Amortization	7	4
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	5,784	2,256
Accumulated Amortization	518	286
Trademarks [Member]
Gross Carrying Amount	316	294
Accumulated Amortization	$0	$0

Estimates_Significant_Accounti4

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2014
Trade names [Member]
Intangible assets, useful life, minimum (years)	20 years 0 months 0 days
Patents [Member]
Intangible assets, useful life, minimum (years)	9 years 0 months 0 days
Minimum [Member] | Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	5 years 0 months 0 days
Minimum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	5 years 0 months 0 days
Minimum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	5 years 0 months 0 days
Minimum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	2 years 0 months 0 days
Minimum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	5 years 0 months 0 days
Minimum [Member] | Retail Equipment [Member]
Property, plant and equipment, useful life, minimum (years)	3 years 0 months 0 days
Minimum [Member] | Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	1 year 0 months 0 days
Minimum [Member] | Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	20 years 0 months 0 days
Minimum [Member] | Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	2 years 0 months 0 days
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	1 year 0 months 0 days
Minimum [Member] | Customer relationships, contracts and agreements [Member]
Intangible assets, useful life, minimum (years)	3 years 0 months 0 days
Minimum [Member] | Other [Member]
Intangible assets, useful life, minimum (years)	10 years 0 months 0 days
Maximum [Member] | Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	45 years 0 months 0 days
Maximum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years 0 months 0 days
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	46 years 0 months 0 days
Maximum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years 0 months 0 days
Maximum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	40 years 0 months 0 days
Maximum [Member] | Retail Equipment [Member]
Property, plant and equipment, useful life, minimum (years)	99 years 0 months 0 days
Maximum [Member] | Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	25 years 0 months 0 days
Maximum [Member] | Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years 0 months 0 days
Maximum [Member] | Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	25 years 0 months 0 days
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	48 years 0 months 0 days
Maximum [Member] | Customer relationships, contracts and agreements [Member]
Intangible assets, useful life, minimum (years)	46 years 0 months 0 days
Maximum [Member] | Other [Member]
Intangible assets, useful life, minimum (years)	15 years 0 months 0 days

Estimates_Aggregate_Amortizati

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) (Depreciation And Amortization [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$219	$120	$70

Estimates_Estimated_Aggregate_

Estimates (Estimated Aggregate Amortization Expense) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Goodwill and Intangible Assets Disclosure [Abstract]
2015	$263
2016	260
2017	260
2018	259
2019	$256

Estimates_Schedule_of_Other_No

Estimates (Schedule of Other Non-Current Assets, net) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Unamortized financing costs (3 to 30 years)	$203	$167
Regulatory assets	85	86
Deferred Costs, Noncurrent	220	144
Restricted Cash and Cash Equivalents, Current	177	378
Other	223	147
Total other non-current assets, net	$908	$922

Estimates_Significant_Accounti5

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Asset Retirement Obligations) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Asset Retirement Obligation	$188	$180
Interstate Transportation and Storage [Member]
Asset Retirement Obligation	58	55
Retail Marketing [Member]
Asset Retirement Obligation	87	84
Investment in Sunoco Logistics [Member]
Asset Retirement Obligation	41	41
Investment In Regency [Member]
Asset Retirement Obligation	$2	$0

Estimates_Accrued_And_Other_Cu

Estimates (Accrued And Other Current Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Information [Abstract]
Interest payable	$440	$357
Customer advances and deposits	103	142
Accrued Capital Expenditures	673	260
Accrued wages and benefits	233	173
Taxes payable other than income taxes	236	211
Income taxes payable	54	4
Deferred Tax Liabilities, Net, Current	99	119
Other Accrued Liabilities, Current	363	412
Total accrued and other current liabilities	$2,201	$1,678

Estimates_Fair_Value_Of_Financ

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long-term Debt, Fair Value	$31,680	$23,970
Total liabilities	-749
Long-term Debt	30,661	23,199
Level 1 [Member]
Total liabilities	-551
Level 2 [Member]
Total liabilities	-182
Level 3 [Member]
Total liabilities	-16
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives	3	47
Commodity derivatives:	745	231
Total assets	748	278
Interest rate derivatives	-155	-95
Embedded derivatives in the Regency Preferred Units	-16	-19
Commodity derivatives:	-578	-233
Total liabilities		-347
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Interest rate derivatives	0	0
Commodity derivatives:	632	217
Total assets	632	217
Interest rate derivatives	0	0
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	-551	-215
Total liabilities		-215
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Interest rate derivatives	3	47
Commodity derivatives:	113	14
Total assets	116	61
Interest rate derivatives	-155	-95
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	-27	-18
Total liabilities		-113
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Interest rate derivatives	0	0
Commodity derivatives:	0	0
Total assets	0	0
Interest rate derivatives	0	0
Embedded derivatives in the Regency Preferred Units	-16	-19
Commodity derivatives:	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		19
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Forward Swaps [Member]
Commodity derivatives:	36
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	36
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Commodity derivatives:	3	3
Commodity derivatives:	4	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:	4
Commodity derivatives:	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	4
Commodity derivatives:	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	3	3
Commodity derivatives:	4	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Commodity derivatives:		5
Commodity derivatives:	7	5
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Commodity derivatives:	21
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:		5
Commodity derivatives:	7	5
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	21
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	19	5
Commodity derivatives:	-18	-4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	26	8
Commodity derivatives:	-25	-6
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	566	203
Commodity derivatives:	-490	-206
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	19	5
Commodity derivatives:	-18	-4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	1	1
Commodity derivatives:	-2	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	541	201
Commodity derivatives:	-490	-201
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	25	7
Commodity derivatives:	-23	-6
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	25	2
Commodity derivatives:	0	-5
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Commodity derivatives:		7
Commodity derivatives:	-32	-9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	46	5
Commodity derivatives:	-32	-5
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	23	2
Commodity derivatives:	0	-4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Condensate Forward Swaps [Member]
Embedded derivatives in the Regency Preferred Units		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Forward Physical Swaps [Member]
Trading Liabilities, Fair Value Disclosure		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Condensate Forward Swaps [Member]
Embedded derivatives in the Regency Preferred Units		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Trading Liabilities, Fair Value Disclosure		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Condensate Forward Swaps [Member]
Embedded derivatives in the Regency Preferred Units		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Trading Liabilities, Fair Value Disclosure		-1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 3 [Member] | Condensate Forward Swaps [Member]
Embedded derivatives in the Regency Preferred Units		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Trading Liabilities, Fair Value Disclosure		$0

Estimates_Significant_Accounti6

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Fair Value Schedule of Unobservable Inputs) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Payments for Repurchase of Preferred Stock and Preference Stock	$0	$340	$0
Net unrealized gains included in other income (expense)	3
Liabilities, Fair Value Disclosure, Recurring	749
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	4.76%
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	35.80%
Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	16
Fair Value, Measurements, Recurring [Member]
Liabilities, Fair Value Disclosure, Recurring		347
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		$19

Estimates_Reconciliation_For_L

Estimates (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net unrealized gains included in other income (expense)	$3
Payments for Repurchase of Preferred Stock and Preference Stock	0	340	0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		$19

Acquisitions_and_Related_Trans2

Acquisitions and Related Transactions Acquisitions (2014 Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended								12 Months Ended			1 Months Ended			0 Months Ended	1 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2012	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, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2014	Aug. 31, 2014	Feb. 28, 2014	Jan. 26, 2015	Oct. 31, 2012	Oct. 05, 2012	Aug. 29, 2014	Oct. 01, 2014	Mar. 21, 2014	Jun. 24, 2013	Jan. 31, 2015
Related Party Transaction, Amounts of Transaction										$75
Incentive Distribution Rights																		100.00%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2,200,000
Revenues		13,481	14,987	14,143	13,080	12,607	12,486	12,063	11,179	55,691	48,335	16,964
Net income		-294	470	500	448	-701	356	338	322	1,124	315	1,274
Debt Instrument, Interest Rate, Stated Percentage		4.50%								4.50%
Asset Retirement Obligation		188				180				188	180
MACS Transaction [Member]
Business Combination, Consideration Transferred													768
PVR Acquisition [Member]
Revenues										956
Net income										166
Eagle Rock Midstream Acquisition [Member]
Revenues										903
Net income										30
Sunoco LP [Member]
Business Combination, Consideration Transferred													556
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares													4,000,000	11,000,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed															18,700,000
Regency Merger [Member]
Relinquishment Of Rights Of Incentive Distributions																320
Susser Merger [Member]
Business Combination, Consideration Transferred														875
Relinquishment Of Rights Of Incentive Distributions																	350
Payments to Acquire Businesses, Gross														1,800
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares														15,800,000
Number of Stores																			630
Dealer-operated [Member] | MACS Transaction [Member]
Number of Stores																				200
Relinquishment, Year 1 [Member] | Regency Merger [Member]
Relinquishment Of Rights Of Incentive Distributions																80
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]
Relinquishment Of Rights Of Incentive Distributions																60
Company-operated [Member] | MACS Transaction [Member]
Number of Stores																				110
Susser [Member]
Incentive Distribution Rights																			100.00%
Revenues										2,320
Net income										105
Business Combination, Acquisition Related Costs										25
Regency [Member]
Incentive Distribution Rights																		100.00%
Regency [Member] | PVR Acquisition [Member]
Stock Issued During Period, Shares, Acquisitions										140,400,000
Business Combination, Consideration Transferred										5,700
Payments to Acquire Businesses, Gross										36
Business Acquisition, Share Price																					$27.82
Regency [Member] | Eagle Rock Midstream Acquisition [Member]
Proceeds from Issuance of Common Stock										400
Stock Issued During Period, Shares, Acquisitions										8,200,000
Business Combination, Consideration Transferred										1,300
Regency [Member] | Hoover Midstream Acquisition [Member]
Stock Issued During Period, Shares, Acquisitions										4,000,000
Business Combination, Consideration Transferred										300
Payments to Acquire Businesses, Gross										184
Asset Retirement Obligation		2								2
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument, Interest Rate, Stated Percentage																						7.60%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage																						8.25%
8.375% Senior Notes due June 1, 2019 [Member] | Regency [Member]
Senior Notes		$499				$0				$499	$0
Debt Instrument, Interest Rate, Stated Percentage		8.38%								8.38%
Pending Merger [Member] | Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share																							0.4066
Business Acquisition, Share Price																							$0.32

Acquisitions_and_Related_Trans3

Acquisitions and Related Transactions Acquisitions (2013 Narrative) (Details) (USD $)	0 Months Ended	12 Months Ended			1 Months Ended	9 Months Ended	1 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2013	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Guarantor Obligations, Current Carrying Value		$600
Proceeds from the sale of other assets		62	89	44
Proceeds from divestiture of business		0	0	1,123
Number of Regency Common Units to be Issued in Acquisition Per Share		1.02
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2,200,000
SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred					463
Cash Acquired from Acquisition					30
Holdco Transaction [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					49,500,000
Payments to Acquire Businesses, Gross					1,400
Estimated Closing Adjustments					68
Regency [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		31,400,000
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		57,200,000
Regency [Member] | PVR Acquisition [Member]
Business Acquisition [Line Items]
Proceeds from divestiture of business		1,800
Business Combination, Consideration Transferred		5,700
Payments to Acquire Businesses, Gross		36
Regency [Member] | Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		1,300
Regency [Member] | Hoover Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		300
Payments to Acquire Businesses, Gross		184
Regency [Member] | Common Units [Member] | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					31,400,000
Regency [Member] | Class F Units [Member] | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					6,300,000
ETP [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		30,800,000
Panhandle [Member] | Regency [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		31,400,000
Panhandle [Member] | Regency [Member] | Class F Units [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		6,300,000
Panhandle [Member] | ETP [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		2,200,000
ETE [Member] | Holdco [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						60.00%
ETP [Member] | Holdco [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%				40.00%
New England Gas Company [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets							40
Proceeds from divestiture of business							20
Missouri Gas Energy [Member]
Business Acquisition [Line Items]
Proceeds from the sale of other assets								$975

Acquisitions_and_Related_Trans4

Acquisitions and Related Transactions Acquisitions (2012 Narrative) (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

3 Months Ended

1 Months Ended

Share data in Millions, unless otherwise specified

Mar. 31, 2012

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, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 31, 2012

Apr. 30, 2013

Sep. 30, 2012

Jan. 12, 2012

Sep. 30, 2013

Jun. 30, 2012

Sep. 30, 2013

Oct. 05, 2012

Mar. 25, 2012

Business Acquisition [Line Items]

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

2.2

General Partner Interest

2.00%

Incentive Distribution Rights

100.00%

Revenues

$13,481,000,000

$14,987,000,000

$14,143,000,000

$13,080,000,000

$12,607,000,000

$12,486,000,000

$12,063,000,000

$11,179,000,000

$55,691,000,000

$48,335,000,000

$16,964,000,000

Net Income (Loss) Attributable to Parent

633,000,000

196,000,000

304,000,000

Proceeds from the sale of other assets

62,000,000

89,000,000

44,000,000

Southern Union Merger [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

3,010,000,000

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

57

Business Combination, Acquisition Related Costs

38,000,000

Citrus Merger [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

2,000,000,000

Interest ownership

50.00%

Payments to Acquire Businesses, Gross

1,900,000,000

Sunoco Merger [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

2,600,000,000

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

55

Business Combination, Acquisition Related Costs

28,000,000

Revenues

5,930,000,000

Net Income (Loss) Attributable to Parent

14,000,000

Holdco Transaction [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

1,400,000,000

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

49.5

Relinquishment Of Rights Of Incentive Distributions

210,000,000

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

12

Canyon Disposal [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

207,000,000

Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax

132,000,000

ETP's Propane Operations [Member]

Business Acquisition [Line Items]

Proceeds from the sale of other assets

1,460,000,000

Sunoco [Member] | Holdco Transaction [Member]

Business Acquisition [Line Items]

Cash Acquired from Acquisition

2,000,000,000

ETP [Member]

Business Acquisition [Line Items]

Incentive Distribution Rights

100.00%

100.00%

Southern Union [Member]

Business Acquisition [Line Items]

Revenues

1,260,000,000

Net Income (Loss) Attributable to Parent

39,000,000

Holdco [Member] | ETE [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

60.00%

Holdco [Member] | ETP [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

40.00%

PES Joint Venture [Member] | Carlyle Group [Member]

Business Acquisition [Line Items]

Interest ownership

67.00%

67.00%

PES Joint Venture [Member] | Sunoco [Member]

Business Acquisition [Line Items]

Interest ownership

33.00%

33.00%

Retained Interest, Fair Value Disclosure

75,000,000

75,000,000

Sunoco Logistics [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

32.00%

Sunoco Logistics [Member] | Sunoco Merger [Member]

Business Acquisition [Line Items]

Revenues

3,110,000,000

Net Income (Loss) Attributable to Parent

145,000,000

AmeriGas [Member]

Business Acquisition [Line Items]

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

30

Long-term debt assumed and non-compete agreement notes payable issued in acquisitions

71,000,000

Contingent Residual Support Agreement Obligation

1,550,000,000

1,550,000,000

1,500,000,000

AmeriGas [Member] | Propane Cylinder Exchange Business [Member]

Business Acquisition [Line Items]

Proceeds from the sale of other assets

43,000,000

Class F Units [Member] | ETP [Member] | Holdco Transaction [Member]

Business Acquisition [Line Items]

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

90.7

Missouri Gas Energy [Member]

Business Acquisition [Line Items]

Proceeds from the sale of other assets

$975,000,000

Acquisitions_and_Related_Trans5

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

Acquisitions_Schedule_Of_Asset

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) (USD $)	Oct. 05, 2012		Mar. 25, 2012		Jul. 01, 2014	Aug. 29, 2014	Mar. 21, 2014
In Millions, unless otherwise specified
Sunoco Merger [Member]
Business Acquisition [Line Items]
Current assets	$7,312	[1]
Property, plant and equipment	6,686	[1]
Goodwill	2,641	[1]
Intangible assets	1,361	[1]
Investments in unconsolidated affiliates	240	[1]
Note receivable	821	[1]
Other assets	128	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	19,189	[1]
Current liabilities	4,424	[1]
Long-term debt obligations, less current maturities	2,879	[1]
Deferred income taxes	1,762	[1]
Other non-current liabilities	769	[1]
Noncontrolling interest	3,580	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	13,414	[1]
Total consideration	5,775	[1]
Cash received	2,714	[1]
Total consideration, net of cash received	3,061	[1]
Southern Union Merger [Member]
Business Acquisition [Line Items]
Current assets			556	[2]
Property, plant and equipment			6,242	[2]
Goodwill			2,497	[2]
Intangible assets			55	[2]
Investments in unconsolidated affiliates			2,023	[2]
Note receivable			0	[2]
Other assets			163	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			11,536	[2]
Current liabilities			1,348	[2]
Long-term debt obligations, less current maturities			3,120	[2]
Deferred income taxes			1,419	[2]
Other non-current liabilities			284	[2]
Noncontrolling interest			0	[2]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			6,171	[2]
Total consideration			5,365	[2]
Cash received			37	[2]
Total consideration, net of cash received			5,328	[2]
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Current assets					120
Property, plant and equipment					1,295
Goodwill					49
Other assets					4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					1,468
Current liabilities					116
Long-term debt obligations, less current maturities					499
Other non-current liabilities					12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					627
Total consideration					841
PVR Acquisition [Member]
Business Acquisition [Line Items]
Current assets							149
Property, plant and equipment							2,716
Goodwill						370	370
Intangible assets							2,717
Investments in unconsolidated affiliates							62
Other assets							18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets							6,032
Current liabilities							168
Long-term debt obligations, less current maturities							1,788
Business Combination, Purchase Price Allocation, Premium on Long Term Debt							99
Other non-current liabilities							30
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities							2,085
Total consideration							3,947
Susser Merger [Member]
Business Acquisition [Line Items]
Current assets						446
Property, plant and equipment						1,069
Goodwill						1,734
Intangible assets						611
Other assets						17
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets						3,877
Current liabilities						377
Long-term debt obligations, less current maturities						564
Deferred income taxes						488
Other non-current liabilities						39
Noncontrolling interest						626
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities						2,094
Total consideration						1,783
Cash received						67
Total consideration, net of cash received						$1,716
[1]	Includes amounts recorded with respect to Sunoco Logistics.
[2]	Includes ETP’s acquisition of Citrus.

Acquisitions_Pro_Forma_Results

Acquisitions (Pro Forma Results Of Operations Table) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Revenues	$56,517,000,000	$50,473,000,000	$40,398
Net income	1,098,000,000	252,000,000	868
Net income attributable to partners	$607,000,000	$133,000,000	$866
Basic net income (loss) per Limited Partner unit	$1.12	$0.24	$1.55
Diluted net income (loss) per Limited Partner unit	$1.11	$0.24	$1.55

Advances_to_and_Investments_in2

Advances to and Investments in Unconsolidated Affiliates (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
Share data in Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 12, 2012	Mar. 25, 2012
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2.2
Proceeds from the sale of other assets		$62,000,000	$89,000,000	$44,000,000
AmeriGas common units sold by ETP		-18.9	-7.5
Cash proceeds from the sale of AmeriGas common units		814,000,000	346,000,000	0
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		3,659,000,000	4,014,000,000	4,737,000,000
Proceeds from divestiture of business		0	0	1,123,000,000
Gain on deconsolidation of Propane Business		0	0	1,057,000,000
Equity in earnings of unconsolidated affiliates		332,000,000	236,000,000	212,000,000
SUG [Member]
Interest ownership		50.00%
Payments to Acquire Businesses, Gross	1,900,000,000
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable	105,000,000
Citrus [Member]
Interest ownership		50.00%
FGT [Member]
Percentage Ownership Operating Facility		100.00%
Fayetteville Express Pipeline, LLC [Member]
Interest ownership		50.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership		50.00%
RIGS Haynesville Partnership Co. [Member]
Interest ownership		49.99%
AmeriGas [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					30
Cash proceeds from the sale of AmeriGas common units		814,000,000	346,000,000
Investment Owned, Balance, Shares		3.1
Citrus Corp [Member]
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Citrus Merger [Member]
Interest ownership						50.00%
Payments to Acquire Businesses, Gross	1,900,000,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		1,030,000,000
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		2,000,000,000
FEP [Member] | ETP [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		130,000,000	144,000,000
Citrus [Member] | ETP [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		1,820,000,000	1,890,000,000
RIGS Haynesville Partnership Co. [Member] | Regency [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		422,000,000	442,000,000
MEP [Member] | Regency [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		$695,000,000	$548,000,000
AmeriGas [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					29.6

Investments_in_Affiliates_Summ

Investments in Affiliates (Summarized Balance Sheet Information) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Investment In Affiliates [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	$889	$1,028
Property, plant and equipment, net	10,520	10,778
Other assets	2,687	2,664
Total assets	14,096	14,470
Current Liabilities	1,983	1,039
Non-current liabilities	7,359	8,139
Equity	4,754	5,292
Total liabilities and equity	$14,096	$14,470

Investments_in_Affiliates_Summ1

Investments in Affiliates (Summarized Income Statement Information) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Investment In Affiliates [Abstract]
Revenues	$4,925	$4,695	$4,492
Operating Income	1,071	1,197	863
Net income	$577	$699	$491

Net_Income_Per_Limited_Partner2

Net Income Per Limited Partner Unit (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Income (loss) from continuing operations	$1,060	$282	$1,383
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	434	99	1,070
Income from continuing operations, net of noncontrolling interest	626	183	313
General Partner’s interest in income from continuing operations	2	0	1
Class D Unitholder's interest income from continuing operations	2	0	0
Income from continuing operations available to Limited Partners	622	183	312
Dilutive effect of equity-based compensation of subsidiaries	-2	0	-1
Net Income (Loss) Available to Common Stockholders, Diluted	$620	$183	$311
Weighted average Limited Partner units	544.3	560.9	533.4
Basic	$1.15	$0.33	$0.59
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share	$0.01	$0.02	($0.02)
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	1.1	0	0
Weighted average Limited Partner units	545.4	560.9	533.4
Diluted	$1.14	$0.33	$0.59
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share	$0.01	$0.02	($0.02)

Debt_Obligations_Debt_Obligati1

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Other Long-term Debt	$223	$228
Debt Instrument, Unamortized Discount (Premium), Net	283
Long-term Debt	30,661	23,199
Current maturities of long-term debt	1,008	637
LONG-TERM DEBT, less current maturities	29,653	22,562
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	3	-7
Long-term Debt	4,680	2,801
LONG-TERM DEBT, less current maturities	4,680	2,801
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Oct-20
Senior Notes	1,187	1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jan-24
Senior Notes	1,150	450
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	2-Dec-18
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	2-Dec-19
Secured Debt	1,400	1,000
Parent Company [Member] | ETE Senior Secured Revolving Credit Facilities [Member]
Debt Instrument [Line Items]
Outstanding borrowings	940	171
ETP [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	-1	-34
Long-term Debt	11,459	11,213
ETP [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-24
Senior Notes	700	700
ETP [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Nov-29
Senior Notes	1,000	1,000
ETP [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Nov-66
Junior Subordinated Notes	450	450
ETP [Member] | 8.5% Senior Notes, due April 15, 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Apr-14
Senior Notes	0	292
ETP [Member] | 5.95% Senior Notes, due February 1, 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-15
Senior Notes	750	750
ETP [Member] | 6.125% Senior Notes, due February 15, 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-17
Senior Notes	400	400
ETP [Member] | 6.7% Senior Notes, due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jul-18
Senior Notes	600	600
ETP [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Mar-19
Senior Notes	400	400
ETP [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Apr-19
Senior Notes	450	450
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Oct-20
Senior Notes	267	267
ETP [Member] | Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jun-21
Senior Notes	700	700
ETP [Member] | Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-22
Senior Notes	800	800
ETP [Member] | 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-23
Senior Notes	350	350
ETP [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-24
Senior Notes	400	400
ETP [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jul-38
Senior Notes	800	800
ETP [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jun-41
Senior Notes	450	450
ETP [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-42
Senior Notes	546	546
ETP [Member] | 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-43
Senior Notes	277	277
ETP [Member] | 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Oct-43
Senior Notes	550	550
ETP [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Oct-36
Senior Notes	1,000	1,000
ETP [Member] | ETP Revolving Credit Facility, due October 27, 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	27-Oct-19
Outstanding borrowings	570	65
Regency [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	48	0
Long-term Debt	6,641	3,310
Regency [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-May-18
Outstanding borrowings	1,504	510
Regency [Member] | 6.875% Senior Notes, due December 1, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Dec-18
Senior Notes	0	600
Regency [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Sep-20
Senior Notes	400	400
Regency [Member] | 6.5% Senior Notes, due July 15, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jul-21
Senior Notes	500	500
Regency [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Mar-22
Senior Notes	900	0
Regency [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Apr-23
Senior Notes	700	700
Regency [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Nov-23
Senior Notes	600	600
Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jun-20
Senior Notes	390	0
Regency [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-May-21
Senior Notes	400	0
Regency [Member] | 8.375% Senior Notes due June 1, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jun-19
Senior Notes	499	0
Regency [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Oct-22
Senior Notes	700	0
Sunoco [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	35	70
Long-term Debt	750	1,035
Sunoco [Member] | 4.875% Senior Notes, due 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Oct-14
Senior Notes	0	250
Sunoco [Member] | 9.625% Senior Notes, due 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Apr-15
Senior Notes	250	250
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jan-17
Senior Notes	400	400
Sunoco [Member] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Nov-24
Subordinated Debt	65	65
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	100	118
Long-term Debt	4,260	2,503
Sunoco Logistics [Member] | 8.75% Senior Notes, due February 15, 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-14
Senior Notes	0	175
Sunoco Logistics [Member] | 6.125% Senior Notes, due May 15, 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-May-16
Senior Notes	175	175
Sunoco Logistics [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-20
Senior Notes	250	250
Sunoco Logistics [Member] | Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-22
Senior Notes	300	300
Sunoco Logistics [Member] | 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jan-23
Senior Notes	250	250
Sunoco Logistics [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-40
Senior Notes	-350	-350
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	-500	0
Sunoco Logistics [Member] | Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Feb-42
Senior Notes	350	350
Sunoco Logistics [Member] | 5.30% Senior Notes due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Apr-44
Senior Notes	700	0
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-May-45
Senior Notes	800	0
Sunoco Logistics [Member] | 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jan-43
Senior Notes	300	300
Sunoco Logistics [Member] | Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	21-Aug-14
Sunoco Logistics [Member] | Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	30-Apr-15
Outstanding borrowings	35	35
Sunoco Logistics [Member] | Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	22-Aug-16
Sunoco Logistics [Member] | Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Nov-18
Outstanding borrowings	150	200
Sunoco Logistics [Member] | Sunoco LP $1.25 billion Revolving Credit Facility, due September 25, 2019 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	683	0
Sunoco LP [Member]
Debt Instrument [Line Items]
Long-term Debt	683	0
Sunoco LP [Member] | Sunoco LP $1.25 billion Revolving Credit Facility, due September 25, 2019 [Member]
Debt Instrument [Line Items]
Outstanding borrowings	683
Transwestern [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	-1	-1
Long-term Debt	781	869
Transwestern [Member] | 5.39% Senior Unsecured Notes, due November 17, 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	17-Nov-14
Senior Notes	0	88
Transwestern [Member] | 5.54% Senior Unsecured Notes, due November 17, 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	17-Nov-16
Senior Notes	125	125
Transwestern [Member] | 5.64% Senior Unsecured Notes, due May 24, 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	24-May-17
Senior Notes	82	82
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	9-Dec-20
Senior Notes	175	175
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	24-May-22
Senior Notes	150	150
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	9-Dec-24
Senior Notes	175	175
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	24-May-37
Senior Notes	75	75
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	99	155
Long-term Debt	1,184	1,240
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Feb-24
Senior Notes	82	82
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	14-Nov-29
Senior Notes	33	33
Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes	54	54
Panhandle [Member] | 6.20% Senior Notes, due November 1, 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Nov-17
Senior Notes	300	300
Panhandle [Member] | 7.00% Senior Notes, due June 15, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jun-18
Senior Notes	400	400
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	1-Jun-19
Senior Notes	150	150
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	15-Jul-29
Senior Notes	$66	$66
Panhandle [Member] | Term Loan due February 23, 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	23-Feb-15

Debt_Obligations_Debt_Obligati2

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]
2015	$1,050
2016	314
2017	1,228
2018	2,095
2019	5,662
Thereafter	20,029
Long-term Debt	30,661	23,199
Excluding unamortized premiums and fair value adjustments [Member]
Debt Instrument [Line Items]
Long-term Debt	$30,378

Debt_Obligations_Senior_Notes_

Debt Obligations (Senior Notes and Term Loans Narrative) (Details) (USD $)	3 Months Ended								12 Months Ended			1 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 31, 2014	Jun. 24, 2013	1-May-14	Feb. 28, 2014	Oct. 05, 2012	Jul. 01, 2014	Apr. 30, 2014
Noncontrolling interest	$21,650,000,000				$15,201,000,000				$21,650,000,000	$15,201,000,000
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST									491,000,000	119,000,000	970,000,000
Leverage Ratio Maximum									6
Net income	-294,000,000	470,000,000	500,000,000	448,000,000	-701,000,000	356,000,000	338,000,000	322,000,000	1,124,000,000	315,000,000	1,274,000,000
Maximum Leverage Ratio Permitted									7
Required repayment of term loan									50,000,000
Repayments of Long-term Debt									13,886,000,000	11,951,000,000	8,848,000,000
Write off of Deferred Debt Issuance Cost											-62,000,000
Long-term Debt	30,661,000,000				23,199,000,000				30,661,000,000	23,199,000,000
Debt instrument, interest rate, stated percentage	4.50%								4.50%
Debt Instrument, Covenant Description									0.66
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,659,000,000				4,014,000,000				3,659,000,000	4,014,000,000	4,737,000,000
Equity in earnings of unconsolidated affiliates									332,000,000	236,000,000	212,000,000
8.25% Senior Notes, due November 14, 2029 [Member]
Debt instrument, interest rate, stated percentage													8.25%
ETE Credit Facility [Member]
Letters Of Credit Availablity	150,000,000								150,000,000
Line of Credit Facility, Current Borrowing Capacity	600,000,000								600,000,000					1,200,000,000	800,000,000
Line of Credit Facility, Maximum Borrowing Capacity	1,000,000,000								1,000,000,000
Sunoco Merger [Member]
Senior Notes	715,000,000								715,000,000							965,000,000
7.60% Senior Notes, due February 1, 2024 [Member]
Debt instrument, interest rate, stated percentage													7.60%
SUG [Member] | Junior Subordinated Debt [Member]
Debt Instrument, Description of Variable Rate Basis									three-month LIBOR rate plus 3.0175%
SUG [Member] | Variable Rate Portion of Debt [Member] | Junior Subordinated Debt [Member]
Senior Notes	54,000,000								54,000,000
Parent Company [Member]
Repayments of Long-term Debt									1,142,000,000	3,235,000,000	162,000,000
Write off of Deferred Debt Issuance Cost									0	0
Long-term Debt	4,680,000,000				2,801,000,000				4,680,000,000	2,801,000,000
Repayments of Related Party Debt									0	0	221,000,000
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,390,000,000				3,841,000,000				5,390,000,000	3,841,000,000
Equity in earnings of unconsolidated affiliates									955,000,000	617,000,000	666,000,000
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes	1,150,000,000				450,000,000				1,150,000,000	450,000,000
Debt instrument, interest rate, stated percentage	5.88%								5.88%
Debt Instrument, Maturity Date									15-Jan-24
Panhandle [Member]
Long-term Debt	1,184,000,000				1,240,000,000				1,184,000,000	1,240,000,000
ETP [Member]
Leverage Ratio Maximum									5
Maximum Leverage Ratio Permitted									5.5
Long-term Debt	11,459,000,000				11,213,000,000				11,459,000,000	11,213,000,000
ETP [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument, Interest Rate, Effective Percentage	3.26%								3.26%
Debt instrument, interest rate, stated percentage	7.20%								7.20%
Debt Instrument, Maturity Date									1-Nov-66
Sunoco Logistics [Member]
Long-term Debt	4,260,000,000				2,503,000,000				4,260,000,000	2,503,000,000
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Senior Notes	800,000,000				0				800,000,000	0
Debt instrument, interest rate, stated percentage	5.35%								5.35%
Debt Instrument, Maturity Date									15-May-45
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes	-500,000,000				0				-500,000,000	0
Sunoco Logistics [Member] | April 2014 Offering [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes	300,000,000								300,000,000
Debt instrument, interest rate, stated percentage	4.25%								4.25%
Sunoco Logistics [Member] | Increase in senior notes [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes	200,000,000								200,000,000
Regency [Member]
Long-term Debt	6,641,000,000				3,310,000,000				6,641,000,000	3,310,000,000
Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member]
Redemption Premium												8,000,000
Debt Instrument, Repurchase Amount																	91,000,000
Debt Instrument, Repurchased Face Amount																	83,000,000
Regency [Member] | 8.25% Senior Notes due April 15, 2018 [Member]
Debt Instrument, Repurchase Amount																		313,000,000
Debt Instrument, Repurchased Face Amount																		300,000,000
Regency [Member] | Senior Notes due 2018 [Member]
Debt Instrument, Repurchase Amount	621,000,000								621,000,000
Debt Instrument, Repurchased Face Amount	600,000,000								600,000,000
Regency [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Senior Notes	900,000,000				0				900,000,000	0
Debt instrument, interest rate, stated percentage	5.88%								5.88%
Debt Instrument, Maturity Date									1-Mar-22
Regency [Member] | 8.375% Senior Notes due June 1, 2019 [Member]
Senior Notes	499,000,000				0				499,000,000	0
Debt instrument, interest rate, stated percentage	8.38%								8.38%
Debt Instrument, Maturity Date									1-Jun-19
Regency [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Senior Notes	700,000,000				0				700,000,000	0
Debt instrument, interest rate, stated percentage	5.00%								5.00%
Debt Instrument, Maturity Date									1-Oct-22
Base Rate Loans [Member] | Maximum [Member] | ETE Credit Facility [Member]
Debt Instrument, Basis Spread on Variable Rate									1.50%
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Original issuance amount [Member]
Line of Credit Facility, Current Borrowing Capacity	1,000,000,000								1,000,000,000
ETE Senior Secured Term Loan due December 2, 2019 [Member] | After increase in capacity [Member]
Line of Credit Facility, Current Borrowing Capacity	1,400,000,000								1,400,000,000
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Increase in term loan [Member]
Line of Credit Facility, Current Borrowing Capacity	400,000,000								400,000,000
Regency [Member] | ETE Common Holdings [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	760,000,000				0				760,000,000	0
Equity in earnings of unconsolidated affiliates									-9,000,000	0
Regency [Member] | ETE GP Acquirer [Member]
Noncontrolling interest	8,700,000,000				4,000,000,000				8,700,000,000	4,000,000,000
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST									-188,000,000	8,000,000	23,000,000
ETP [Member] | ETP GP [Member]
Noncontrolling interest	11,942,000,000				11,308,000,000				11,942,000,000	11,308,000,000
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST									823,000,000	-50,000,000	1,108,000,000
ETP [Member] | ETE Common Holdings [Member]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	1,720,000,000				1,660,000,000				1,720,000,000	1,660,000,000
Equity in earnings of unconsolidated affiliates									292,000,000	134,000,000
PVR Acquisition [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions									1,200,000,000
PVR Acquisition [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions									400,000,000
PVR Acquisition [Member] | 8.375% Senior Notes due June 1, 2020 [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions									473,000,000
PVR Acquisition [Member] | 8.25% Senior Notes due April 15, 2018 [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions									300,000,000
PVR Acquisition [Member] | Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions									$473,000,000

Debt_Obligations_Credit_Facili

Debt Obligations (Credit Facilities Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	1-May-14	Feb. 28, 2014	Feb. 18, 2015
Bridge loan related fees	$0	$0	$62,000,000
Long-term Debt	30,661,000,000	23,199,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Parent Company [Member]
Long-term Debt	4,680,000,000	2,801,000,000
Repayments of Related Party Debt	0	0	221,000,000
ETP [Member]
Long-term Debt	11,459,000,000	11,213,000,000
Sunoco Logistics [Member]
Long-term Debt	4,260,000,000	2,503,000,000
Sunoco LP [Member]
Long-term Debt	683,000,000	0
Regency [Member]
Long-term Debt	6,641,000,000	3,310,000,000
ETE Credit Facility [Member]
Revolving credit facility	600,000,000			1,200,000,000	800,000,000
Letters Of Credit Availablity	150,000,000
Line of Credit Facility, Maximum Borrowing Capacity	1,000,000,000
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member]
Amount Outstanding	940,000,000	171,000,000
Regency Credit Facility [Member]
Revolving credit facility	2,000,000,000
Credit Facility, Incremental Borrowing Capacity	500,000,000
Amount Outstanding	1,504,000,000
Amount available for future borrowings	473,000,000
Letters of credit outstanding, amount	23,000,000
Weighted average interest rate on amount outstanding	2.17%
Line Of Credit Facility Fronting Fee Percentage	0.20%
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Revolving credit facility	35,000,000
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] | Sunoco Logistics [Member]
Revolving credit facility	1,500,000,000
Line of Credit Facility, Maximum Borrowing Capacity	2,250,000,000
Sunoco LP $1.25 billion Revolving Credit Facility, due September 25, 2019 [Member] | Sunoco LP [Member]
Revolving credit facility	1,250,000,000
Line of Credit Facility, Maximum Borrowing Capacity	250,000,000
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	1-Nov-18
Amount Outstanding	150,000,000	200,000,000
ETP Revolving Credit Facility, due October 27, 2016 [Member] | ETP [Member]
Debt Instrument, Maturity Date	27-Oct-19
Amount Outstanding	570,000,000	65,000,000
Revolving Credit Facility [Member] | Regency [Member]
Debt Instrument, Maturity Date	1-May-18
Amount Outstanding	1,504,000,000	510,000,000
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	22-Aug-16
Sunoco LP $1.25 billion Revolving Credit Facility, due September 25, 2019 [Member] | Sunoco Logistics [Member]
Amount Outstanding	683,000,000	0
Sunoco LP $1.25 billion Revolving Credit Facility, due September 25, 2019 [Member] | Sunoco LP [Member]
Amount Outstanding	683,000,000
Federal Funds Effective Rate [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.50%
LIBOR [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.00%
ETE Credit Facility [Member]
Revolving credit facility						1,500,000,000
Maximum [Member] | Regency Credit Facility [Member]
Line of credit facility, unused capacity, commitment fee percentage	0.45%
Line Of Credit Participation Fee	2.50%
Maximum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	2.50%
Maximum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.50%
Maximum [Member] | Base Rate Loans [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.50%
Maximum [Member] | Eurodollar Loans [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	2.50%
Minimum [Member] | Regency Credit Facility [Member]
Line of credit facility, unused capacity, commitment fee percentage	0.30%
Line Of Credit Participation Fee	1.63%
Minimum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.75%
Minimum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.75%
Minimum [Member] | Base Rate Loans [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	0.63%
Minimum [Member] | Eurodollar Loans [Member] | Regency Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.63%
ETP Revolving Credit Facility, due October 27, 2016 [Member]
Revolving credit facility	2,500,000,000
Line of Credit Facility, Maximum Borrowing Capacity	3,750,000,000
ETP Revolving Credit Facility, due October 27, 2016 [Member] | ETP [Member]
Amount available for future borrowings	1,810,000,000
Line Of Credit Maturity October 27, 2016 [Member]
Letters of credit outstanding, amount	121,000,000
Line Of Credit Maturity October 27, 2016 [Member] | ETP Revolving Credit Facility, due October 27, 2016 [Member] | ETP [Member]
Line of Credit Facility, Interest Rate at Period End	1.66%
PVR Acquisition [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	1,200,000,000
PVR Acquisition [Member] | 8.25% Senior Notes due April 15, 2018 [Member]
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$300,000,000

Debt_Obligations_Debt_Obligati3

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014
Debt Instrument [Line Items]
Leverage Ratio Maximum		6
Maximum Leverage Ratio Permitted		7
Debt instrument covenant minimum fixed charge coverage ratio		1.5
Debt Instrument, Covenant Description		0.66
West Texas Gulf [Member]
Debt Instrument [Line Items]
Fixed Charge Coverage Ratio		1.67
Leverage Ratio Maximum		2
Debt instrument covenant minimum fixed charge coverage ratio	1
Leverage Ratio		0.85
ETP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum		5
Maximum Leverage Ratio Permitted		5.5
Regency [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio		5
Maximum consolidated EBITA to consolidated interest expense		2.5
Maximum consolidated senior secured leverage ratio		3
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio		5
Adjusted EBITDA Ratio		3.7
Sunoco LP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum		5.5
Maximum Leverage Ratio Permitted		6
Debt Instrument, Covenant Description		50
Acquisition Period [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio		5.5

Debt_Obligations_Debt_Obligati4

Debt Obligations Debt Obligations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2014
Debt Instrument, Interest Rate, Stated Percentage	4.50%
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	15-Oct-20
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	15-Jan-24
ETE Senior Secured Term Loan due December 2, 2018 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	2-Dec-18
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	2-Dec-19
8.5% Senior Notes, due April 15, 2014 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.50%
Debt Instrument, Maturity Date	15-Apr-14
5.95% Senior Notes, due February 1, 2015 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	1-Feb-15
6.125% Senior Notes, due February 15, 2017 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	15-Feb-17
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.70%
Debt Instrument, Maturity Date	1-Jul-18
9.7% Senior Notes, due March 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%
Debt Instrument, Maturity Date	15-Mar-19
9.0% Senior Notes due April 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	15-Apr-19
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt Instrument, Maturity Date	1-Oct-20
Senior Notes 4.65% Due June 1, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	1-Jun-21
Senior Notes 5.20% Due February 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt Instrument, Maturity Date	1-Feb-22
3.6% Senior Notes due February 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	1-Feb-23
4.9% Senior Notes due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	1-Feb-24
6.625% Senior Notes, due October 15, 2036 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument, Maturity Date	15-Oct-36
7.5% Senior Notes, due July 1, 2038 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	1-Jul-38
Senior Notes 6.05% Due June 1, 2041 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt Instrument, Maturity Date	1-Jun-41
Senior Notes 6.50% Due February 1, 2042 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	1-Feb-42
5.15% Senior Notes due February 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	1-Feb-43
5.95% Senior Notes due October 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	1-Oct-43
ETP Revolving Credit Facility, due October 27, 2016 [Member] | ETP [Member]
Debt Instrument, Maturity Date	27-Oct-19
6.20% Senior Notes, due November 1, 2017 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Debt Instrument, Maturity Date	1-Nov-17
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	15-Jun-18
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.13%
Debt Instrument, Maturity Date	1-Jun-19
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	15-Jul-29
Term Loan due February 23, 2015 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.84%
Debt Instrument, Maturity Date	23-Feb-15
6.875% Senior Notes, due December 1, 2018 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument, Maturity Date	1-Dec-18
5.75% Senior Notes due September 1, 2020 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	1-Sep-20
6.5% Senior Notes, due July 15, 2021 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	15-Jul-21
5.875% Senior Notes due April 1, 2022 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	1-Mar-22
5.5% Senior Notes, due April 15, 2023 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	15-Apr-23
4.5% Senior Notes due November 1, 2023 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	1-Nov-23
8.375% Senior Notes due June 1, 2020 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.38%
Debt Instrument, Maturity Date	1-Jun-20
6.5% Senior Notes due May 15, 2021 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	15-May-21
8.375% Senior Notes due June 1, 2019 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.38%
Debt Instrument, Maturity Date	1-Jun-19
5.0% Senior Notes due October 1, 2022 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	1-Oct-22
Revolving Credit Facility [Member] | Regency [Member]
Debt Instrument, Maturity Date	1-May-18
7.60% Senior Notes, due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	1-Feb-24
7.60% Senior Notes, due February 1, 2024 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	1-Feb-24
8.25% Senior Notes, due November 14, 2029 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	15-Nov-29
8.25% Senior Notes, due November 14, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	14-Nov-29
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt Instrument, Maturity Date	1-Nov-66
4.875% Senior Notes, due 2014 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.88%
Debt Instrument, Maturity Date	15-Oct-14
9.625% Senior Notes, due 2015 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.63%
Debt Instrument, Maturity Date	15-Apr-15
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	15-Jan-17
9.00% Debentures, due 2024 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	1-Nov-24
8.75% Senior Notes, due February 15, 2014 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.75%
Debt Instrument, Maturity Date	15-Feb-14
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	15-May-16
5.50% Senior Notes, due February 15, 2020 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	15-Feb-20
Senior Note 4.65% Due February 15, 2022 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	15-Feb-22
3.45% Senior Notes due January 2023 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt Instrument, Maturity Date	15-Jan-23
6.85% Senior Notes, due February 15, 2040 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt Instrument, Maturity Date	15-Feb-40
Senior Note 6.10%, due February 15, 2042 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	15-Feb-42
4.95% Senior Notes due January 2043 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	15-Jan-43
5.30% Senior Notes due April 1, 2044 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	1-Apr-44
5.35% Senior Notes due May 15, 2045 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.35%
Debt Instrument, Maturity Date	15-May-45
Sunoco Logistics $200 million Revolving Credit Facility, due August 21, 2014 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	21-Aug-14
Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	30-Apr-15
Sunoco Logistics $350 million Revolving Credit Facility, due August 22, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	22-Aug-16
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date	1-Nov-18
5.39% Senior Unsecured Notes, due November 17, 2014 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.39%
Debt Instrument, Maturity Date	17-Nov-14
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.54%
Debt Instrument, Maturity Date	17-Nov-16
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.64%
Debt Instrument, Maturity Date	24-May-17
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt Instrument, Maturity Date	9-Dec-20
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt Instrument, Maturity Date	24-May-22
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt Instrument, Maturity Date	9-Dec-24
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt Instrument, Maturity Date	24-May-37

Redeemable_Preferred_Units_Det

Redeemable Preferred Units (Details) (USD $)	12 Months Ended			3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2011	25-May-10	Dec. 31, 2012
Preferrred Units Issued Stated Price	$100
Proceeds from Issuance of Preferred Stock and Preference Stock	$300
Preferred Stock Redemption Premium	40
Gain Recognized from Conversion of Series A Preferred Units	26
Conversion of Stock, Amount Converted		-41
ETE Preferred Units [Member]
Preferred units, issued					3,000,000
Aggregate liquidation preference					300
Quarterly cash distribution, per preferred unit				$2
Preferred units outstanding	3,000,000
Preferred units carrying value non-cash adjustment	9	8
Regency Preferred Units [Member]
Preferred units outstanding	1,900,000	1,900,000				4,371,586
Subsidiary preferred unit mandatory redemption date	9/2/29
Mandatory redeemable price of units outstanding	33	32				73
Conversion of Stock, Shares Converted		-2,459,017
Conversion of Stock, Amount Converted		-41	[1]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,064,805
Regency Mandatorily Redeemable Amount At Expiration [Member]
Mandatory redeemable price of units outstanding	$35
[1]	(1) This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Redeemable_Preferred_Units_Sch

Redeemable Preferred Units Schedule Of Redeemable Preferred Units (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Preferred Units [Line Items]
Conversion of Stock, Amount Converted		($41)
Regency Preferred Units [Member]
Preferred Units [Line Items]
Preferred Units, Outstanding	1,900,000	1,900,000		4,371,586
Preferred Units Redemption Amount	33	32		73
Conversion of Stock, Shares Converted		-2,459,017
Conversion of Stock, Amount Converted		-41	[1]
Accretion to Redemption Value, Adjustment	$1
[1]	(1) This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.

Equity_Narrative_Details

Equity (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended		0 Months Ended	3 Months Ended		1 Months Ended		0 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2013	Jul. 31, 2012	Mar. 31, 2012	Sep. 30, 2014	Dec. 31, 2014	Oct. 31, 2012	Aug. 31, 2014	Jan. 26, 2015	Mar. 31, 2015	Feb. 20, 2015	Dec. 31, 2011	Oct. 05, 2012
Stock Repurchase Program, Authorized Amount	$1,000,000,000							$1,000,000,000					$2,000,000,000
Partners' Capital Account, Units, Unit-based Compensation	21,063,775	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	1,500,000
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding	20.00%							20.00%
Limited Partners' Capital Account, Units Outstanding	538,766,899	559,923,300	559,900,000					538,766,899						445,900,000
Limited Partner interest in the Partnership, percentage	99.46%
Gain from subsidiary issuances of common units	744,000,000	-384,000,000	80,000,000
Class E Unit Distribution Rate	11.10%							11.10%
Class E Unit Maximum Distribution	$1.41							$1.41
Class F Unit Distribution Rate	35.00%							35.00%
Class F Unit Maximum Distribution	$3.75							$3.75
ETP [Member]
Common units issued through public offering				13,800,000	15,500,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan	6,100,000
Proceeds from issuance of common units				657,000,000	671,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan	155,000,000	109,000,000	43,000,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan	7,300,000							7,300,000
Regency [Member]
Common units issued through public offering						12,650,000
Proceeds from issuance of common units						297,000,000
Sunoco Logistics [Member]
Fees and Commissions	5,000,000
Equity Distribution Agreement, maximum aggregate value of common units sold	1,250,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	477,000,000
Partners' Capital Account, Units, Sale of Units							7,700,000
Partners' Capital Account, Sale of Units							362,000,000
Sunoco LP [Member]
Partners' Capital Account, Units, Sale of Units								9,100,000
Partners' Capital Account, Sale of Units								405,000,000
Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	1,540,000
Limited Partners' Capital Account, Units Outstanding	1,540,000	1,540,000						1,540,000
Class F Units [Member] | Sunoco [Member]
Partners' Capital Account, Units	40,000,000							40,000,000
Class H Units [Member]
Partners' Capital Account, Units	50,200,000							50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent	50.05%							50.05%
Holdco Transaction [Member]
Relinquishment Of Rights Of Incentive Distributions									210,000,000
Holdco Transaction [Member] | Class G Units [Member]
Partners' Capital Account, Units															90,700,000
Hoover Midstream Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, Acquisitions	4,000,000
Business Combination, Consideration Transferred	300,000,000
PVR Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, Acquisitions	140,400,000
Business Combination, Consideration Transferred	5,700,000,000
Eagle Rock Midstream Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, Acquisitions	8,200,000
Proceeds from Issuance of Common Stock	400,000,000
Business Combination, Consideration Transferred	1,300,000,000
Susser Merger [Member]
Relinquishment Of Rights Of Incentive Distributions									350,000,000
Business Combination, Consideration Transferred										875,000,000
Additional Units [Member] | Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	40,000
January 2013 [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	200,000,000
May 2013 [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	800,000,000
2013 Plans [Member]
Common Units Issued Inconnection With The Equity Distribution Agreement	2,700,000
Fees and Commissions	2,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	144,000,000
Equity Distribution Agreements, Value of Units Available to be Issued	0							0
May 2014 [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	1,000,000,000
November 2014 [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	1,500,000,000
2014 Plans [Member]
Common Units Issued Inconnection With The Equity Distribution Agreement	18,800,000
Fees and Commissions	11,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	1,080,000,000
Equity Distribution Agreements, Value of Units Available to be Issued	1,410,000,000							1,410,000,000
Issued to wholly-owned subsidiary of ETE [Member] | Regency [Member]
Stock Issued During Period, Shares, New Issues	14,400,000
Stock Issued During Period, Value, New Issues	400,000,000
Issued to wholly-owned subsidiary of ETE [Member] | Eagle Rock Midstream Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, New Issues	16,500,000
Stock Issued During Period, Value, New Issues	400,000,000
2012 Agreement [Member] | Regency [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	200,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	34,000,000	149,000,000
2014 Agreement [Member] | Regency [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold	400,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	395,000,000
2015 Agreement [Member] | Regency [Member]
Equity Distribution Agreement, maximum aggregate value of common units sold											1,000,000,000
Class E Units [Member] | ETP [Member]
Limited Partners' Capital Account, Units Outstanding	8,900,000							8,900,000
Bakken Exchange [Member]
Partners' Capital Account, Units, Redeemed												30,800,000
Business Combination, Consideration Transferred												$879,000,000
Bakken Exchange [Member] | Parent Company [Member]
Percent of total equity ownership of a subsidiary															45.00%
Bakken Exchange [Member] | Class H Units [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent												90.05%
Partners' Capital Account, Units, Redeemed												30,800,000
Bakken Exchange [Member] | Class I Units [Member]
Partners' Capital Account, Units												100

Equity_Change_In_ETE_Common_Un

Equity (Change In ETE Common Units) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Outstanding	538,766,899	559,923,300	559,900,000	445,900,000
Issuance of restricted Common Units under long-term incentive plans	-21,063,775	0	0
Number of Common Units, end of period	538,766,899	559,923,300	559,900,000	445,900,000
SUG Merger [Member]
Business Acquisition Units Acquired			114,000,000
Units Acquired for Equity [Member] | SUG Merger [Member]
Business Acquisition Units Acquired	0	0

Equity_Equity_Schedule_Of_Comm

Equity Equity (Schedule Of Common Units Sold In Public Offering) (Details) (USD $)	1 Months Ended		0 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 30, 2013	Jul. 31, 2012	Mar. 31, 2012
ETP [Member]
Capital Unit [Line Items]
Number of ETP Common Units	13,800,000	15,500,000
Price per ETP Unit	$48.05	$44.57
Net Proceeds	$657	$671
Regency [Member]
Capital Unit [Line Items]
Number of ETP Common Units			12,650,000
Price per ETP Unit			$24.47
Net Proceeds			$297

Equity_Quarterly_Distributions

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

12 Months Ended

3 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

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, 2011

Partners' Capital Account, Distributions

$821

$733

$666

Sunoco LP [Member]

Distribution Made to Limited Partner, Date of Record

17-Feb-15

18-Nov-14

Distribution Made to Limited Partner, Distribution Date

27-Feb-15

28-Nov-14

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.60

$0.55

Sunoco Logistics [Member]

Distribution Made to Limited Partner, Date of Record

9-Feb-15

7-Nov-14

8-Aug-14

9-May-14

10-Feb-14

8-Nov-13

8-Aug-13

9-May-13

8-Feb-13

Distribution Made to Limited Partner, Distribution Date

13-Feb-15

14-Nov-14

14-Aug-14

15-May-14

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.40

$0.38

$0.37

$0.35

$0.33

$0.32

$0.30

$0.29

$0.27

Parent Company [Member]

Distribution Made to Limited Partner, Date of Record

6-Feb-15

3-Nov-14

4-Aug-14

5-May-14

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

Distribution Made to Limited Partner, Distribution Date

19-Feb-15

19-Nov-14

19-Aug-14

19-May-14

19-Feb-14

19-Nov-13

19-Aug-13

17-May-13

19-Feb-13

16-Nov-12

17-Aug-12

18-May-12

17-Feb-12

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.45

$0.42

$0.38

$0.36

$0.35

$0.34

$0.33

$0.32

$0.32

$0.31

$0.31

$0.31

$0.31

ETP [Member]

Distribution Made to Limited Partner, Date of Record

6-Feb-15

3-Nov-14

4-Aug-14

5-May-14

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

Distribution Made to Limited Partner, Distribution Date

13-Feb-15

14-Nov-14

14-Aug-14

15-May-14

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

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$1.00

$0.98

$0.96

$0.94

$0.92

$0.91

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

Regency [Member]

Distribution Made to Limited Partner, Date of Record

6-Feb-15

4-Nov-14

7-Aug-14

8-May-14

7-Feb-14

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

6-Nov-12

6-Aug-12

7-May-12

6-Feb-12

Distribution Made to Limited Partner, Distribution Date

13-Feb-15

14-Nov-14

14-Aug-14

15-May-14

14-Feb-14

14-Nov-13

14-Aug-13

13-May-13

14-Feb-13

14-Nov-12

14-Aug-12

14-May-12

13-Feb-12

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$0.50

$0.50

$0.49

$0.48

$0.48

$0.47

$0.47

$0.46

$0.46

$0.46

$0.46

$0.46

$0.46

Equity_Accumulated_Other_Compr

Equity (Accumulated Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Partners' Capital Notes [Abstract]
Net gains on commodity related hedges	($1)	($4)
Unrealized gains on available-for-sale securities	3	2
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	-3	-1
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	-57	56
AOCI attributable to equity method investments	2	8
Subtotal	-56	61
Amounts attributable to noncontrolling interest	51	-52
Total AOCI included in partners' capital, net of tax	($5)	$9

Equity_Tax_amounts_in_componen

Equity Tax amounts in components of other comprehensive income (loss) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive Income Loss Commodity Hedges Tax	($1)	($1)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	2	1
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	-37	-39
Other Comprehensive Income (Loss), Tax	($36)	($39)

Equity_Equity_Schedule_of_Clas

Equity Equity (Schedule of Class I Distributions) (Details) (Future IDR Relinquishments [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Currently Effective IDRs [Member]
Relinquishment Of Rights Of Incentive Distributions	$18	$35	$35	$35	$35	$70	$80	$85	$107	$86
Pro Forma for Class H and Class I Units [Member]
Relinquishment Of Rights Of Incentive Distributions	18	35	35	35	35	70	80	85	77	31
Pro Forma for Regency Merger [Member]
Relinquishment Of Rights Of Incentive Distributions	$18	$35	$35	$35	$50	$130	$140	$145	$142	$91

UnitBased_Compensation_Plans_D

Unit-Based Compensation Plans (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Grant Date Fair Value Per Unit	$53.83	$49.65
Fair Value Of Units As Of The Vesting Date	$26	$29	$29
Granted unvested awards	$60.85
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	6,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	5,690,101
Unvested awards	34,340
Units Vested In Period	30,034
Fair Value Of Units As Of The Vesting Date	1.5
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	1
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	2 years 1 month 0 days
ETP Unit-Based Compensation Plans [Member]
Awards granted	1,000,000
Unvested awards	3,600,000	3,200,000
Vesting Period	5 years 0 months 0 days
Units Vested In Period	500,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	128
Granted unvested awards		$50.54	$43.93
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 0 months 0 days
ETP Cash Restricted Units [Member]
Unvested awards	400,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	24
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 15 days
Sunoco Logistics Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	700,000
Unvested awards	1,500,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	33
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 11 months 0 days
Regency Common Unit Options [Member]
Exercisable at the end of the period, Units	107,650
Options, Outstanding, Weighted Average Exercise Price	$22.68
Regency Phantom Units [Member]
Unvested awards	2,167,719
Grant Date Fair Value Per Unit	$24.31
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	42
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	3 years 11 months 0 days
Regency Cash Restricted Units [Member]
Unvested awards	400,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	7
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 6 months 0 days
Employee [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	0
Director [Member]
Vesting Period	5 years 0 months
Director [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	3,687
Class D Units [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	1,540,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$23
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		3 years 0 months 0 days

UnitBased_Compensation_Plans_U1

Unit-Based Compensation Plans Unit-Based Compensation Plans (Schedule of ETP awards granted to employees and non-employee directors) (Details) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Grant-Date Fair Value Per ETP Unit	$53.83	$49.65
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$60.85
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$48.12
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$32.36
ETP Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	3,600,000	3,200,000
Awards granted	1,000,000
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted		$50.54	$43.93
Awards vested	-500,000
Stock Granted, Value, Share-based Compensation, Forfeited	($0.10)

Income_Taxes_Narrative_Details

Income Taxes Narrative (Details) (USD $)	12 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2013	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$439
Operating Loss Carryforwards	5
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	116		217
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	-84		-74
Amount of Deferred Gain Challenged by IRS	545
Deferred Gain Associated with Like Kind Exchange	690
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	425
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	4
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	2
Proceeds from Income Tax Refunds	372
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	372
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	1
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	6
Expiring 2013 to 2032 [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	111
Holdco [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$1
ETE [Member] | Holdco [Member]
Operating Loss Carryforwards [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		60.00%
ETP [Member] | Holdco [Member]
Operating Loss Carryforwards [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%	40.00%

Income_Taxes_Components_of_Inc

Income Taxes Components of Income Tax (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Federal	$321	$51	($3)
State	86	-1	6
Total	407	50	3
Federal	-53	-14	41
State	3	57	10
Total	-50	43	51
Total income tax expense from continuing operations	$357	$93	$54

Income_Taxes_Reconciliation_of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate	35.00%
Income tax expense (benefit) at U.S. statutory rate of 35 percent	$212		($172)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	0		241
Income Tax Reconciliation, Nondeductible Expense, Premium on Debt Retirement	-10		0
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount	-8		0
State income taxes (net of federal income tax effects)	55		41
Other	3		-17
Total income tax expense from continuing operations	357		93		54
Corporate Subsidiaries [Member]
Income tax expense (benefit) at U.S. statutory rate of 35 percent	212	[1]	-172	[1]
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	0		241
Income Tax Reconciliation, Nondeductible Expense, Premium on Debt Retirement	-10		0	[1]
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount	-8		0	[1]
State income taxes (net of federal income tax effects)	9	[1]	31	[1]
Other	3	[1]	-16	[1]
Total income tax expense from continuing operations	311		84
Partnership [Member]
Income tax expense (benefit) at U.S. statutory rate of 35 percent	0		0
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	0		0
Income Tax Reconciliation, Nondeductible Expense, Premium on Debt Retirement	0		0
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount	0		0
State income taxes (net of federal income tax effects)	46		10
Other	0		-1
Total income tax expense from continuing operations	46		9
Lake Charles LNG Transaction [Member]
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	105		0
Lake Charles LNG Transaction [Member] | Corporate Subsidiaries [Member]
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	105		0
Lake Charles LNG Transaction [Member] | Partnership [Member]
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	$0		$0
[1]	Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of ETP Holdco.

Income_Taxes_Effects_of_Tempor

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effects of Temporary Differences that Comprise Net Deferred Income Tax Liability [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	$5	$0	$0
Deferred income tax assets:
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	116	217
Pension and other postretirement benefits	47	57
Long term debt	53	108
Other	111	104
Deferred Tax Assets, Gross	327	486
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	-84	-74
Net deferred income tax assets	243	412
Deferred income tax liabilities:
Properties, plants and equipment	-1,583	-1,624
Inventory	-153	-302
Investments in unconsolidated affiliates	-2,530	-2,245
Deferred Tax Liabilities, Intangible Assets	-355	-180
Other	-32	-45
Deferred Tax Liabilities, Gross	4,653	4,396
Deferred Tax Liabilities	-4,410	-3,984	-3,696
Deferred Tax Liabilities, Net, Current	-85	-119
DEFERRED INCOME TAXES	4,325	3,865
Increase in Tax Liability Attributable to Susser Acquisition	$488	$0

Income_Taxes_Components_of_Net

Income Taxes Components of Net Deferred Tax Liability (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of Net Deferred Income Tax [Abstract]
Deferred Tax Liabilities, Net	($4,410)	($3,984)	($3,696)
Increase in Tax Liability Attributable to Sunoco Acquisition	-488	0
Deferred Income Tax Liability as a Result of SUGS Contribution to Regency	0	-115
Noncurrent asset	62	-124
Deferred Tax Liabilities, Other	0	-49
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	116	217
Valuation allowance	$84	$74

Income_Taxes_Changes_in_Unreco

Income Taxes Changes in Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in Unrecognized Tax Benefits [Abstract]
Unrecognized Tax Benefits, Increase Resulting from Acquisition	$0	$0	$28
Balance at beginning of year	429	27	2
Additions attributable to tax positions taken in the current year	20	0	0
Additions attributable to tax positions taken in prior years	-1	406	0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	5	0	0
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	3	4	3
Balance at end of year	440	429	27
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$439

Regulatory_Matters_Commitments2

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) (USD $)	12 Months Ended			9 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jan. 12, 2012
Payments for Environmental Liabilities	$48,000,000	$41,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Lease Expiration Date	31-Dec-58
Operating leases rent expense	159,000,000	151,000,000	60,000,000
Environmental Costs Recognized, Recovery Credited to Expense	19,000,000
Total environmental liabilities	401,000,000	403,000,000
Guarantor Obligations, Current Carrying Value	600,000,000
Operating Leases, Rent Expense, Contingent Rentals	24,000,000	22,000,000	6,000,000
Site Contingency, Number of Sites Needing Remediation	51
FGT [Member]
Proceeds from Legal Settlements				100,000,000
Interest Awarded	1,000,000			19,000,000
AmeriGas [Member]
Contingent Residual Support Agreement Obligation	1,550,000,000				1,500,000,000
Southern Union [Member]
Percentage Of Recovery	50.00%
Loss Contingency, Estimated Recovery from Third Party	150000
SUGS [Member]
Environmental Expense and Liabilities	1,000,000
Related To Deductibles [Member]
Accrual for loss contingency	37,000,000	46,000,000
MTBE Sites [Member]
Site Contingency, Number of Sites Needing Remediation	19
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount	319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount	595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount	1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount	$536,000,000

Regulatory_Matters_Commitments3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Operating Leased Assets [Line Items]
2015	$151
2016	129
2017	118
2018	108
2019	102
Thereafter	829
Total Future Rent Payments	1,437
Future Rental Income	-34
Net Future Rental Payments	$1,403

Regulatory_Matters_Commitments4

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Environmental Remediation Obligations [Abstract]
Current	$41	$47
Non-current	360	356
Total environmental liabilities	$401	$403

Regulatory_Matters_Commitments5

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Schedule of Rental Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense	$159	$151	$60
Operating Leases, Rent Expense, Sublease Rentals	-26	-24	-4
Operating Leases, Rent Expense, Net	$133	$127	$56

Price_Risk_Management_Assets_A2

Price Risk Management Assets And Liabilities (Narrative) (Details) (Regency [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Loss Contingency, Range of Possible Loss, Maximum	$82
Netting [Member]
Derivative Asset, Fair Value, Gross Liability	$1

Price_Risk_Management_Assets_A3

Price Risk Management Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
	Megawatt		Megawatt
Mark-To-Market Derivatives [Member] | Power [Member] | Forwards/Swaps [Member] | ETP [Member]
Notional Volume	288,775		351,050
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Power [Member] | Future [Member] | ETP [Member]
Notional Volume	-156,000		-772,476
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Power [Member] | Options - Puts [Member] | ETP [Member]
Notional Volume	-72,000		-52,800
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Power [Member] | Options - Calls [Member] | ETP [Member]
Notional Volume	198,556		103,200
Maturity	2105		2014
Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume			103,000
Maturity			2014
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	-232,500		9,457,500
Maturity	2015
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Notional Volume	-13,907,500	[1]	-487,500	[1]
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Notional Volume	0		1,937,500
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Options - Calls [Member] | ETP [Member]
Maturity	2015
Mark-To-Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maturity			2019
Mark-To-Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Maturity	2016		2017
Mark-To-Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maturity			2016
Mark-To-Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	-8,779,000		-8,195,000
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Notional Volume	-25,525,000		-24,455,000
Maturity	2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Notional Volume	57,500		570,000
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Notional Volume	46,150,000		-9,690,000
Maturity	2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Notional Volume	-9,116,777		5,668,559
Maturity	2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forwards/Swaps [Member] | Regency [Member]
Notional Volume	-292,000		-438,000
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Propane [Member] | Forwards/Swaps [Member] | Regency [Member]
Notional Volume	-29,148,000		-52,122,000
Maturity	2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | WTI Crude Oil [Member] | Forwards/Swaps [Member] | Regency [Member]
Notional Volume	-1,252,000		-521,000
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maturity	2016		2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Maturity			2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maturity			2016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Maturity			2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Propane [Member] | Forwards/Swaps [Member] | Regency [Member]
Maturity			2015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | WTI Crude Oil [Member] | Forwards/Swaps [Member] | Regency [Member]
Maturity	2016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maturity	2015		2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Propane [Member] | Forwards/Swaps [Member] | Regency [Member]
Maturity			2014
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | WTI Crude Oil [Member] | Forwards/Swaps [Member] | Regency [Member]
Maturity	2015
Cash Flow Hedging [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	0		-30,000
Maturity			2014
Cash Flow Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	0		-12,775,000
Maturity			2014
Cash Flow Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Notional Volume	0		-1,825,000
Maturity			2014
Cash Flow Hedging [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forwards/Swaps [Member] | ETP [Member]
Notional Volume	0		-780,000
Maturity			2014
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	-39,287,500		-50,530,000
Maturity	2015		2014
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Notional Volume	-39,287,500		-7,352,500
Maturity			2014
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Hedged Item - Inventory [Member] | ETP [Member]
Notional Volume	39,287,500		50,530,000
Maturity	2015		2014
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Options - Calls [Member] | ETP [Member]
Notional Volume	5,000,000
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | ETP [Member]
Notional Volume	-2,179,400		-1,133,600
Maturity	2015		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Future [Member] | ETP [Member]
Notional Volume	13,745,755		-280,000
Maturity	2015		2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]
Maturity	2015
[1]	(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Price_Risk_Management_Assets_A4

Price Risk Management Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) (Interest Rate Derivatives [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
July 2018 [Member] | ETP [Member]
Notional Amount	$0		$600
Type	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	[1]
June 2021 [Member] | ETP [Member]
Notional Amount	0		400
Type	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	[1]
February 2023 [Member] | ETP [Member]
Notional Amount	200		400
Type	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	[1]
July 2014 [Member] | ETP [Member]
Notional Amount	0	[2]	400	[2]
Type	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	[1],[2]
July 2015 [Member] | ETP [Member]
Notional Amount	200	[2]	0	[2]
Type	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	[1],[2]
July 2016 [Member] | ETP [Member]
Notional Amount	200	[3]	0	[3]
Type	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	[1],[3]
November 2021 [Member] | Southern Union [Member]
Notional Amount	0	[3]	275	[3]
Type	Pay a fixed rate of 3.82% and receive a floating rate	[1],[3]
Forward-Starting Swaps [Member] | July 2018 [Member] | ETP [Member]
Notional Amount	200	[4]	0	[4]
Type	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	[1],[4]
Forward-Starting Swaps [Member] | July 2019 [Member] | ETP [Member]
Notional Amount	300	[4]	0	[4]
Type	Forward-starting to pay a fixed rate of 3.19% and receive a floating rate	[1],[4]
Forward-Starting Swaps [Member] | July 2017 [Member] | ETP [Member]
Notional Amount	$300	[4]	$0	[4]
Type	Forward-starting to pay a fixed rate of 3.84% and receive a floating rate	[1],[4]
[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
[3]	(3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
[4]	(4) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Price_Risk_Management_Assets_A5

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Asset Derivatives	$770	$320
Liability Derivatives	771	389
Designated as Hedging Instrument [Member]
Asset Derivatives	43	3
Liability Derivatives	0	-18
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	43	3
Liability Derivatives	0	-18
Not Designated as Hedging Instrument [Member]
Asset Derivatives	727	317
Liability Derivatives	-771	-371
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	617	227
Liability Derivatives	-577	-209
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Asset Derivatives	107	43
Liability Derivatives	-23	-48
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Asset Derivatives	3	47
Liability Derivatives	-155	-95
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	-16	-19
Netting [Member]
Asset Derivatives	697	306
Liability Derivatives	597	356
Bi-lateral contracts [Member] | Netting [Member]
Asset Derivatives	23	42
Liability Derivatives	23	38
Broker cleared derivative contracts [Member] | Netting [Member]
Asset Derivatives	674	264
Liability Derivatives	$574	$318

Price_Risk_Management_Assets_A6

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$0	($1)	$8
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$0	($1)	$8

Price_Risk_Management_Assets_A7

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	($3)	$4	$14
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	-8	8	54
Amount of Gain/(Loss) Recognized in Income on Derivatives	39	24	-12
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	-3	4	14
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	-8	8	54
Interest Rate Derivatives [Member] | Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	-157	53	-19
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	3	6	14
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	199	-21	26
Non Trading [Member] | Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	-3	-26
Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	($6)	($11)	($7)

Price_Risk_Management_Assets_A8

Price Risk Management Assets And Liabilities (Offsetting Agreements Netting Table) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Asset Derivatives	$770	$320
Derivative Liability, Fair Value, Gross Liability	-771	-389
Derivative Asset, Fair Value, Amount Offset Against Collateral	-14	-37
Derivative Liability, Fair Value, Amount Offset Against Collateral	-3	91
Netting [Member]
Asset Derivatives	697	306
Derivative Liability, Fair Value, Gross Liability	-597	-356
Derivative Asset, Fair Value, Gross Liability	-19	-36
Derivative Liability, Fair Value, Gross Asset	19	36
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	683	269
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-600	-265
Netting [Member] | Bi-lateral contracts [Member]
Asset Derivatives	23	42
Derivative Liability, Fair Value, Gross Liability	-23	-38
Netting [Member] | Broker cleared derivative contracts [Member]
Asset Derivatives	674	264
Derivative Liability, Fair Value, Gross Liability	-574	-318
Netting [Member] | Asset Fair Value, Netting Offset [Member]
Payments on Margin Deposits	5	-1
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	87	51
Netting [Member] | Liability Fair Value, Netting Offset [Member]
Payments on Margin Deposits	-22	55
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	($171)	($124)

Retirement_Benefits_Narrative_

Retirement Benefits (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Retirement Benefits [Line Items]
Gain on curtailment of other postretirement benefit plans	$0	$0	$15
ETP [Member]
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost Recognized	59	47	30
Sunoco [Member]
Retirement Benefits [Line Items]
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent	200
Pension Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	100.00%	41.00%
Fixed Income Securities		45.00%
Other Investments - Plan Asset Allocation		14.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	129
Other Postretirement Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	53.00%	41.00%
Fixed Income Securities	41.00%	48.00%
Cash Fund Investments	6.00%	6.00%
Other Investments - Plan Asset Allocation		5.00%
Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	25.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	35.00%
Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	65.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	75.00%
Other Postretirement Benefits | Cash [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	10.00%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$10

Retirement_Benefits_Obligation

Retirement Benefits (Obligations and Funded Status) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	$0	$0
Change in Benefit Obligations, Dispositions	0	-41
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in Plan Assets, Dispositions	0	-27
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Service Cost	0
Defined Benefit Plan, Interest Cost	31	35
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	600
Defined Benefit Plan, Fair Value of Plan Assets	598	600
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	223	296
Defined Benefit Plan, Service Cost	0	0
Defined Benefit Plan, Interest Cost	5	6
Defined Benefit Plan, Plan Amendments	1	2
Defined Benefit Plan, Benefits Paid	28	26
Defined Benefit Plan, Actuarial Gain (Loss)	2	-14
Defined Benefit Plan, Benefit Obligation	203	223
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	284	312
Defined Benefit Plan, Actual Return on Plan Assets	7	17
Defined Benefit Plan, Contributions by Employer	9	8
Defined Benefit Plan, Benefits Paid	28	26
Defined Benefit Plan, Fair Value of Plan Assets	272	284
Defined Benefit Plan, Funded Status of Plan	-69	-61
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	96	86
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	-2	-2
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	-25	-23
Defined Benefit Plan, Amounts Recognized in Balance Sheet	69	61
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	-21	-25
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	18	18
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	-3	-7
Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in Benefit Obligations, Dispositions	0	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	61	78
Defined Benefit Plan, Service Cost	0	0
Defined Benefit Plan, Interest Cost	3	2
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	-9	-16
Defined Benefit Plan, Actuarial Gain (Loss)	10	-3
Defined Benefit Plan, Benefit Obligation	65	61
Change in plan assets:
Defined Benefit Plan, Benefits Paid	-9	-16
Defined Benefit Plan, Funded Status of Plan	65	61
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	-9	-9
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	-56	-52
Defined Benefit Plan, Amounts Recognized in Balance Sheet	-65	-61
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	7	-4
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	7	-4
Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	-27
Change in Benefit Obligations, Dispositions	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	-27
Change in Plan Assets, Dispositions	0
Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	632	1,117
Defined Benefit Plan, Service Cost	0	3
Defined Benefit Plan, Interest Cost	28	33
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	-45	-99
Defined Benefit Plan, Actuarial Gain (Loss)	130	-74
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		-95
Change in Benefit Obligations, Dispositions		-253
Defined Benefit Plan, Benefit Obligation	718	632
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	600	906
Defined Benefit Plan, Actual Return on Plan Assets	70	43
Defined Benefit Plan, Contributions by Employer	0	0
Defined Benefit Plan, Benefits Paid	-45	-99
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		-95
Change in Plan Assets, Dispositions		-155
Defined Benefit Plan, Fair Value of Plan Assets	598	600
Defined Benefit Plan, Funded Status of Plan	120	32
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	0	0
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	-120	-32
Defined Benefit Plan, Amounts Recognized in Balance Sheet	-120	-32
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	18	-86
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	18	-86
Change in Plan Assets [Member] | Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in Plan Assets, Dispositions	0	0
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefits Paid	0	0
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Actual Return on Plan Assets	0	0
Defined Benefit Plan, Contributions by Employer	0	0
Defined Benefit Plan, Benefits Paid	0	0
Defined Benefit Plan, Fair Value of Plan Assets	$0	$0

Retirement_Benefits_Accumulate

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	$203	$223
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	272	284
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	718	632
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	718	632
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	598	600
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	65	61
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	65	61
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$0	$0

Retirement_Benefits_Net_Period

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Gain on curtailment of other postretirement benefit plans	$0	$0	($15)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0
Defined Benefit Plan, Interest Cost	31	35
Defined Benefit Plan, Expected Return on Plan Assets	-40	-54
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Amortization of Gains (Losses)	-1	2
Net Periodic Benefit Costs, Settlements	-4	-2
Net periodic benefit cost subtotal	-14	-16
Net Period Benefit Cost Regulatory Adjustment	0	5
Defined Benefit Plan, Net Periodic Benefit Cost	-14	-11
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0	0
Defined Benefit Plan, Interest Cost	5	6
Defined Benefit Plan, Expected Return on Plan Assets	-8	-9
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	1
Defined Benefit Plan, Amortization of Gains (Losses)	-1	0
Net Periodic Benefit Costs, Settlements	0	0
Net periodic benefit cost subtotal	-3	-2
Net Period Benefit Cost Regulatory Adjustment	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	($3)	($2)

Retirement_Benefits_Benefit_As

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.09%	7.57%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.41%	5.42%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2018	2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.62%	4.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.65%	3.50%
Expected long term return on assets, tax exempt accounts	7.50%	7.50%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.24%	2.33%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.02%	2.68%
Expected long term return on assets, tax exempt accounts	7.00%	6.95%
Expected long term return on assets, taxable accounts	4.50%	4.42%

Retirement_Benefits_Fair_Value

Retirement Benefits (Fair Value of Plan Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$272	$284	$312
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	598	600
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9	10
Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25	12
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	138	130
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	110	368
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	125	144
Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	463	220
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	147	122
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25	12
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9	10
Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25	12
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	138	112
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	125	162
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	573	501
Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	18
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	110	281
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	125	144
Level 2 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	463	220
Level 3 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	87
Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	87
Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$0	$0

Retirement_Benefits_Benefit_Pa

Retirement Benefits (Benefit Payments) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$28
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	26
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	25
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	23
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	22
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	65
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	717
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	0
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	0
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	0
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	0
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	0
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	9
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	8
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	7
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	7
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	6
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$23

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue	$965	$1,442	$189

Reportable_Segments_Operating_

Reportable Segments (Operating Segments) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues	$13,481	$14,987	$14,143	$13,080	$12,607	$12,486	$12,063	$11,179	$55,691	$48,335	$16,964
Cost of products sold									48,389	42,554	13,088
Depreciation, depletion and amortization									1,724	1,313	871
Equity in earnings of unconsolidated affiliates									332	236	212
Investment In ETP [Member]
Revenues									51,158	46,339	15,702
Cost of products sold									45,540	41,204	12,266
Depreciation, depletion and amortization									1,130	1,032	656
Equity in earnings of unconsolidated affiliates									234	172	142
Investment In Regency [Member]
Revenues									4,951	2,521	2,000
Cost of products sold									3,452	1,793	1,387
Depreciation, depletion and amortization									541	287	252
Equity in earnings of unconsolidated affiliates									195	135	105
Investment in Lake Charles LNG [Member]
Depreciation, depletion and amortization									39	39	30
Corporate and Other [Member]
Depreciation, depletion and amortization									17	16	14
Adjustments and Eliminations [Member]
Revenues									-634	-741	-904
Cost of products sold									-603	-443	-565
Depreciation, depletion and amortization									-3	-61	-81
Equity in earnings of unconsolidated affiliates									-97	-71	-35
External Customers [Member] | Investment In ETP [Member]
Revenues									50,989	46,210	15,671
External Customers [Member] | Investment In Regency [Member]
Revenues									4,597	2,404	1,986
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues									216	216	166
Intersegment [Member] | Investment In ETP [Member]
Revenues									169	129	31
Intersegment [Member] | Investment In Regency [Member]
Revenues									$354	$117	$14

Reportable_Segments_Equity_in_

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	$332	$236	$212
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	234	172	142
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	195	135	105
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	($97)	($71)	($35)

Reportable_Segments_Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Adjusted EBITDA	$5,840	$4,367	$3,105
Depreciation and amortization	-1,724	-1,313	-871
Interest expense, net of interest capitalized	-1,369	-1,221	-1,018
Bridge loan related fees	0	0	-62
Gain on deconsolidation of Propane Business	0	0	1,057
Gain on sale of AmeriGas common units	177	87	0
Goodwill impairment	-370	-689	0
Gains (losses) on interest rate derivatives	-157	53	-19
Non-cash compensation expense	-82	-61	-47
Gains (losses) on interest rate derivatives	116	48	10
Gain (Loss) on Disposition of Assets	1	-2	-4
Losses on extinguishments of debt	-25	-162	-123
Inventory, LIFO Reserve, Effect on Income, Net	-473	3	-75
Adjusted EBITDA related to discontinued operations	-27	-76	-99
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	-748	-727	-647
Equity in earnings of unconsolidated affiliates	332	236	212
Non-operating environmental remediation	0	-168	0
Other, net	-73	-2	14
Income from continuing operations before income tax expense	1,417	375	1,437
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	4,829	3,953	2,744
Depreciation and amortization	-1,130	-1,032	-656
Equity in earnings of unconsolidated affiliates	234	172	142
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,172	608	517
Depreciation and amortization	-541	-287	-252
Equity in earnings of unconsolidated affiliates	195	135	105
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	195	187	135
Depreciation and amortization	-39	-39	-30
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	-97	-43	-52
Depreciation and amortization	-17	-16	-14
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	-259	-338	-239
Depreciation and amortization	3	61	81
Equity in earnings of unconsolidated affiliates	($97)	($71)	($35)

Reportable_Segments_Assets_Seg

Reportable Segments (Assets Segments)(Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	$64,469	$50,330	$48,904
Investment In ETP [Member]
Assets	48,221	43,702	43,230
Investment In Regency [Member]
Assets	17,103	8,782	8,123
Investment in Lake Charles LNG [Member]
Assets	1,210	1,338	1,917
Corporate and Other [Member]
Assets	1,153	720	707
Adjustments and Eliminations [Member]
Assets	($3,218)	($4,212)	($5,073)

Reporting_Segments_Additions_T

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$5,559	$3,342	$3,517
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	4,478	2,455	3,049
Investment in Regency [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	1,112	1,011	599
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	1	2	4
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	($32)	($126)	($135)

Reportable_Segments_Advances_t

Reportable Segments (Advances to and investments in affiliates) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	$3,659,000,000	$4,014,000,000	$4,737,000,000
Investment In ETP [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,840,000,000	4,436,000,000	3,502,000,000
Investment In Regency [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	2,418,000,000	2,097,000,000	2,214,000,000
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	($2,599,000,000)	($2,519,000,000)	($979,000,000)

Reportable_Segments_ETP_Revenu

Reportable Segments ETP Revenue (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue from External Customer [Line Items]
Revenues	$13,481	$14,987	$14,143	$13,080	$12,607	$12,486	$12,063	$11,179	$55,691	$48,335	$16,964
Investment In ETP [Member]
Revenue from External Customer [Line Items]
Revenues									51,158	46,339	15,702
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									2,652	2,250	2,012
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,057	1,270	1,109
Investment In ETP [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									1,210	1,307	1,757
Investment In ETP [Member] | NGL Transportation And Services [Member]
Revenue from External Customer [Line Items]
Revenues									3,790	2,063	619
Investment In ETP [Member] | Investment in Sunoco Logistics [Member]
Revenue from External Customer [Line Items]
Revenues									17,920	16,480	3,109
Investment In ETP [Member] | Retail Marketing [Member]
Revenue from External Customer [Line Items]
Revenues									22,484	21,004	5,926
Investment In ETP [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									2,045	1,965	1,170
Investment In ETP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									50,989	46,210	15,671
Investment In ETP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									$169	$129	$31

Reportable_Segments_Regency_Re

Reportable Segments Regency Revenue (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue from External Customer [Line Items]
Revenues	$13,481	$14,987	$14,143	$13,080	$12,607	$12,486	$12,063	$11,179	$55,691	$48,335	$16,964
Investment In Regency [Member]
Revenue from External Customer [Line Items]
Revenues									4,951	2,521	2,000
Investment In Regency [Member] | Gathering And Processing [Member]
Revenue from External Customer [Line Items]
Revenues									4,570	2,287	1,797
Investment In Regency [Member] | Natural Gas Transportation [Member]
Revenue from External Customer [Line Items]
Revenues									0	1	1
Investment In Regency [Member] | Natural Resources [Member]
Revenue from External Customer [Line Items]
Revenues									58	0	0
Investment In Regency [Member] | Contract Services [Member]
Revenue from External Customer [Line Items]
Revenues									307	215	183
Investment In Regency [Member] | Corporate and Other [Member]
Revenue from External Customer [Line Items]
Revenues									16	18	19
Investment In Regency [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									4,597	2,404	1,986
Investment In Regency [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									$354	$117	$14

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues	$13,481	$14,987	$14,143	$13,080	$12,607	$12,486	$12,063	$11,179	$55,691	$48,335	$16,964
Gross margin	1,900	1,972	1,792	1,638	1,489	1,422	1,498	1,372	7,302	5,781
Operating income	165	822	773	710	-153	529	644	531	2,470	1,551	1,360
Net income (loss)	-294	470	500	448	-701	356	338	322	1,124	315	1,274
Limited Partners’ interest in net income	$111	$188	$163	$167	($171)	$150	$127	$90	$629	$196	$302
Basic net income per limited partner unit	$0.21	$0.35	$0.30	$0.30	($0.31)	$0.27	$0.23	$0.16	$1.16	$0.35	$0.57
Diluted net income (loss) per limited partner unit	$0.21	$0.35	$0.30	$0.30	($0.31)	$0.27	$0.23	$0.16	$1.15	$0.35	$0.57

Quarterly_Financial_Data_Unaud3

Quarterly Financial Data (Unaudited) Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Inventory Valuation Reserves	$456
Goodwill impairment	$370	$689	$0

Supplemental_Financial_Stateme2

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash and cash equivalents	$847,000,000	$590,000,000	$372,000,000	$126,000,000
Accounts receivable from related companies	35,000,000	63,000,000
Other current assets	301,000,000	312,000,000
Total current assets	6,153,000,000	6,536,000,000
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,659,000,000	4,014,000,000	4,737,000,000
INTANGIBLE ASSETS, net	5,582,000,000	2,264,000,000
GOODWILL	7,865,000,000	5,894,000,000	6,434,000,000
OTHER NON-CURRENT ASSETS, net	908,000,000	922,000,000
Total assets	64,469,000,000	50,330,000,000	48,904,000,000
Accounts payable	3,349,000,000	3,834,000,000
Accounts payable to related companies	19,000,000	14,000,000
Interest payable	440,000,000	357,000,000
Price risk management liabilities	21,000,000	53,000,000
Accrued and other current liabilities	2,201,000,000	1,678,000,000
Current maturities of long-term debt	1,008,000,000	637,000,000
Total current liabilities	6,782,000,000	6,500,000,000
LONG-TERM DEBT, less current maturities	29,653,000,000	22,562,000,000
OTHER NON-CURRENT LIABILITIES	1,193,000,000	1,019,000,000
COMMITMENTS AND CONTINGENCIES
General Partner	-1,000,000	-3,000,000
Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively)	648,000,000	1,066,000,000
Class D Units (1,540,000 units authorized, issued and outstanding)	22,000,000	6,000,000
Accumulated other comprehensive income (loss)	-5,000,000	9,000,000
Total partners’ capital	664,000,000	1,078,000,000
Total liabilities and equity	64,469,000,000	50,330,000,000
Parent Company [Member]
Cash and cash equivalents	2,000,000	8,000,000	9,000,000	18,000,000
Accounts receivable from related companies	14,000,000	5,000,000
Other current assets	1,000,000	0
Total current assets	17,000,000	13,000,000
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,390,000,000	3,841,000,000
INTANGIBLE ASSETS, net	10,000,000	14,000,000
GOODWILL	9,000,000	9,000,000
OTHER NON-CURRENT ASSETS, net	46,000,000	41,000,000
Total assets	5,472,000,000	3,918,000,000
Accounts payable to related companies	11,000,000	11,000,000
Interest payable	58,000,000	24,000,000
Accrued and other current liabilities	3,000,000	3,000,000
Total current liabilities	72,000,000	38,000,000
LONG-TERM DEBT, less current maturities	4,680,000,000	2,801,000,000
NOTE PAYABLE TO AFFILIATE	54,000,000	0
OTHER NON-CURRENT LIABILITIES	2,000,000	1,000,000
COMMITMENTS AND CONTINGENCIES
General Partner	-1,000,000	-3,000,000
Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively)	648,000,000	1,066,000,000
Class D Units (1,540,000 units authorized, issued and outstanding)	22,000,000	6,000,000
Accumulated other comprehensive income (loss)	-5,000,000	9,000,000
Total partners’ capital	664,000,000	1,078,000,000
Total liabilities and equity	$5,472,000,000	$3,918,000,000

Supplemental_Financial_Stateme3

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									($611)	($533)	($527)
Interest expense, net of interest capitalized									-1,369	-1,221	-1,018
Bridge loan related fees											-62
Equity in earnings of unconsolidated affiliates									332	236	212
Gains (losses) on interest rate derivatives									-157	53	-19
Losses on extinguishments of debt									-25	-162	-123
Other, net									-11	-1	30
Income tax expense (benefit)									357	93	54
NET INCOME ATTRIBUTABLE TO PARTNERS									633	196	304
GENERAL PARTNER’S INTEREST IN NET INCOME									2	0	2
CLASS D UNITHOLDER’S INTEREST IN NET INCOME									2	0	0
LIMITED PARTNERS’ INTEREST IN NET INCOME	111	188	163	167	-171	150	127	90	629	196	302
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									-111	-56	-53
Interest expense, net of interest capitalized									-205	-210	-235
Bridge loan related fees									0	0
Equity in earnings of unconsolidated affiliates									955	617	666
Gains (losses) on interest rate derivatives									0	9	-15
Losses on extinguishments of debt									0	-157	0
Other, net									-5	-8	-4
INCOME BEFORE INCOME TAXES									634	195	297
Income tax expense (benefit)									1	-1	-7
NET INCOME ATTRIBUTABLE TO PARTNERS									633	196	304
GENERAL PARTNER’S INTEREST IN NET INCOME									-2	0	-2
CLASS D UNITHOLDER’S INTEREST IN NET INCOME									2	0	0
LIMITED PARTNERS’ INTEREST IN NET INCOME									$629	$196	$302

Supplemental_Financial_Stateme4

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$3,175	$2,419	$1,078
Cash paid for acquisitions	-2,367	-405	-10
Proceeds from the sale of other assets	62	89	44
Net cash used in investing activities	-6,795	-2,347	-4,196
Proceeds from borrowings	18,375	12,934	12,870
Repayments of long-term debt	-13,886	-11,951	-8,848
Distributions to partners	-821	-733	-666
Redemption of Preferred Units	0	-340	0
Units repurchased under buyback program	-1,000	0	0
Debt issuance costs	-77	-87	-112
Net cash provided by financing activities	3,877	146	3,364
INCREASE IN CASH AND CASH EQUIVALENTS	257	218	246
CASH AND CASH EQUIVALENTS, beginning of period	590	372	126
CASH AND CASH EQUIVALENTS, end of period	847	590	372
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	816	768	555
Cash paid for acquisitions	0	0	-1,113
Proceeds from the sale of other assets	0	1,332	0
Contributions to unconsolidated affiliates	-118	-8	-487
Payments to Acquire Additional Interest in Subsidiaries	-800	0	0
Increase (Decrease) in Notes Payable, Related Parties	54	0	0
Note receivable from affiliate	0	0	-221
Payments received on note receivable from affiliate	0	166	55
Net cash used in investing activities	-864	1,490	-1,766
Proceeds from borrowings	3,020	2,080	2,108
Repayments of long-term debt	-1,142	-3,235	-162
Distributions to partners	-821	-733	-666
Redemption of Preferred Units	0	-340	0
Units repurchased under buyback program	-1,000	0	0
Debt issuance costs	-15	-31	-78
Net cash provided by financing activities	42	-2,259	1,202
INCREASE IN CASH AND CASH EQUIVALENTS	-6	-1	-9
CASH AND CASH EQUIVALENTS, beginning of period	8	9	18
CASH AND CASH EQUIVALENTS, end of period	$2	$8	$9