Energy Transfer (ET) 8-K 3 Feb 17 2015 FY Management’s Discussion and Analysis of Financial Condition and Results of Operations Financial data

Document and Entity Information

Document and Entity Information Document - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	1,276,187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	8-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,044,788,657
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 25.4

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$ 606	$ 847
Accounts receivable, net	2,400	3,378
Accounts receivable from related companies	119	35
Inventories	1,636	1,467
Exchanges receivable	31	44
Derivative assets	46	81
Other current assets	572	287
Total current assets	5,410	6,139
Property, plant and equipment	54,979	45,018
Accumulated depreciation and depletion	(6,296)	(4,726)
Property, Plant and Equipment, Net	48,683	40,292
Advances to and investments in unconsolidated affiliates	3,462	3,659
Non-current derivative assets	0	10
Goodwill	7,473	7,865
Intangible assets, net	5,431	5,582
Other non-current assets, net	730	732
Total assets	71,189	64,279
LIABILITIES AND EQUITY
Accounts payable	2,274	3,349
Accounts payable to related companies	28	19
Exchanges payable	106	184
Derivative liabilities	69	21
Accrued and other current liabilities	2,302	2,102
Current maturities of long-term debt	131	1,008
Total current liabilities	4,910	6,683
Long-term debt, less current maturities	36,837	29,477
Deferred income taxes	4,590	4,410
Non-current derivative liabilities	137	154
Other non-current liabilities	1,069	1,193
Commitments and contingencies
Redeemable noncontrolling interests	15	15
PREFERRED UNITS OF SUBSIDIARY (Note 7)	33	33
Partners' Capital
General Partner	(2)	(1)
Limited Partners:
Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively)	(952)	648
Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively)	22	22
Accumulated other comprehensive loss	0	(5)
Total partners’ capital	(932)	664
Noncontrolling interest	24,530	21,650
Total equity	23,598	22,314
Total liabilities and equity	$ 71,189	$ 64,279

Consolidated Balance Sheets Bal

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Authorized	1,044,767,336	1,077,533,798
Issued	1,044,767,336	1,077,533,798
Outstanding	1,044,767,336	1,077,533,798	1,119,800,000	1,119,800,000
Class D Units [Member]
Class of Stock [Line Items]
Authorized	2,156,000	3,080,000
Issued	2,156,000	3,080,000
Outstanding	2,156,000	3,080,000

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
REVENUES:
Natural gas sales	$ 3,671		$ 5,386		$ 3,842
NGL sales	3,935		5,845		3,618
Crude sales	8,378		16,416		15,477
Gathering, transportation and other fees	4,200		3,733		3,097
Refined product sales	15,672		19,437		18,479
Other	6,270		4,874		3,822
Total revenues	42,126		55,691		48,335
COSTS AND EXPENSES:
Cost of products sold	34,009		48,414		42,580
Operating expenses	2,661		2,102		1,669
Depreciation, depletion and amortization	2,079		1,724		1,313
Selling, general and administrative	639		611		533
Impairment losses	339		370		689
Total costs and expenses	39,727		53,221		46,784
OPERATING INCOME	2,399		2,470		1,551
OTHER INCOME (EXPENSE):
Interest expense, net	(1,643)		(1,369)		(1,221)
Equity in earnings from unconsolidated affiliates	276		332		236
Gain on sale of AmeriGas common units	0		177		87
Losses on extinguishments of debt	(43)		(25)		(162)
Gains (losses) on interest rate derivatives	(18)		(157)		53
Non-operating environmental remediation	0		0		(168)
Other, net	22		(11)		(1)
Income from continuing operations before income tax expense	993		1,417		375
Income tax expense (benefit) from continuing operations	(100)	[1]	357	[1]	93
INCOME FROM CONTINUING OPERATIONS	1,093		1,060		282
Income from discontinued operations	0		64		33
NET INCOME	1,093		1,124		315
Less: Net income (loss) attributable to noncontrolling interest	(96)		491		119
NET INCOME ATTRIBUTABLE TO PARTNERS	1,189		633		196
General Partner’s interest in net income	3		2		0
Class D Unitholder’s interest in net income	3		2		0
Limited Partners’ interest in net income	$ 1,183		$ 629		$ 196
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$ 1.11		$ 0.58		$ 0.17
Diluted	1.11		0.57		0.17
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	1.11		0.58		0.18
Diluted	$ 1.11		$ 0.57		$ 0.18
[1]	Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries.

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income	$ 1,093	$ 1,124	$ 315
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	0	3	(4)
Change in value of derivative instruments accounted for as cash flow hedges	0	0	(1)
Change in value of available-for-sale securities	(3)	1	2
Actuarial gain (loss) relating to pension and other postretirement benefits	65	(113)	66
Foreign currency translation adjustment	(1)	(2)	(1)
Change in other comprehensive income from unconsolidated affiliates	(1)	(6)	17
Other comprehensive income (loss), net of tax, total	60	(117)	79
Comprehensive income	1,153	1,007	394
Less: Comprehensive income (loss) attributable to noncontrolling interest	(41)	388	181
Comprehensive income attributable to partners	$ 1,194	$ 619	$ 213

Consolidated Statement Of Equit

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	General Partner [Member]	Common Unitholders [Member]	Class D Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 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)
Subsidiary unit transactions | Subsidiary units issued in certain acquisitions [Member]	0	1	506	0	0	507
Subsidiary unit transactions | Subsidiary units issued for cash [Member]	1,759	0	122	0	0	1,637
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 Stock, Amount Converted	(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)
Subsidiary unit transactions | Subsidiary units issued in certain acquisitions [Member]	5,815	0	211	0	0	5,604
Subsidiary unit transactions | Subsidiary units issued to Parent [Member]	0	0	99	0	0	99
Subsidiary unit transactions | Subsidiary units issued for cash [Member]	3,057	0	148	2	0	2,907
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | Lake Charles LNG Transaction [Member]	0	2	480	0	0	(482)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(319)	0	0	0	0	(319)
Capital contributions received from noncontrolling interest	139	0	0	0	0	139
Partners' Capital Account, Unit-based Compensation	65	0	0	14	0	51
Other, net	(3)	0	30	0	0	(33)
Stock Repurchased During Period, Value	1,000	0	1,000	0	0	0
Other comprehensive income, net of tax	(117)	0	0	0	(14)	(103)
Net income	1,124	2	629	2	0	491
Balance at Dec. 31, 2014	22,314	(1)	648	22	(5)	21,650
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,090)	(3)	(1,084)	(3)	0	0
Distributions to noncontrolling interest	(2,335)	0	0	0	0	(2,335)
Subsidiary unit transactions	3,889	1	524	1	0	4,415
Capital contributions received from noncontrolling interest	875	0	0	0	0	875
Partners' Capital Account, Unit-based Compensation	70	0	0	8	0	62
Other, net	(149)	0	(118)	0	0	(31)
Stock Repurchased During Period, Value	1,064	0	1,064	0	0	0
Conversion of Stock, Amount Converted	0	0	7	(7)	0	0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	(65)	0	0	0	0	(65)
Other comprehensive income, net of tax	60	0	0	0	5	55
Net income	1,093	3	1,183	3	0	(96)
Balance at Dec. 31, 2015	$ 23,598	$ (2)	$ (952)	$ 22	$ 0	$ 24,530

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 1,093	$ 1,124	$ 315
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,079	1,724	1,313
Deferred income taxes	242	(50)	43
Amortization included in interest expense	(21)	(51)	(55)
Unit-based compensation expense	91	82	61
Impairment losses	339	370	689
Gain on sale of AmeriGas common units	0	(177)	(87)
Losses on extinguishments of debt	43	25	162
(Gains) losses on disposal of assets	(8)	(1)	2
Equity in earnings of unconsolidated affiliates	(276)	(332)	(236)
Distributions from unconsolidated affiliates	409	291	313
Inventory valuation adjustments	249	473	(3)
Other non-cash	(8)	(72)	51
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(1,164)	(231)	(149)
Net cash provided by operating activities	3,068	3,175	2,419
INVESTING ACTIVITIES:
Cash received for sale of noncontrolling interest	64	0	0
Cash proceeds from the sale of AmeriGas common units	0	814	346
Cash paid for acquisitions, net of cash received	(835)	(2,367)	(405)
Cash paid for acquisition of a noncontrolling interest	(129)	0	0
Capital expenditures (excluding allowance for equity funds used during construction)	(9,386)	(5,381)	(3,505)
Contributions in aid of construction costs	80	45	52
Contributions to unconsolidated affiliates	(45)	(334)	(3)
Distributions from unconsolidated affiliates in excess of cumulative earnings	128	136	419
Proceeds from the sale of discontinued operations	0	77	1,008
Proceeds from the sale of other assets	26	62	89
Change in restricted cash	19	172	(348)
Other	(16)	(19)	0
Net cash used in investing activities	(10,094)	(6,795)	(2,347)
FINANCING ACTIVITIES:
Proceeds from borrowings	26,455	18,375	12,934
Repayments of long-term debt	(19,828)	(13,886)	(11,951)
Subsidiary units issued for cash	3,889	3,057	1,759
Distributions to partners	(1,090)	(821)	(733)
Distributions to noncontrolling interests	(2,335)	(1,905)	(1,428)
Debt issuance costs	(75)	(77)	(87)
Capital contributions from noncontrolling interest	841	139	18
Redemption of Preferred Units	0	0	(340)
Units repurchased under buyback program	(1,064)	(1,000)	0
Other, net	(8)	(5)	(26)
Net cash provided by financing activities	6,785	3,877	146
Increase (decrease) in cash and cash equivalents	(241)	257	218
Cash and cash equivalents, beginning of period	847	590	372
Cash and cash equivalents, end of period	$ 606	$ 847	$ 590

Operations And Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014, and 2013 , 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. 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, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. As discussed in Note 8 , in January 2014 and July 2015, the Partnership completed two-for-one splits 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 effects of the unit splits for all periods presented. At December 31, 2015 , our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 2.6 million ETP common units and 81.0 million ETP Class H units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP. The consolidated financial statements of ETE presented herein include the results of operations of: • the Parent Company; • our controlled subsidiaries, ETP and Sunoco LP (see description of their respective operations below under “Business Operations”); • ETP’s and Sunoco LP’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Sunoco LP; and • our wholly-owned subsidiary, Lake Charles LNG. 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 2015 presentation. These reclassifications had no impact on net income or total equity. 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 Sunoco LP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein. ETP is a publicly traded partnership whose operations comprise the following: • the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, and Avalon shales; • intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are 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; • interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and • a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines. ETP also 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. In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. The transaction was effective January 1, 2016. Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 21 million ETP common units owned by ETE. 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. Our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • 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. Regency Merger. On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly owned subsidiary of ETP (the “Regency Merger”). Regency previously was a direct subsidiary of ETE and had been presented as a separate reportable segment. Each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP common units. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to subsidiaries of ETP. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2015
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, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. 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 February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting periods presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard. In August 2015, the FASB issued ASU No. 2015-16 " Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments. " This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. 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 with 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 Sunoco LP Revenues from our two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignment basis, in which Sunoco LP retains 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. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease. 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, 2015 2014 2013 Accounts receivable $ 856 $ 600 $ (556 ) Accounts receivable from related companies (5 ) 30 64 Inventories (430 ) 51 (254 ) Exchanges receivable 14 18 (8 ) Other current assets (239 ) 133 (81 ) Other non-current assets, net 250 (6 ) (23 ) Accounts payable (1,127 ) (850 ) 541 Accounts payable to related companies 400 5 (140 ) Exchanges payable (79 ) (99 ) 128 Accrued and other current liabilities (618 ) (59 ) 192 Other non-current liabilities (261 ) (73 ) 147 Derivative assets and liabilities, net 75 19 (159 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (1,164 ) $ (231 ) $ (149 ) Non-cash investing and financing activities and supplemental cash flow information were as follows: Years Ended December 31, 2015 2014 2013 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 910 $ 643 $ 226 Net gains (losses) from subsidiary common unit transactions (526 ) 744 (384 ) NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ 34 $ — $ — 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 $ 1,800 $ 1,416 $ 1,256 Cash paid for income taxes 72 345 58 Accounts Receivable Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. 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 identification of specific customers with payment issues. Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. 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 refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 420 392 Spare parts and other 377 319 Total inventories $ 1,636 $ 1,467 During the year ended December 31, 2015 , the Partnership recorded write downs of $249 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, 2015 2014 Deposits paid to vendors $ 74 $ 65 Income taxes receivable 326 17 Prepaid expenses and other 172 205 Total other current assets $ 572 $ 287 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. Property, plant and equipment is reviewed 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. In 2015, we recorded $110 million fixed asset impairments related to ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities 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, 2015 2014 Land and improvements $ 686 $ 1,307 Buildings and improvements (1 to 45 years) 1,526 1,922 Pipelines and equipment (5 to 83 years) 32,677 27,149 Natural gas and NGL storage facilities (5 to 46 years) 390 1,214 Bulk storage, equipment and facilities (2 to 83 years) 2,853 4,010 Tanks and other equipment (5 to 40 years) 1,488 58 Retail equipment (2 to 99 years) 401 515 Vehicles (1 to 25 years) 220 203 Right of way (20 to 83 years) 2,573 2,451 Furniture and fixtures (2 to 25 years) 57 59 Linepack 61 119 Pad gas 44 44 Natural resources 484 454 Other (1 to 30 years) 3,675 999 Construction work-in-process 7,844 4,514 54,979 45,018 Less – Accumulated depreciation and depletion (6,296 ) (4,726 ) Property, plant and equipment, net $ 48,683 $ 40,292 We recognized the following amounts for the periods presented: Years Ended December 31, 2015 2014 2013 Depreciation and depletion expense $ 1,776 $ 1,457 $ 1,128 Capitalized interest, excluding AFUDC $ 163 $ 113 $ 43 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. 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, 2015 2014 Unamortized financing costs (1) $ 29 $ 41 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 221 209 Total other non-current assets, net $ 730 $ 732 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies. Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes 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, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 5,254 $ (738 ) $ 5,144 $ (485 ) Trade names (15 years) 559 (25 ) 556 (15 ) Patents (9 years) 48 (16 ) 48 (11 ) Other (1 to 15 years) 15 (7 ) 36 (7 ) Total amortizable intangible assets 5,876 (786 ) 5,784 (518 ) Non-amortizable intangible assets: Trademarks 341 — 316 — Total intangible assets $ 6,217 $ (786 ) $ 6,100 $ (518 ) Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 303 $ 219 $ 120 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2016 $ 242 2017 242 2018 241 2019 239 2020 239 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. In 2015, we recorded $24 million of intangible asset impairments related to ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2013 $ 5,856 $ — $ 184 $ (146 ) $ 5,894 Goodwill acquired 2,340 3,143 — (3,143 ) 2,340 Lake Charles LNG Transaction (1) (184 ) — — 184 — Goodwill impairment (370 ) — — — (370 ) Other — — — 1 1 Balance, December 31, 2014 7,642 3,143 184 (3,104 ) 7,865 Goodwill acquired — 31 — — 31 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (63 ) — (164 ) (218 ) Balance, December 31, 2015 $ 5,428 $ 3,111 $ 184 $ (1,250 ) $ 7,473 (1) As discussed in Note 3 , ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $184 million 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 decrease in goodwill of $392 million during the year ended December 31, 2015 primarily due to the impairments discussed below as well as purchase price allocation adjustments. During 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets. This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership appl

Acquisitions and Related Transa

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2015
Acquisitions and Dispositions [Abstract]
Acquisitions and Related Transactions	ACQUISITIONS AND RELATED TRANSACTIONS : Pending Transactions WMB Merger In September 2015, ETE, ETC and WMB entered into a merger agreement. The merger agreement provides that WMB will be merged with and into ETC, with ETC surviving the merger. ETC is a recently formed limited partnership that will elect to be treated as a corporation for federal income tax purposes and, upon closing, will own the managing member interest in our general partner and limited partner interests in ETE. At the time of the merger, each issued and outstanding share of WMB common stock will be exchanged for (i) $8.00 in cash and 1.5274 ETC common shares, (ii) 1.8716 ETC common shares, or (iii) $43.50 in cash. The closing of the transaction is subject to customary conditions, including the receipt of approval of the merger from WMB’s stockholders and all required regulatory approvals, including approval pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976. ETE and WMB anticipate that the transaction will be completed in the first half of 2016. WMB, headquartered in Tulsa, Oklahoma, owns approximately 60% of WPZ, including all of the 2% general-partner interest in WPZ. WPZ is a master limited partnership with operations across the natural gas value chain from gathering, processing and interstate transportation of natural gas and natural gas liquids to petrochemical production of ethylene, propylene and other olefins. With major positions in top U.S. supply basins and also in Canada, WPZ owns and operates more than 33,000 miles of pipelines system wide providing natural gas for clean-power generation, heating and industrial use. Sunoco, Inc. to Sunoco LP In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion . Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. The transaction was effective January 1, 2016. 2015 Transactions Sunoco LLC to Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million . Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. Susser to Sunoco LP In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million . The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries. Sunoco LP to ETE Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 21 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. Bakken Pipeline In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP 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 also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access, LLC and Energy Transfer Crude Oil Company, LLC, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction. Regency Merger On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 common units of ETP. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to ETP subsidiaries. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. 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 ETP 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. The following table summarizes the 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 were 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 8 . 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. 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 (1) 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 (1) None of the goodwill is expected to be deductible for tax purposes. 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. 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. The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 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 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. 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 Missouri Gas Energy division and Laclede Massachusetts agreed to acquire the assets of Southern Union New England Gas Company 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 New England Gas Company division. In September 2013, Southern Union completed its sale of the assets of Missouri Gas Energy 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 New England Gas Company 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 Missouri Gas Energy and New England Gas Company’s sale dates in September 2013 and December 2013, respectively: Year Ended December 31, 2013 Revenue from discontinued operations $ 415 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65 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 (which have subsequently converted to ETP common units in the Regency Merger) 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.

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2015
Investment In Affiliates [Abstract]
Investments In Affiliates	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES : The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014 , were as follows: December 31, 2015 2014 Citrus $ 1,739 $ 1,823 AmeriGas 80 94 FEP 115 130 MEP 660 695 HPC 402 422 Others 466 495 Total $ 3,462 $ 3,659 Citrus ETP owns CrossCountry, which 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. In 2012, 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. AmeriGas In 2012, ETP received 29.6 million AmeriGas common units in connection with the contribution of its propane operations. During the years ended December 31, 2014 and 2013, ETP sold 18.9 million and 7.5 million AmeriGas common units, respectively, for net proceeds of $814 million and $346 million , respectively. 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. FEP ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. MEP ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. HPC ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: December 31, 2015 2014 Current assets $ 632 $ 889 Property, plant and equipment, net 10,213 10,520 Other assets 2,649 2,687 Total assets $ 13,494 $ 14,096 Current liabilities $ 841 $ 1,983 Non-current liabilities 7,950 7,359 Equity 4,703 4,754 Total liabilities and equity $ 13,494 $ 14,096 Years Ended December 31, 2015 2014 2013 Revenue $ 4,026 $ 4,925 $ 4,695 Operating income 1,302 1,071 1,197 Net income 807 577 699 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, 2015
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 Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method. 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, 2015 2014 2013 Income from continuing operations $ 1,093 $ 1,060 $ 282 Less: Income (loss) from continuing operations attributable to noncontrolling interest (96 ) 434 99 Income from continuing operations, net of noncontrolling interest 1,189 626 183 Less: General Partner’s interest in income from continuing operations 3 2 — Less: Class D Unitholder’s interest in income from continuing operations 3 2 — Income from continuing operations available to Limited Partners $ 1,183 $ 622 $ 183 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,062.8 1,088.6 1,121.8 Basic income from continuing operations per Limited Partner unit $ 1.11 $ 0.58 $ 0.17 Basic income from discontinued operations per Limited Partner unit $ — $ — $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 1,183 $ 622 $ 183 Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder (2 ) (2 ) — Diluted income from continuing operations available to Limited Partners 1,181 620 183 Weighted average limited partner units 1,062.8 1,088.6 1,121.8 Dilutive effect of unconverted unit awards 1.6 2.2 — Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,064.4 1,090.8 1,121.8 Diluted income from continuing operations per Limited Partner unit $ 1.11 $ 0.57 $ 0.17 Diluted income from discontinued operations per Limited Partner unit $ — $ — $ 0.01

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2015
Debt Obligations [Abstract]
Debt Disclosure [Text Block]	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2015 2014 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 1,150 5.5% Senior Notes due June 1, 2027 1,000 — ETE Senior Secured Term Loan, due December 2, 2019 2,190 1,400 ETE Senior Secured Revolving Credit Facility due December 18, 2018 860 940 Unamortized premiums, discounts and fair value adjustments, net (17 ) 3 Deferred debt issuance costs (38 ) (34 ) 6,332 4,646 Subsidiary Indebtedness: ETP Debt 5.95% Senior Notes due February 1, 2015 — 750 6.125% Senior Notes due February 15, 2017 400 400 2.5% Senior Notes due June 15, 2018 650 — 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 5.75% Senior Notes due September 1, 2020 (assumed from Regency) 400 — 4.15% Senior Notes due October 1, 2020 1,050 700 6.5% Senior Notes due May 15, 2021 (assumed from Regency) 500 — 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 (assumed from Regency) 900 — 5.0% Senior Notes due October 1, 2022 (assumed from Regency) 700 — 3.60% Senior Notes due February 1, 2023 800 800 5.5% Senior Notes due April 15, 2023 (assumed from Regency) 700 — 4.5% Senior Notes due November 1, 2023 (assumed from Regency) 600 — 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 4.05% Senior Notes due March 15, 2025 1,000 — 4.75% Senior Notes due January 15, 2026 1,000 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 — 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 — 6.125% Senior Notes due December 15, 2045 1,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 545 546 ETP $3.75 billion Revolving Credit Facility due November 2019 1,362 570 Unamortized premiums, discounts and fair value adjustments, net (21 ) (1 ) Deferred debt issuance costs (147 ) (55 ) 20,633 11,404 Transwestern Debt 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 ) Deferred debt issuance costs (2 ) (3 ) 779 778 Panhandle Debt 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 75 99 1,160 1,184 Sunoco, Inc. Debt 9.625% Senior Notes due April 15, 2015 — 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 20 35 485 750 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 (1) 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.4% Senior Notes due April 1,2021 600 — 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 500 500 5.95% Senior Notes due December 1, 2025 400 — 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 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) — 35 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 562 150 Unamortized premiums, discounts and fair value adjustments, net 85 100 Deferred debt issuance costs (32 ) (26 ) 5,590 4,234 Sunoco LP Debt 5.5% Senior Notes Due August 1, 2020 600 — 6.375% Senior Notes due April 1, 2023 800 — Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 450 683 Deferred debt issuance costs (18 ) — 1,832 683 Regency Debt, net of deferred debt issuance costs of $58 million (3) — 6,583 Other 157 223 36,968 30,485 Less: current maturities 131 1,008 $ 36,837 $ 29,477 (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. (2) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.50 billion Revolving Credit Facility. (3) The Regency senior notes were redeemed and/or assumed by ETP. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $96 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2016 $ 308 2017 1,189 2018 2,515 2019 5,007 2020 4,729 Thereafter 23,316 Total $ 37,064 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 constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP 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 and ETE Common Holdings, LLC, (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 and/or the consolidated subsidiaries of ETP. 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: • 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 $20.53 billion and $11.94 billion as of December 31, 2015 and 2014, 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, Class H unitholders and Class I unitholders) of $334 million , $823 million and $(50) million for the years ended December 31, 2015, 2014 and 2013, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations. • As of December 31, 2014, ETE Common Holdings, LLC (“ETE Common Holdings”) owned 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 owned 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. During 2015, all of the units held by ETE Common Holdings were redeemed by ETP. ETE Common Holdings does not own the general partner interests in ETP; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP. The carrying values of ETE Common Holdings’ investments in ETP was $1.72 billion as of December 31, 2014, and ETE Common Holdings’ equity in earnings from its investments in ETP was $292 million for the year ended December 31, 2014. ETP’s general partner interest, Common Units and Class H Units are reflected separately in ETP’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. Therefore, the financial statements of the Non-Reporting Entities have been excluded from this Annual Report on Form 10-K. In May 2015, ETE issued $1 billion aggregate principal amount of its 5.5% senior notes maturing June 1, 2027 . 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 $465 million as of December 31, 2015 . 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 3.65% at December 31, 2015 . 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. In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018 , $350 million aggregate principal amount of 4.15% senior notes due October 2020 , $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045 . ETP used the net proceeds of $2.98 billion from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025 , $500 million aggregate principal amount of 4.90% senior notes due March 2035 , and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045 . ETP used the $2.48 billion net proceeds from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. At the time of the Regency Merger, Regency had outstanding $5.1 billion principal amount of senior notes. On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019 . Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023 . On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it became a co-obligor with respect to such payment obligations thereunder. Accordingly, pursuant to the terms of such supplemental indentures the Panhandle Guarantee was terminated. On August 10, 2015, ETP entered into various supplemental indentures pursuant to which ETP has agreed to assume all of the obligations of Regency under the outstanding Regency senior notes. On August 13, 2015, ETP redeemed in full the outstanding amount of the 8.375% senior notes due June 2020 (“the 2020 notes”) and 6.50% senior notes due May 2021 (“the 2021 notes”). The amount paid to redeem the 2020 Notes included a make whole premium of $40 million and the amount paid to redeem the 2021 Notes included a make whole premium of $24 million . Transwestern Senior Notes The Transwestern senior notes are redeemable 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 November 2015, Sunoco Logistics issued $600 million aggregate principal amount of 4.40% senior notes due April 2021 and $400 million aggregate principal amount of 5.95% senior notes due December 2025. Sunoco LP Senior Notes In July 2015, Sunoco LP issued $600 million aggregate principal amount of 5.5% senior notes due August 2020. The net proceeds from the offering were used to fund a portion of the cash consideration for Sunoco LP’s acquisition of Susser. In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests and to repay outstanding balances under the Sunoco LP revolving credit facility. 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 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. In March 2015, the Parent Company entered into a Senior Secured Term Loan C Agreement (the “ETE Term Loan C Agreement”), which increased the aggregate principal amount under the ETE Term Loan Facility to $2.25 billion , an increase of $850 million . The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, 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 3.25% and the applicable margin for base rate loans is 2.25% . For the $1.4 billion aggregate principal amount under the Senior Secured Term Loan B Agreement of the ETE Term Loan Facility, 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 October 2015, ETE entered into an Amended and Restated Commitment Letter with a syndicate of 20 banks for a senior secured credit facility in an aggregate principal amount of $6.05 billion in order to fund the cash portion of the WMB Merger. Under the terms of the facility, the banks have committed to provide a 364-day secured loan that can be extended at ETE’s option for an additional year. The interest rate on the facility is capped at 5.5% . 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 $3.75 billion and expires in November 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. As of December 31, 2015 , the ETP Credit Facility had $1.36 billion outstanding, and the amount available for future borrowings was $2.24 billion after taking into account letters of credit of $145 million . The weighted average interest rate on the total amount outstanding as of December 31, 2015 was 1.86% . Sunoco Logistics Credit Facilities Sunoco Logistics maintains a $2.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $3.25 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, 2015 , the Sunoco Logistics Credit Facility had $562 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 . The Sunoco LP Credit Facility was amended to $1.50 billion in April 2015. As of December 31, 2015 , the Sunoco LP Credit Facility had $450 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 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’ $2.50 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 3.6 to 1 at December 31, 2015 , as calculated in accordance with the credit agreements. 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, 2015 .

Redeemable Preferred Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2015
Preferred Units, Preferred Partners' Capital Account [Abstract]
Redeemable Preferred Units	REDEEMABLE PREFERRED UNITS: In connection with the closing of the Regency Merger, Regency’s 1.9 million outstanding series A cumulative convertible preferred units were converted into corresponding newly issued ETP cumulative convertible series A preferred units on a one-for-one basis. If outstanding, the ETP Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. Holders of the ETP Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of ETP common units issuable upon conversion of the ETP Preferred Units is equal to the issue price of $18.30 , plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37 . As of December 31, 2015 , the ETP Preferred Units were convertible into 0.9 million ETP Common Units.

Equity

Equity	12 Months Ended
	Dec. 31, 2015
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, 2015 , there were issued and outstanding 1.04 billion Common Units representing an aggregate 99.53% 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, 2015 , 2014 and 2013 was as follows: Years Ended December 31, 2015 2014 2013 Number of Common Units, beginning of period 1,077.5 1,119.8 1,119.8 Conversion of Class D Units to ETE Common Units 0.9 — — Repurchase of common units under buyback program (33.6 ) (42.3 ) — Number of Common Units, end of period 1,044.8 1,077.5 1,119.8 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 “2014 Split”). The 2014 Split was completed on January 27, 2014. The 2014 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. On May 28, 2015, ETE announced that the board of directors its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2015 Split”). The 2015 Split was completed on July 27, 2015. The 2015 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 July 15, 2015. 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 42.3 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 an additional $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. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015, and there was $936 million available to use under the program as of December 31, 2015. 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 3,000,000 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 3,000,000 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 3,080,000 Class D Units of ETE, which number of Class D Units includes an additional 80,000 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, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, 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. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and his termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. As of this date, it is ETE’s current position that as a result of Mr. Welch’s termination, the unconverted Class D units are not eligible to be converted. 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 In April 2013, ETP completed a public offering of 13.8 million ETP common units for net proceeds of $657 million . The proceeds were used to repay amounts outstanding under the ETP Credit Facility 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. During the year ended December 31, 2015 , ETP issued 21.1 million units for $1.07 billion , net of commissions of $11 million . As of December 31, 2015 , $328 million of ETP Common Units remained available to be issued under the currently effective equity distribution agreement. ETP’s Equity Incentive Plan Activity 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, 2015 , 2014 and 2013 , aggregate distributions of $360 million , $155 million , and $109 million , respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 12.8 million ETP Common Units. In December 2015, ETP provided notice to the DRIP participants that it has changed the discount at which participants may purchase ETP common units through the DRIP from 5% to 1% , effective for the distributions payable in respect of the fourth quarter of 2015 and future quarters. As of December 31, 2015 , a total of 11.5 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 are reported by ETP as treasury units. 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. Bakken Pipeline Transaction In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP 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 also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction, ETP issued 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 Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s 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 ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” 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 . In the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion . During the year ended December 31, 2015 , Sunoco Logistics received proceeds of $890 million , net of commissions of $10 million , from the issuance of 26.8 million common units pursuant to the equity distribution agreement, which were used for general partnership purposes. In March 2015, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million . The proceeds were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering. In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the 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 $1.50 billion Sunoco LP Credit Facility and for general partnership purposes. In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million . The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility. Contributions to Subsidiaries The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. 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. 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 Sunoco LP 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, 2015, 2014, and 2013 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 7, 2013 February 19, 2013 $ 0.1588 March 31, 2013 May 6, 2013 May 17, 2013 0.1613 June 30, 2013 August 5, 2013 August 19, 2013 0.1638 September 30, 2013 November 4, 2013 November 19, 2013 0.1681 December 31, 2013 February 7, 2014 February 19, 2014 0.1731 March 31, 2014 May 5, 2014 May 19, 2014 0.1794 June 30, 2014 August 4, 2014 August 19, 2014 0.1900 September 30, 2014 November 3, 2014 November 19, 2014 0.2075 December 31, 2014 February 6, 2015 February 19, 2015 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650 September 30, 2015 November 5, 2015 November 19, 2015 0.2850 December 31, 2015 February 4, 2016 February 19, 2016 0.2850 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 Rate December 31, 2012 February 7, 2013 February 14, 2013 $ 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units: Total Year 2016 $ 137 2017 128 2018 105 2019 95 Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared by Sunoco Logistics during the years ended December 31, 2015, 2014, and 2013 were as follows: Quarter Ended Record Date Payment Date Rate 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 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790 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 Rate September 30, 2014 November 18, 2014 November 28, 2014 $ 0.5457 December 31, 2014 February 17, 2015 February 27, 2015 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 September 30, 2015 November 17, 2015 November 27, 2015 0.7454 December 31, 2015 February 5, 2016 February 16, 2016 0.8013 Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: December 31, 2015 2014 Available-for-sale securities $ — $ 3 Foreign currency translation adjustment (4 ) (3 ) Net losses on commodity related hedges — (1 ) Actuarial gain (loss) related to pensions and other postretirement benefits 8 (57 ) Investments in unconsolidated affiliates, net — 2 Subtotal 4 (56 ) Amounts attributable to noncontrolling interest (4 ) 51 Total AOCI included in partners’ capital, net of tax $ — $ (5 ) The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): December 31, 2015 2014 Available-for-sale securities $ (2 ) $ (1 ) Foreign currency translation adjustment 4 2 Actuarial (gain) loss relating to pension and other postretirement benefits 7 (37 ) Total $ 9 $ (36 )

Unit-Based Compensation Plans

Unit-Based Compensation Plans	12 Months Ended
	Dec. 31, 2015
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Unit-Based Compensation Plans	UNIT-BASED COMPENSATION PLANS: We, ETP, Sunoco Logistics and Sunoco LP 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 12,000,000 units. As of December 31, 2015 , 11,367,454 units remain available to be awarded under the plan. On December 23, 2013, ETE and Mr. Welch entered a Class D Unit Agreement providing for the issuance to Mr. Welch of an aggregate of 3,080,000 Class D Units of ETE. Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, 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. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and his termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. As of this date, it is ETE’s current position that as a result of Mr. Welch’s termination, the unconverted Class D units are not eligible to be converted. During 2015 , no ETE unit awards were granted to ETE employees and 12,748 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 2015 , a total of 26,244 ETE Common Units vested, with a total fair value of $0.8 million as of the vesting date. As of December 31, 2015 , excluding Class D units, a total of 56,096 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 2.7 years . ETP Unit-Based Compensation Plans Unit-Based Compensation Plan ETP has issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2015 , an aggregate total of 5.3 million ETP Common Units remain available to be awarded under ETP’s equity incentive 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 ETP Units Weighted Average Grant-Date Fair Value Per ETP Unit Unvested awards as of December 31, 2014 3.5 $ 53.83 Awards granted 2.1 35.21 Awards vested (1.2 ) 48.67 Awards forfeited (0.4 ) 55.44 Conversion of RGP unit awards to ETP unit awards 0.8 58.88 Unvested awards as of December 31, 2015 4.8 47.61 During the years ended December 31, 2015, 2014, and 2013 , the weighted average grant-date fair value per unit award granted was $35.21 , $60.85 and $50.54 , respectively. The total fair value of awards vested was $49 million , $26 million and $29 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2015 , a total of 4.8 million unit awards remain unvested, for which ETP expects to recognize a total of $147 million in compensation expense over a weighted average period of 2.1 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, 2015 , a total of 0.6 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2015 , ETP expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.3 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. As of December 31, 2015 , a total of 2.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $52 million of expense over a weighted-average period of 3.0 years . Sunoco LP Unit-Based Compensation Plan Sunoco LP’s general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco LP. As of December 31, 2015 , a total of 1.1 million Sunoco LP restricted units were outstanding for which Sunoco LP expects to recognize $40 million of expense over a weighted-average period of 3.3 years .

Income Taxes _Disclosure_

Income Taxes [Disclosure]	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Current expense (benefit): Federal $ (292 ) $ 321 $ 51 State (51 ) 86 (1 ) Total (343 ) 407 50 Deferred expense (benefit): Federal 272 (53 ) (14 ) State (29 ) 3 57 Total 243 (50 ) 43 Total income tax expense (benefit) from continuing operations $ (100 ) $ 357 $ 93 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, 2015 , 2014 and 2013 is as follows: December 31, 2015 December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Income tax expense (benefit) at U.S. statutory rate of 35 percent $ (19 ) $ (19 ) $ 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 — — Dividend received deduction (22 ) (22 ) — — — — Premium on debt retirement — — (10 ) (10 ) — — Audit settlement (7 ) (7 ) — — — — Foreign taxes — — (8 ) (8 ) — — State income taxes (net of federal income tax effects) (45 ) (26 ) 9 55 31 41 Other (26 ) (26 ) 3 3 (16 ) (17 ) Income tax expense (benefit) from continuing operations $ (119 ) $ (100 ) $ 311 $ 357 $ 84 $ 93 (1) Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. (2) Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. 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, 2015 2014 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 217 $ 116 Pension and other postretirement benefits 36 47 Long term debt 61 53 Other 162 111 Total deferred income tax assets 476 327 Valuation allowance (121 ) (84 ) Net deferred income tax assets 355 243 Deferred income tax liabilities: Properties, plants and equipment (1,633 ) (1,583 ) Inventory — (153 ) Investments in unconsolidated affiliates (2,976 ) (2,530 ) Trademarks (286 ) (355 ) Other (50 ) (32 ) Total deferred income tax liabilities (4,945 ) (4,653 ) Accumulated deferred income taxes $ (4,590 ) $ (4,410 ) As a result of the early adoption and retrospective application of ASU 2015-17 (see Note 2), $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. 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, 2015 2014 Net deferred income tax liability, beginning of year $ (4,410 ) $ (3,984 ) Susser acquisition — (488 ) Tax provision (including discontinued operations) (242 ) 62 Other 62 — Net deferred income tax liability $ (4,590 ) $ (4,410 ) ETP Holdco, Susser Petroleum Property Company and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $67 million , all of which will expire in 2033 through 2034 . Our corporate subsidiaries have state net operating loss carryforward benefits of $123 million , net of federal tax, which expire between 2016 and 2035. The valuation allowance of $121 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, 2015 2014 2013 Balance at beginning of year $ 440 $ 429 $ 27 Additions attributable to tax positions taken in the current year 178 20 — Additions attributable to tax positions taken in prior years — (1 ) 406 Settlements — (5 ) — Lapse of statute (8 ) (3 ) (4 ) Balance at end of year $ 610 $ 440 $ 429 As of December 31, 2015 , we have $588 million ( $550 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 ( $3 million , net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2015 , we recognized interest and penalties of less than $1 million . At December 31, 2015 , we have interest and penalties accrued of $5 million , net of tax. 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 $519 million . However, due to the uncertainty surrounding the claims, a reserve of $519 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, 2015 . In December of 2015, The Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“ Nextel ”) that the Pennsylvania limitation on NOL carryforwards violated the uniformity clause of the Pennsylvania Constitution. Based upon the decision in Nextel , Sunoco, Inc. is recognizing approximately $46 million ( $30 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims. However, as the Nextel decision is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9 million ( $6 million after federal income tax benefits) against the receivable. In general, ETE and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2012 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. Sunoco, Inc. has been examined by the IRS for tax years through 2012. However, 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 statute, 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 was under examination by the IRS for the tax years 2004 through 2009. In July 2015, we and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, we recognized a net tax benefit of $7 million . 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, 2015
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. Guarantee of Collection Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP had agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. ETP Retail Holdings Guarantee of Sunoco LP Notes In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $775 million of cash and $41 million of Sunoco LP common units. The cash portion of the consideration was financed through Sunoco LP’s issuance of $800 million principal amount of 6.375% senior notes due 2023. Retail Holdings entered into a guarantee of collection with Sunoco LP and Sunoco Finance Corp., a wholly owned subsidiary of Sunoco LP, pursuant to which Retail Holdings has agreed to provide a guarantee of collection, but not of payment, to Sunoco LP with respect to the principal amount of the senior notes issued by Sunoco LP. 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 late 2015. On June 22, 2015, Transwestern filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On October 15, 2015, the FERC issued an order approving the rate case settlement without condition. 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 no earlier than May 1, 2015, subject to refund. On September 11, 2015, FGT filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On December 4, 2015, the FERC issued an order approving the rate case settlement without condition. Sea Robin Rate Case On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin sought to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject to refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and the settlement, as modified on January 16, 2015, was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million , including interest. Commitments In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters 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, 2015 2014 2013 Rental expense (1) $ 225 $ 159 $ 151 Less: Sublease rental income (16 ) (26 ) (24 ) Rental expense, net $ 209 $ 133 $ 127 (1) Includes contingent rentals totaling $26 million , $24 million and $22 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Future minimum lease commitments for such leases are: Years Ending December 31: 2016 $ 121 2017 114 2018 103 2019 96 2020 97 Thereafter 602 Future minimum lease commitments 1,133 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 1,099 ETP’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, 2015 , Sunoco, Inc. is a defendant in six 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, and one case by the City of Breaux Bridge in the USDC Western District of Louisiana. 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. In November 2015, Sunoco along with other co-defendants agreed to a global settlement in principle of the City of Breaux Bridge MTBE 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. Regency Merger Litigation Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction. On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees. On February 9, 2015, Stuart Yeager, a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit. On February 10, 2015, Lucien Coggia a purported Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit. On February 3, 2015, Linda Blankman, a purported Regency unitholder, filed a class action complaint on behalf of the Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit. On February 6, 2015, Edwin Bazini, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit. On March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934. On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Stephen Weaver, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim. On February 13, 2015, Irwin Berlin, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit. On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”). On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit. On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery. On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed. On July 6, 2015, Defendants filed Motions to Dismiss and the briefing has since been completed. Oral argument on the Motions was held in December 2015. On September 29, 2015, Chancellor Bouchard ordered discovery stayed, pending a ruling on Defendants’ Motions to Dismiss. On June 5, 2015, the Dieckman Lawsuit was dismissed. On July 23, 2015, the Blankman, Bazini, Hinnau, Weaver and Berlin Lawsuits were dismissed. On August 20, 2015, the Cooperman Lawsuit was dismissed. The Consolidated Federal Lawsuit was terminated once all named plaintiffs voluntarily dismissed. On January 8, 2016, the plaintiffs in the Consolidated State Lawsuit filed a notice of non-suit without prejudice. The Dieckman DE Lawsuit is the only lawsuit that remains. The Defendants cannot predict the outcome of this lawsuit, or the amount of time and expense that will be required to resolve it. The Defendants intend to vigorously defend the lawsuit. 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 with the Texas Court of Appeals, and briefing by Enterprise and ETP is compete. Oral argument has not been scheduled. 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. Litigation Relating to the WMB Merger Following the September 28, 2015, announcement of the proposed merger between ETE and WMB, purported WMB shareholders filed lawsuits in state and federal courts in Delaware and federal court in Oklahoma asserting claims relating to the proposed transaction. Between October 5, 2015 and December 15, 2015, purported WMB stockholders filed five putative class action lawsuits against ETE and other defendants in the Delaware Court of Chancery challenging the merger. The suits were captioned Greenwald v. The Williams Companies, Inc., C.A. No. 11573, Ozaki v. Armstrong, C.A. No. 11574, Blystone v. The Williams Companies, Inc., C.A. No. 11601, Glener v. The Williams Companies, Inc., C.A. No. 11606, and Amaitis v. Armstrong, C.A. No. 11809. The complaints named as defendants the WMB Board, ETE, ETC, Energy Transfer Corp GP, LLC, General Partner, and Energy Transfer Equity GP, LLC (collectively, with the exception of the WMB board, the “ETE Defendants”). The Greenwald, Blystone and Glener complaints named WMB as a defendant also, and the Amaitis complaint named Barclays Capital Inc. (“Barclays”), and Lazard Freres & Co. (“Lazard”) as defendants. The Greenwald, Ozaki, Blystone and Glener complaints alleged that the WMB Board breached its fiduciary duties to WMB stockholders by agreeing to sell WMB through an unfair process and for an unfair price, and that the other named defendants aided and abetted this supposed breach of fiduciary duties. The Amaitis complaint alleged that the WMB Board breached its fiduciary duties by failing to disclose all material information about the merger, and that the directors of the WMB Board who voted in favor of the proposed merger violated their fiduciary duties by selling WMB through an unfair process and for an unfair price. The Amaitis complaint also alleged that the other named defendants aided and abetted these supposed breaches of fiduciary duty. The complaints sought, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On January 13, 2016, the Delaware Court of Chancery consolidated, pursuant to a stipulation among the plaintiffs, the Greenwald, Ozaki, Blystone, Glener, and Amaitis actions, along with another case not involving the ETE Defendants, into a new consolidated action captioned In re The Williams Companies, Inc. Merger Litigation, Consolidated C.A. No. 11844. In its stipulated order, the Court dismissed without prejudice the ETE Defendants, Barclays and Lazard from the consolidated action. There currently are no lawsuits related to the WMB merger pending against the ETE Defendants in Delaware state court. ETE is currently a defendant in two lawsuits in federal district court challenging the proposed merger with WMB. On January 14, 2016, a purported stockholder in WMB filed a lawsuit against WMB and ETE, captioned Bumgarner v. The Williams Companies, Inc., Case No. 16-cv-26-GKF-FHM, in the United States District Court for the Northern District of Oklahoma. The plaintiff alleges that ETE and WMB have violated Section 14 of the Securities Exchange Act of 1934 (the “Exchange Act”) by making allegedly false representations concerning the merger. As relief, the complaint seeks an injunction against the proposed merger. On February 1, 2016, the plaintiff amended his complaint. On February 19, 2016, ETE and WMB moved to dismiss the lawsuit. On January 19, 2016, a purported stockholder in WMB filed a lawsuit against WMB, the WMB Board, and the ETE Defendants, captioned City of Birmingham Retirement and Relief System v. Armstrong, Case No. 1:16-cv-00017-RGA, in the United States District Court for the District of Delaware. The lawsuit alleges that the WMB Board has violated its duty of disclosure by issuing a misleading proxy statement in support of the transaction, that a majority of the WMB Board violated its fiduciary duties by voting in favor of the transaction, and that the ETE Defendants aided and abetted this supposed breach of fiduciary duties. The complaint also alleges that the WMB Board and WMB have violated Section 14 of the Exchange Act by issuing a supposedly misleading proxy statement, and that WMB and ETE have violated Section 20 of the Exchange Act by supposedly causing a misleading proxy statement to be issued. On January 20, 2016, the plaintiff filed a motion for expedited discovery, and all defendants filed an opposition to that motion on February 8, 2016. On February 19, plaintiff filed a reply brief in support of expedited discovery. On February 10, 2016, WMB and the WMB Board filed a motion to dismiss the complaint, and on February 18, 2016, the ETE Defendants filed a motion to dismiss the complaint. 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, 2015 and 2014 , accruals of approximately $40 million and $37 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, 2015 or 2014 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. Compliance Orders from the New Mexico Environmental Department Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. Lone Star NGL Fractionators Notice of Enforcement Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $300,000 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, tribal, 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 investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas 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

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative Assets And Liabilities	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. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices 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. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes. We use futures and swaps 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 in our retail marketing segment. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. The following table details our outstanding commodity-related derivatives: December 31, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (602,500 ) 2016 - 2017 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (31,240,000 ) 2016 - 2017 (13,907,500 ) 2015 - 2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 357,092 2016 - 2017 288,775 2015 Futures (109,791 ) 2016 (156,000 ) 2015 Options — Puts 260,534 2016 (72,000 ) 2015 Options — Calls 1,300,647 2016 198,556 2105 Crude (Bbls) – Futures (591,000 ) 2016 - 2017 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,522,500 ) 2016 - 2017 57,500 2015 Swing Swaps IFERC 71,340,000 2016 - 2017 46,150,000 2015 Fixed Swaps/Futures (14,380,000 ) 2016 - 2018 (34,304,000 ) 2015 - 2016 Forward Physical Contracts 21,922,484 2016 - 2017 (9,116,777 ) 2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (8,146,800 ) 2016 - 2018 (4,417,400 ) 2015 Refined Products (Bbls) – Futures (1,289,000 ) 2016 - 2017 13,745,755 2015 Corn (Bushels) – Futures 1,185,000 2016 — — Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item — Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Interest Rate 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, 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 200 200 ETP July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 300 ETP July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 ETP July 2019 (4) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 300 ETP July 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — ETP June 2021 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 — ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (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, midstream companies and independent power generators. 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. 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 December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 38 $ 43 $ (3 ) $ — 38 43 (3 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 353 617 (306 ) (577 ) Commodity derivatives 63 107 (47 ) (23 ) Interest rate derivatives — 3 (171 ) (155 ) Embedded derivatives in ETP Preferred Units — — (5 ) (16 ) 416 727 (529 ) (771 ) Total derivatives $ 454 $ 770 $ (532 ) $ (771 ) 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, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 3 $ (176 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 63 107 (47 ) (23 ) Broker cleared derivative contracts Other current assets 391 660 (309 ) (577 ) 454 770 (532 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (17 ) (19 ) 17 19 Payments on margin deposit Other current assets (309 ) (577 ) 309 577 Total net derivatives $ 128 $ 174 $ (206 ) $ (175 ) We disclose the non-exchange traded financial derivative instruments as derivative 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, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ (1 ) Total $ — $ — $ (1 ) Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (3 ) $ 4 Total $ — $ (3 ) $ 4 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2015 2014 2013 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ (8 ) $ 8 Total $ 21 $ (8 ) $ 8 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2015 2014 2013 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (11 ) $ (6 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 15 199 (21 ) Commodity contracts – Non-trading Deferred gas purchases — — (3 ) Interest rate derivatives Gains (losses) on interest rate derivatives (18 ) (157 ) 53 Embedded derivatives Other, net 12 3 6 Total $ (2 ) $ 39 $ 24

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2015
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, Sunoco LP 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 $40 million , $50 million and $47 million to the 401(k) savings plan for the years ended December 31, 2015, 2014, and 2013 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2015 and 2014 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. 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 paid lump sums to eligible active and terminated vested participants in December 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: December 31, 2015 December 31, 2014 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 $ 718 $ 65 $ 203 $ 632 $ 61 $ 223 Interest cost 23 2 4 28 3 5 Amendments — — — — — 1 Benefits paid, net (46 ) (8 ) (20 ) (45 ) (9 ) (28 ) Actuarial (gain) loss and other 16 (2 ) (6 ) 130 10 2 Settlements (691 ) — — (27 ) — — Benefit obligation at end of period $ 20 $ 57 $ 181 $ 718 $ 65 $ 203 Change in plan assets: Fair value of plan assets at beginning of period $ 598 $ — $ 272 $ 600 $ — $ 284 Return on plan assets and other 16 — — 70 — 7 Employer contributions 138 — 9 — — 9 Benefits paid, net (46 ) — (20 ) (45 ) — (28 ) Settlements (691 ) — — (27 ) — — Fair value of plan assets at end of period $ 15 $ — $ 261 $ 598 $ — $ 272 Amount underfunded (overfunded) at end of period $ 5 $ 57 $ (80 ) $ 120 $ 65 $ (69 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 103 $ — $ — $ 96 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (5 ) (48 ) (22 ) (120 ) (56 ) (25 ) $ (5 ) $ (57 ) $ 79 $ (120 ) $ (65 ) $ 69 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ 2 $ 4 $ (18 ) $ 18 $ 7 $ (21 ) Prior service cost — — 16 — — 18 $ 2 $ 4 $ (2 ) $ 18 $ 7 $ (3 ) The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 20 $ 57 N/A $ 718 $ 65 N/A Accumulated benefit obligation 20 57 $ 181 718 65 $ 203 Fair value of plan assets 15 — 261 598 — 272 Components of Net Periodic Benefit Cost December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net Periodic Benefit Cost: Interest cost $ 25 $ 4 $ 31 $ 5 Expected return on plan assets (16 ) (8 ) (40 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — (1 ) (1 ) Settlements 32 — (4 ) — Net periodic benefit cost $ 41 $ (3 ) $ (14 ) $ (3 ) Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.59 % 2.38 % 3.62 % 2.24 % 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, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.79 % 4.65 % 3.02 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % 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, 2015 2014 Health care cost trend rate 7.16 % 7.09 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.39 % 5.41 % 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, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 15 $ — $ 15 $ — Total $ 15 $ — $ 15 $ — (1) Comprised of 100% equities as of December 31, 2015 . 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 . 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, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset Category: Cash and Cash Equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 141 141 — — Fixed income securities 102 — 102 — Total $ 261 $ 159 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . 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 and 6% cash as of December 31, 2014 . 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. Contributions We expect to contribute $16 million to pension plans and $10 million to other po stretirement plans in 2016 . 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) 2016 $ 20 $ 9 $ 21 2017 — 7 20 2018 — 7 19 2019 — 6 17 2020 — 6 16 2021 – 2025 — 2 58 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, 2015
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS: The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements. In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15 ). In addition, subsidiaries of ETE recorded sales with affiliates of $290 million , $965 million and $1.44 billion during the years ended December 31, 2015 , 2014 and 2013 , respectively.

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2015
Reportable Segments [Abstract]
Reportable Segments	REPORTABLE SEGMENTS: Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • 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. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented. The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP the equity in earnings from which is also eliminated in ETE’s consolidated financial statements. The amounts included in the Investment in Sunoco LP segment have been retrospectively adjusted in these consolidated financial statements as a result of ETP’s contribution to Sunoco LP of the remaining 68.42% membership interest in Sunoco, LLC and 100% of the membership interests in Sunoco Retail LLC. 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. Eliminations in the tables below include the following: • 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 year ended December 31, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013. • MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above. Years Ended December 31, 2015 2014 2013 Revenues: Investment in ETP: Revenues from external customers $ 34,156 $ 55,475 $ 48,335 Intersegment revenues 136 — — 34,292 55,475 48,335 Investment in Sunoco LP: Revenues from external customers 18,449 7,343 — Intersegment revenues 11 — — 18,460 7,343 — Investment in Lake Charles LNG: Revenues from external customers 216 216 216 Adjustments and Eliminations: (10,842 ) (7,343 ) (216 ) Total revenues $ 42,126 $ 55,691 $ 48,335 Costs of products sold: Investment in ETP $ 27,029 $ 48,414 $ 42,580 Investment in Sunoco LP 16,476 6,767 — Adjustments and Eliminations (9,496 ) (6,767 ) — Total costs of products sold $ 34,009 $ 48,414 $ 42,580 Depreciation, depletion and amortization: Investment in ETP $ 1,929 $ 1,669 $ 1,296 Investment in Sunoco LP 278 86 — Investment in Lake Charles LNG 39 39 39 Corporate and Other 17 16 16 Adjustments and Eliminations (184 ) (86 ) (38 ) Total depreciation, depletion and amortization $ 2,079 $ 1,724 $ 1,313 Years Ended December 31, 2015 2014 2013 Equity in earnings of unconsolidated affiliates: Investment in ETP $ 469 $ 332 $ 236 Adjustments and Eliminations (193 ) — — Total equity in earnings of unconsolidated affiliates $ 276 $ 332 $ 236 Years Ended December 31, 2015 2014 2013 Segment Adjusted EBITDA: Investment in ETP $ 5,714 $ 5,710 $ 4,404 Investment in Sunoco LP 719 332 — Investment in Lake Charles LNG 196 195 187 Corporate and Other (104 ) (97 ) (43 ) Adjustments and Eliminations (590 ) (300 ) (181 ) Total Segment Adjusted EBITDA 5,935 5,840 4,367 Depreciation, depletion and amortization (2,079 ) (1,724 ) (1,313 ) Interest expense, net of interest capitalized (1,643 ) (1,369 ) (1,221 ) Gain on sale of AmeriGas common units — 177 87 Impairment losses (339 ) (370 ) (689 ) Gains (losses) on interest rate derivatives (18 ) (157 ) 53 Non-cash unit-based compensation expense (91 ) (82 ) (61 ) Unrealized gains (losses) on commodity risk management activities (65 ) 116 48 Losses on extinguishments of debt (43 ) (25 ) (162 ) Inventory valuation adjustments (249 ) (473 ) 3 Adjusted EBITDA related to discontinued operations — (27 ) (76 ) Adjusted EBITDA related to unconsolidated affiliates (713 ) (748 ) (727 ) Equity in earnings of unconsolidated affiliates 276 332 236 Non-operating environmental remediation — — (168 ) Other, net 22 (73 ) (2 ) Income from continuing operations before income tax expense $ 993 $ 1,417 $ 375 December 31, 2015 2014 2013 Total assets: Investment in ETP $ 65,173 $ 62,518 $ 49,900 Investment in Sunoco LP 8,842 8,773 — Investment in Lake Charles LNG 1,369 1,210 1,338 Corporate and Other 638 1,119 720 Adjustments and Eliminations (4,833 ) (9,341 ) (1,628 ) Total $ 71,189 $ 64,279 $ 50,330 Years Ended December 31, 2015 2014 2013 Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): Investment in ETP $ 8,167 $ 5,494 $ 3,327 Investment in Sunoco LP 491 154 — Investment in Lake Charles LNG 1 1 2 Adjustments and Eliminations (123 ) (90 ) 13 Total $ 8,536 $ 5,559 $ 3,342 December 31, 2015 2014 2013 Advances to and investments in affiliates: Investment in ETP $ 5,003 $ 3,760 $ 4,050 Adjustments and Eliminations (1,541 ) (101 ) (36 ) Total $ 3,462 $ 3,659 $ 4,014 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 Sunoco LP. Investment in ETP Years Ended December 31, 2015 2014 2013 Intrastate Transportation and Storage $ 1,912 $ 2,645 $ 2,242 Interstate Transportation and Storage 1,008 1,057 1,270 Midstream 2,622 4,770 3,220 Liquids Transportation and Services 3,232 3,730 2,025 Investment in Sunoco Logistics 10,302 17,920 16,480 Retail Marketing 12,478 22,484 21,004 All Other 2,738 2,869 2,094 Total revenues 34,292 55,475 48,335 Less: Intersegment revenues 136 — — Revenues from external customers $ 34,156 $ 55,475 $ 48,335 Investment in Sunoco LP Years Ended December 31, 2015 2014 2013 Retail operations $ 8,257 $ 3,095 $ — Wholesale operations 10,203 4,248 — Total revenues 18,460 7,343 — Less: Intersegment revenues 11 — — Revenues from external customers $ 18,449 $ 7,343 $ — Investment in Lake Charles LNG Lake Charles LNG’s revenues of $216 million , $216 million and $216 million for the years ended December 31, 2015, 2014 and 2013, respectively, were related to LNG terminalling.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
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 2015: Revenues $ 10,380 $ 11,594 $ 10,616 $ 9,536 $ 42,126 Operating income 617 896 650 236 2,399 Net income (loss) 221 772 238 (138 ) 1,093 Limited Partners’ interest in net income 282 298 291 312 1,183 Basic net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Diluted net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,080 $ 14,143 $ 14,987 $ 13,481 $ 55,691 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 $ 0.15 $ 0.15 $ 0.18 $ 0.11 $ 0.58 Diluted net income per limited partner unit $ 0.15 $ 0.15 $ 0.18 $ 0.11 $ 0.57 The three months ended December 31, 2015 and 2014 reflected the unfavorable impacts of $171 million and $456 million , respectively, related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2015 and 2014 reflected the recognition of impairment losses of $339 million and $370 million , respectively. Impairment losses in 2015 were primarily related to ETP’s Lone Star Refinery Services operations and ETP’s Transwestern pipeline, and in 2014 , impairment losses were primarily related to Regency’s Permian Basin gathering and processing operations.

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 1 $ 2 Accounts receivable from related companies 34 14 Other current assets — 1 Total current assets 35 17 PROPERTY, PLANT AND EQUIPMENT, net 20 — ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 5,764 5,390 INTANGIBLE ASSETS, net 6 10 GOODWILL 9 9 OTHER NON-CURRENT ASSETS, net 10 12 Total assets $ 5,844 $ 5,438 LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES: Accounts payable to related companies $ 111 $ 11 Interest payable 66 58 Accrued and other current liabilities 1 3 Total current liabilities 178 72 LONG-TERM DEBT, less current maturities 6,332 4,646 NOTE PAYABLE TO AFFILIATE 265 54 OTHER NON-CURRENT LIABILITIES 1 2 COMMITMENTS AND CONTINGENCIES PARTNERS’ CAPITAL: General Partner (2 ) (1 ) Limited Partners: Limited Partners – Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding at December 31, 2015 and 2014, respectively) (952 ) 648 Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) 22 22 Accumulated other comprehensive income (loss) — (5 ) Total partners’ capital (932 ) 664 Total liabilities and partners’ capital $ 5,844 $ 5,438 STATEMENTS OF OPERATIONS Years Ended December 31, 2015 2014 2013 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (112 ) $ (111 ) $ (56 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (294 ) (205 ) (210 ) Equity in earnings of unconsolidated affiliates 1,601 955 617 Gains on interest rate derivatives — — 9 Loss on extinguishment of debt — — (157 ) Other, net (5 ) (5 ) (8 ) INCOME BEFORE INCOME TAXES 1,190 634 195 Income tax expense (benefit) 1 1 (1 ) NET INCOME 1,189 633 196 GENERAL PARTNER’S INTEREST IN NET INCOME 3 2 — CLASS D UNITHOLDER’S INTEREST IN NET INCOME 3 2 — LIMITED PARTNERS’ INTEREST IN NET INCOME $ 1,183 $ 629 $ 196 STATEMENTS OF CASH FLOWS Years Ended December 31, 2015 2014 2013 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 1,103 $ 816 $ 768 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction (817 ) — — Proceeds from ETP Holdco Transaction — — 1,332 Contributions to unconsolidated affiliates — (118 ) (8 ) Capital expenditures (19 ) — — Purchase of additional interest in Regency — (800 ) — Payments received on note receivable from affiliate — — 166 Net cash provided by (used in) investing activities (836 ) (918 ) 1,490 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 3,672 3,020 2,080 Principal payments on debt (1,985 ) (1,142 ) (3,235 ) Distributions to partners (1,090 ) (821 ) (733 ) Proceeds from affiliate 210 54 — Redemption of Preferred Units — — (340 ) Units repurchased under buyback program (1,064 ) (1,000 ) — Debt issuance costs (11 ) (15 ) (31 ) Net cash provided by (used in) financing activities (268 ) 96 (2,259 ) DECREASE IN CASH AND CASH EQUIVALENTS (1 ) (6 ) (1 ) CASH AND CASH EQUIVALENTS, beginning of period 2 8 9 CASH AND CASH EQUIVALENTS, end of period $ 1 $ 2 $ 8

Estimates, Significant Accoun25

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2015
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, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. 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 February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting periods presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard. In August 2015, the FASB issued ASU No. 2015-16 " Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments. " This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements.
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 with 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 Sunoco LP Revenues from our two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignment basis, in which Sunoco LP retains 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. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease. 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 and take steps to mitigate risk as necessary. 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 identification of specific customers with payment issues.
Inventories	Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. 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 refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 420 392 Spare parts and other 377 319 Total inventories $ 1,636 $ 1,467 During the year ended December 31, 2015 , the Partnership recorded write downs of $249 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 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. Property, plant and equipment is reviewed 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. In 2015, we recorded $110 million fixed asset impairments related to ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities 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	Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes 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, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 5,254 $ (738 ) $ 5,144 $ (485 ) Trade names (15 years) 559 (25 ) 556 (15 ) Patents (9 years) 48 (16 ) 48 (11 ) Other (1 to 15 years) 15 (7 ) 36 (7 ) Total amortizable intangible assets 5,876 (786 ) 5,784 (518 ) Non-amortizable intangible assets: Trademarks 341 — 316 — Total intangible assets $ 6,217 $ (786 ) $ 6,100 $ (518 ) Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 303 $ 219 $ 120 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2016 $ 242 2017 242 2018 241 2019 239 2020 239 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. In 2015, we recorded $24 million of intangible asset impairments related to ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2013 $ 5,856 $ — $ 184 $ (146 ) $ 5,894 Goodwill acquired 2,340 3,143 — (3,143 ) 2,340 Lake Charles LNG Transaction (1) (184 ) — — 184 — Goodwill impairment (370 ) — — — (370 ) Other — — — 1 1 Balance, December 31, 2014 7,642 3,143 184 (3,104 ) 7,865 Goodwill acquired — 31 — — 31 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (63 ) — (164 ) (218 ) Balance, December 31, 2015 $ 5,428 $ 3,111 $ 184 $ (1,250 ) $ 7,473 (1) As discussed in Note 3 , ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $184 million 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 decrease in goodwill of $392 million during the year ended December 31, 2015 primarily due to the impairments discussed below as well as purchase price allocation adjustments. During 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets. This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015. During the fourth quarter of 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices. 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. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Other Non-Current Assets, net	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, 2015 2014 Unamortized financing costs (1) $ 29 $ 41 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 221 209 Total other non-current assets, net $ 730 $ 732 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
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, 2015 and 2014 , 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, 2015 2014 Investment in ETP: Interstate transportation and storage operations $ 58 $ 60 Investment in Sunoco Logistics 88 41 Retail marketing operations 66 87 $ 212 $ 188 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. Long-lived assets related to AROs aggregated $18 million and were reflected as property, plant and equipment on our balance sheet as of December 31, 2015 and 2014 . In addition, Panhandle had $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015 .
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.
Redeemable Noncontrolling Interest [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 the consolidated balance sheet.
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. 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, 2015 was $33.22 billion and $36.97 billion , respectively. As of December 31, 2014 , the aggregate fair value and carrying amount of our consolidated debt obligations was $31.68 billion and $30.49 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
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). Excise taxes collected by our retail marketing operations were $3.05 billion , $2.46 billion and $2.22 billion for the years ended December 31, 2015 , 2014 and 2013 , respectively.
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, 2015, 2014, and 2013 , 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 ETP Holdco, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. 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 within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
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.

Estimates, Significant Accoun26

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2015
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. The annual impairment test is performed during the fourth quarter.
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, 2015 2014 2013 Accounts receivable $ 856 $ 600 $ (556 ) Accounts receivable from related companies (5 ) 30 64 Inventories (430 ) 51 (254 ) Exchanges receivable 14 18 (8 ) Other current assets (239 ) 133 (81 ) Other non-current assets, net 250 (6 ) (23 ) Accounts payable (1,127 ) (850 ) 541 Accounts payable to related companies 400 5 (140 ) Exchanges payable (79 ) (99 ) 128 Accrued and other current liabilities (618 ) (59 ) 192 Other non-current liabilities (261 ) (73 ) 147 Derivative assets and liabilities, net 75 19 (159 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (1,164 ) $ (231 ) $ (149 )
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, 2015 2014 2013 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 910 $ 643 $ 226 Net gains (losses) from subsidiary common unit transactions (526 ) 744 (384 ) NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ 34 $ — $ — 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 $ 1,800 $ 1,416 $ 1,256 Cash paid for income taxes 72 345 58
Schedule of Inventory	Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 420 392 Spare parts and other 377 319 Total inventories $ 1,636 $ 1,467
Other Current Assets	Other current assets consisted of the following: December 31, 2015 2014 Deposits paid to vendors $ 74 $ 65 Income taxes receivable 326 17 Prepaid expenses and other 172 205 Total other current assets $ 572 $ 287
Property, Plant and Equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2015 2014 Land and improvements $ 686 $ 1,307 Buildings and improvements (1 to 45 years) 1,526 1,922 Pipelines and equipment (5 to 83 years) 32,677 27,149 Natural gas and NGL storage facilities (5 to 46 years) 390 1,214 Bulk storage, equipment and facilities (2 to 83 years) 2,853 4,010 Tanks and other equipment (5 to 40 years) 1,488 58 Retail equipment (2 to 99 years) 401 515 Vehicles (1 to 25 years) 220 203 Right of way (20 to 83 years) 2,573 2,451 Furniture and fixtures (2 to 25 years) 57 59 Linepack 61 119 Pad gas 44 44 Natural resources 484 454 Other (1 to 30 years) 3,675 999 Construction work-in-process 7,844 4,514 54,979 45,018 Less – Accumulated depreciation and depletion (6,296 ) (4,726 ) Property, plant and equipment, net $ 48,683 $ 40,292
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2015 2014 2013 Depreciation and depletion expense $ 1,776 $ 1,457 $ 1,128 Capitalized interest, excluding AFUDC $ 163 $ 113 $ 43
Schedule of Goodwill	Changes in the carrying amount of goodwill were as follows: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2013 $ 5,856 $ — $ 184 $ (146 ) $ 5,894 Goodwill acquired 2,340 3,143 — (3,143 ) 2,340 Lake Charles LNG Transaction (1) (184 ) — — 184 — Goodwill impairment (370 ) — — — (370 ) Other — — — 1 1 Balance, December 31, 2014 7,642 3,143 184 (3,104 ) 7,865 Goodwill acquired — 31 — — 31 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (63 ) — (164 ) (218 ) Balance, December 31, 2015 $ 5,428 $ 3,111 $ 184 $ (1,250 ) $ 7,473
Components And Useful Lives Of Intangibles And Other Assets	Components and useful lives of intangible assets were as follows: December 31, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 5,254 $ (738 ) $ 5,144 $ (485 ) Trade names (15 years) 559 (25 ) 556 (15 ) Patents (9 years) 48 (16 ) 48 (11 ) Other (1 to 15 years) 15 (7 ) 36 (7 ) Total amortizable intangible assets 5,876 (786 ) 5,784 (518 ) Non-amortizable intangible assets: Trademarks 341 — 316 — Total intangible assets $ 6,217 $ (786 ) $ 6,100 $ (518 )
Aggregate Amortization Expense Of Intangibles And Other Assets	Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 303 $ 219 $ 120
Estimated Aggregate Amortization Expense	Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2016 $ 242 2017 242 2018 241 2019 239 2020 239
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, 2015 2014 Unamortized financing costs (1) $ 29 $ 41 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 221 209 Total other non-current assets, net $ 730 $ 732 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Schedule of Asset Retirement Obligations [Table Text Block]	December 31, 2015 2014 Investment in ETP: Interstate transportation and storage operations $ 58 $ 60 Investment in Sunoco Logistics 88 41 Retail marketing operations 66 87 $ 212 $ 188
Accrued and Other Current Liabilities	Accrued and other current liabilities consisted of the following: December 31, 2015 2014 Interest payable $ 519 $ 440 Customer advances and deposits 114 103 Accrued capital expenditures 743 673 Accrued wages and benefits 218 233 Taxes payable other than income taxes 76 236 Other 632 417 Total accrued and other current liabilities $ 2,302 $ 2,102
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, 2015 and 2014 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ — $ — $ — $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 16 16 — — Swing Swaps IFERC 10 2 8 — Fixed Swaps/Futures 274 274 — — Forward Physical Swaps 4 — 4 — Power: Forwards 22 — 22 — Futures 3 3 — — Options — Calls 1 1 — — Options — Puts 1 1 — — Natural Gas Liquids — Forwards/Swaps 99 99 — — Refined Products – Futures 15 15 — — Crude – Futures 9 9 — — Total commodity derivatives 454 420 34 — Total assets $ 454 $ 420 $ 34 $ — Liabilities: Interest rate derivatives $ (171 ) $ — $ (171 ) $ — Embedded derivatives in the ETP Preferred Units (5 ) — — (5 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (16 ) (16 ) — — Swing Swaps IFERC (12 ) (2 ) (10 ) — Fixed Swaps/Futures (203 ) (203 ) — — Power: Forwards (22 ) — (22 ) — Futures (2 ) (2 ) — — Options — Puts (1 ) (1 ) — — Natural Gas Liquids — Forwards/Swaps (89 ) (89 ) — — Refined Products – Futures (6 ) (6 ) — — Crude — Futures (5 ) (5 ) — — Total commodity derivatives (356 ) (324 ) (32 ) — Total liabilities $ (532 ) $ (324 ) $ (203 ) $ (5 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 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 ETP 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 )
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 ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units: Unobservable Input December 31, 2015 Embedded derivatives in the ETP Preferred Units Credit Spread 5.33 % Volatility 37.00 %
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, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 11 Balance, December 31, 2015 $ (5 )

Acquisitions and Related Tran27

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
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 Missouri Gas Energy and New England Gas Company’s sale dates in September 2013 and December 2013, respectively: Year Ended December 31, 2013 Revenue from discontinued operations $ 415 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65
Eagle Rock Midstream 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. 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. The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 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
PVR Acquisition [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	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. 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 (1) 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 ETP 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. The following table summarizes the 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 i28

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Current assets $ 632 $ 889 Property, plant and equipment, net 10,213 10,520 Other assets 2,649 2,687 Total assets $ 13,494 $ 14,096 Current liabilities $ 841 $ 1,983 Non-current liabilities 7,950 7,359 Equity 4,703 4,754 Total liabilities and equity $ 13,494 $ 14,096 Years Ended December 31, 2015 2014 2013 Revenue $ 4,026 $ 4,925 $ 4,695 Operating income 1,302 1,071 1,197 Net income 807 577 699 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. The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014 , were as follows: December 31, 2015 2014 Citrus $ 1,739 $ 1,823 AmeriGas 80 94 FEP 115 130 MEP 660 695 HPC 402 422 Others 466 495 Total $ 3,462 $ 3,659

Net Income Per Limited Partne29

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Income from continuing operations $ 1,093 $ 1,060 $ 282 Less: Income (loss) from continuing operations attributable to noncontrolling interest (96 ) 434 99 Income from continuing operations, net of noncontrolling interest 1,189 626 183 Less: General Partner’s interest in income from continuing operations 3 2 — Less: Class D Unitholder’s interest in income from continuing operations 3 2 — Income from continuing operations available to Limited Partners $ 1,183 $ 622 $ 183 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,062.8 1,088.6 1,121.8 Basic income from continuing operations per Limited Partner unit $ 1.11 $ 0.58 $ 0.17 Basic income from discontinued operations per Limited Partner unit $ — $ — $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 1,183 $ 622 $ 183 Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder (2 ) (2 ) — Diluted income from continuing operations available to Limited Partners 1,181 620 183 Weighted average limited partner units 1,062.8 1,088.6 1,121.8 Dilutive effect of unconverted unit awards 1.6 2.2 — Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,064.4 1,090.8 1,121.8 Diluted income from continuing operations per Limited Partner unit $ 1.11 $ 0.57 $ 0.17 Diluted income from discontinued operations per Limited Partner unit $ — $ — $ 0.01

Debt Obligations Debt Obligatio

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Obligations [Abstract]
Schedule of debt obligations	Our debt obligations consist of the following: December 31, 2015 2014 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 1,150 5.5% Senior Notes due June 1, 2027 1,000 — ETE Senior Secured Term Loan, due December 2, 2019 2,190 1,400 ETE Senior Secured Revolving Credit Facility due December 18, 2018 860 940 Unamortized premiums, discounts and fair value adjustments, net (17 ) 3 Deferred debt issuance costs (38 ) (34 ) 6,332 4,646 Subsidiary Indebtedness: ETP Debt 5.95% Senior Notes due February 1, 2015 — 750 6.125% Senior Notes due February 15, 2017 400 400 2.5% Senior Notes due June 15, 2018 650 — 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 5.75% Senior Notes due September 1, 2020 (assumed from Regency) 400 — 4.15% Senior Notes due October 1, 2020 1,050 700 6.5% Senior Notes due May 15, 2021 (assumed from Regency) 500 — 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 (assumed from Regency) 900 — 5.0% Senior Notes due October 1, 2022 (assumed from Regency) 700 — 3.60% Senior Notes due February 1, 2023 800 800 5.5% Senior Notes due April 15, 2023 (assumed from Regency) 700 — 4.5% Senior Notes due November 1, 2023 (assumed from Regency) 600 — 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 4.05% Senior Notes due March 15, 2025 1,000 — 4.75% Senior Notes due January 15, 2026 1,000 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 — 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 — 6.125% Senior Notes due December 15, 2045 1,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 545 546 ETP $3.75 billion Revolving Credit Facility due November 2019 1,362 570 Unamortized premiums, discounts and fair value adjustments, net (21 ) (1 ) Deferred debt issuance costs (147 ) (55 ) 20,633 11,404 Transwestern Debt 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 ) Deferred debt issuance costs (2 ) (3 ) 779 778 Panhandle Debt 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 75 99 1,160 1,184 Sunoco, Inc. Debt 9.625% Senior Notes due April 15, 2015 — 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 20 35 485 750 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 (1) 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.4% Senior Notes due April 1,2021 600 — 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 500 500 5.95% Senior Notes due December 1, 2025 400 — 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 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) — 35 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 562 150 Unamortized premiums, discounts and fair value adjustments, net 85 100 Deferred debt issuance costs (32 ) (26 ) 5,590 4,234 Sunoco LP Debt 5.5% Senior Notes Due August 1, 2020 600 — 6.375% Senior Notes due April 1, 2023 800 — Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 450 683 Deferred debt issuance costs (18 ) — 1,832 683 Regency Debt, net of deferred debt issuance costs of $58 million (3) — 6,583 Other 157 223 36,968 30,485 Less: current maturities 131 1,008 $ 36,837 $ 29,477
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 $96 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2016 $ 308 2017 1,189 2018 2,515 2019 5,007 2020 4,729 Thereafter 23,316 Total $ 37,064

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]	ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units: Total Year 2016 $ 137 2017 128 2018 105 2019 95
Change In ETE Common Units	The change in ETE Common Units during the years ended December 31, 2015 , 2014 and 2013 was as follows: Years Ended December 31, 2015 2014 2013 Number of Common Units, beginning of period 1,077.5 1,119.8 1,119.8 Conversion of Class D Units to ETE Common Units 0.9 — — Repurchase of common units under buyback program (33.6 ) (42.3 ) — Number of Common Units, end of period 1,044.8 1,077.5 1,119.8
Accumulated Other Comprehensive Income (Loss)	The following table presents the components of AOCI, net of tax: December 31, 2015 2014 Available-for-sale securities $ — $ 3 Foreign currency translation adjustment (4 ) (3 ) Net losses on commodity related hedges — (1 ) Actuarial gain (loss) related to pensions and other postretirement benefits 8 (57 ) Investments in unconsolidated affiliates, net — 2 Subtotal 4 (56 ) Amounts attributable to noncontrolling interest (4 ) 51 Total AOCI included in partners’ capital, net of tax $ — $ (5 )
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, 2015 2014 Available-for-sale securities $ (2 ) $ (1 ) Foreign currency translation adjustment 4 2 Actuarial (gain) loss relating to pension and other postretirement benefits 7 (37 ) Total $ 9 $ (36 )
Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared during the years ended December 31, 2015, 2014, and 2013 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 7, 2013 February 19, 2013 $ 0.1588 March 31, 2013 May 6, 2013 May 17, 2013 0.1613 June 30, 2013 August 5, 2013 August 19, 2013 0.1638 September 30, 2013 November 4, 2013 November 19, 2013 0.1681 December 31, 2013 February 7, 2014 February 19, 2014 0.1731 March 31, 2014 May 5, 2014 May 19, 2014 0.1794 June 30, 2014 August 4, 2014 August 19, 2014 0.1900 September 30, 2014 November 3, 2014 November 19, 2014 0.2075 December 31, 2014 February 6, 2015 February 19, 2015 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650 September 30, 2015 November 5, 2015 November 19, 2015 0.2850 December 31, 2015 February 4, 2016 February 19, 2016 0.2850
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 Rate December 31, 2012 February 7, 2013 February 14, 2013 $ 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550
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, 2015, 2014, and 2013 were as follows: Quarter Ended Record Date Payment Date Rate 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 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790
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 Rate September 30, 2014 November 18, 2014 November 28, 2014 $ 0.5457 December 31, 2014 February 17, 2015 February 27, 2015 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 September 30, 2015 November 17, 2015 November 27, 2015 0.7454 December 31, 2015 February 5, 2016 February 16, 2016 0.8013

Unit-Based Compensation Plans U

Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	The following table shows the activity of the ETP awards granted to employees and non-employee directors: Number of ETP Units Weighted Average Grant-Date Fair Value Per ETP Unit Unvested awards as of December 31, 2014 3.5 $ 53.83 Awards granted 2.1 35.21 Awards vested (1.2 ) 48.67 Awards forfeited (0.4 ) 55.44 Conversion of RGP unit awards to ETP unit awards 0.8 58.88 Unvested awards as of December 31, 2015 4.8 47.61

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Current expense (benefit): Federal $ (292 ) $ 321 $ 51 State (51 ) 86 (1 ) Total (343 ) 407 50 Deferred expense (benefit): Federal 272 (53 ) (14 ) State (29 ) 3 57 Total 243 (50 ) 43 Total income tax expense (benefit) from continuing operations $ (100 ) $ 357 $ 93
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, 2015 , 2014 and 2013 is as follows: December 31, 2015 December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Income tax expense (benefit) at U.S. statutory rate of 35 percent $ (19 ) $ (19 ) $ 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 — — Dividend received deduction (22 ) (22 ) — — — — Premium on debt retirement — — (10 ) (10 ) — — Audit settlement (7 ) (7 ) — — — — Foreign taxes — — (8 ) (8 ) — — State income taxes (net of federal income tax effects) (45 ) (26 ) 9 55 31 41 Other (26 ) (26 ) 3 3 (16 ) (17 ) Income tax expense (benefit) from continuing operations $ (119 ) $ (100 ) $ 311 $ 357 $ 84 $ 93 (1) Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. (2) Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries.
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, 2015 2014 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 217 $ 116 Pension and other postretirement benefits 36 47 Long term debt 61 53 Other 162 111 Total deferred income tax assets 476 327 Valuation allowance (121 ) (84 ) Net deferred income tax assets 355 243 Deferred income tax liabilities: Properties, plants and equipment (1,633 ) (1,583 ) Inventory — (153 ) Investments in unconsolidated affiliates (2,976 ) (2,530 ) Trademarks (286 ) (355 ) Other (50 ) (32 ) Total deferred income tax liabilities (4,945 ) (4,653 ) Accumulated deferred income taxes $ (4,590 ) $ (4,410 )
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2015 2014 2013 Balance at beginning of year $ 440 $ 429 $ 27 Additions attributable to tax positions taken in the current year 178 20 — Additions attributable to tax positions taken in prior years — (1 ) 406 Settlements — (5 ) — Lapse of statute (8 ) (3 ) (4 ) Balance at end of year $ 610 $ 440 $ 429
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, 2015 2014 Net deferred income tax liability, beginning of year $ (4,410 ) $ (3,984 ) Susser acquisition — (488 ) Tax provision (including discontinued operations) (242 ) 62 Other 62 — Net deferred income tax liability $ (4,590 ) $ (4,410 )

Regulatory Matters, Commitmen34

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Rental expense (1) $ 225 $ 159 $ 151 Less: Sublease rental income (16 ) (26 ) (24 ) Rental expense, net $ 209 $ 133 $ 127 (1) Includes contingent rentals totaling $26 million , $24 million and $22 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.
Environmental Exit Costs by Cost [Table Text Block]	December 31, 2015 2014 Current $ 42 $ 41 Non-current 326 360 Total environmental liabilities $ 368 $ 401
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum lease commitments for such leases are: Years Ending December 31: 2016 $ 121 2017 114 2018 103 2019 96 2020 97 Thereafter 602 Future minimum lease commitments 1,133 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 1,099

Derivative Assets And Liabili35

Derivative Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
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, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 3 $ (176 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 63 107 (47 ) (23 ) Broker cleared derivative contracts Other current assets 391 660 (309 ) (577 ) 454 770 (532 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (17 ) (19 ) 17 19 Payments on margin deposit Other current assets (309 ) (577 ) 309 577 Total net derivatives $ 128 $ 174 $ (206 ) $ (175 )
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (602,500 ) 2016 - 2017 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (31,240,000 ) 2016 - 2017 (13,907,500 ) 2015 - 2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 357,092 2016 - 2017 288,775 2015 Futures (109,791 ) 2016 (156,000 ) 2015 Options — Puts 260,534 2016 (72,000 ) 2015 Options — Calls 1,300,647 2016 198,556 2105 Crude (Bbls) – Futures (591,000 ) 2016 - 2017 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,522,500 ) 2016 - 2017 57,500 2015 Swing Swaps IFERC 71,340,000 2016 - 2017 46,150,000 2015 Fixed Swaps/Futures (14,380,000 ) 2016 - 2018 (34,304,000 ) 2015 - 2016 Forward Physical Contracts 21,922,484 2016 - 2017 (9,116,777 ) 2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (8,146,800 ) 2016 - 2018 (4,417,400 ) 2015 Refined Products (Bbls) – Futures (1,289,000 ) 2016 - 2017 13,745,755 2015 Corn (Bushels) – Futures 1,185,000 2016 — — Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item — Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Swaps Outstanding	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, 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 200 200 ETP July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 300 ETP July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 ETP July 2019 (4) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 300 ETP July 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — ETP June 2021 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 — ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (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 December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 38 $ 43 $ (3 ) $ — 38 43 (3 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 353 617 (306 ) (577 ) Commodity derivatives 63 107 (47 ) (23 ) Interest rate derivatives — 3 (171 ) (155 ) Embedded derivatives in ETP Preferred Units — — (5 ) (16 ) 416 727 (529 ) (771 ) Total derivatives $ 454 $ 770 $ (532 ) $ (771 )
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, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ (1 ) Total $ — $ — $ (1 )
Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (3 ) $ 4 Total $ — $ (3 ) $ 4 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2015 2014 2013 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ (8 ) $ 8 Total $ 21 $ (8 ) $ 8 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2015 2014 2013 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (11 ) $ (6 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 15 199 (21 ) Commodity contracts – Non-trading Deferred gas purchases — — (3 ) Interest rate derivatives Gains (losses) on interest rate derivatives (18 ) (157 ) 53 Embedded derivatives Other, net 12 3 6 Total $ (2 ) $ 39 $ 24

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
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: December 31, 2015 December 31, 2014 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 $ 718 $ 65 $ 203 $ 632 $ 61 $ 223 Interest cost 23 2 4 28 3 5 Amendments — — — — — 1 Benefits paid, net (46 ) (8 ) (20 ) (45 ) (9 ) (28 ) Actuarial (gain) loss and other 16 (2 ) (6 ) 130 10 2 Settlements (691 ) — — (27 ) — — Benefit obligation at end of period $ 20 $ 57 $ 181 $ 718 $ 65 $ 203 Change in plan assets: Fair value of plan assets at beginning of period $ 598 $ — $ 272 $ 600 $ — $ 284 Return on plan assets and other 16 — — 70 — 7 Employer contributions 138 — 9 — — 9 Benefits paid, net (46 ) — (20 ) (45 ) — (28 ) Settlements (691 ) — — (27 ) — — Fair value of plan assets at end of period $ 15 $ — $ 261 $ 598 $ — $ 272 Amount underfunded (overfunded) at end of period $ 5 $ 57 $ (80 ) $ 120 $ 65 $ (69 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 103 $ — $ — $ 96 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (5 ) (48 ) (22 ) (120 ) (56 ) (25 ) $ (5 ) $ (57 ) $ 79 $ (120 ) $ (65 ) $ 69 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ 2 $ 4 $ (18 ) $ 18 $ 7 $ (21 ) Prior service cost — — 16 — — 18 $ 2 $ 4 $ (2 ) $ 18 $ 7 $ (3 )
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 20 $ 57 N/A $ 718 $ 65 N/A Accumulated benefit obligation 20 57 $ 181 718 65 $ 203 Fair value of plan assets 15 — 261 598 — 272
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, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.59 % 2.38 % 3.62 % 2.24 % 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, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.79 % 4.65 % 3.02 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % 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, 2015 2014 Health care cost trend rate 7.16 % 7.09 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.39 % 5.41 % 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, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 15 $ — $ 15 $ — Total $ 15 $ — $ 15 $ — (1) Comprised of 100% equities as of December 31, 2015 . 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 . 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, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset Category: Cash and Cash Equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 141 141 — — Fixed income securities 102 — 102 — Total $ 261 $ 159 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . 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 and 6% cash as of December 31, 2014 . 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.
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) 2016 $ 20 $ 9 $ 21 2017 — 7 20 2018 — 7 19 2019 — 6 17 2020 — 6 16 2021 – 2025 — 2 58
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net Periodic Benefit Cost: Interest cost $ 25 $ 4 $ 31 $ 5 Expected return on plan assets (16 ) (8 ) (40 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — (1 ) (1 ) Settlements 32 — (4 ) — Net periodic benefit cost $ 41 $ (3 ) $ (14 ) $ (3 )

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Financial Information By Segment	Years Ended December 31, 2015 2014 2013 Revenues: Investment in ETP: Revenues from external customers $ 34,156 $ 55,475 $ 48,335 Intersegment revenues 136 — — 34,292 55,475 48,335 Investment in Sunoco LP: Revenues from external customers 18,449 7,343 — Intersegment revenues 11 — — 18,460 7,343 — Investment in Lake Charles LNG: Revenues from external customers 216 216 216 Adjustments and Eliminations: (10,842 ) (7,343 ) (216 ) Total revenues $ 42,126 $ 55,691 $ 48,335 Costs of products sold: Investment in ETP $ 27,029 $ 48,414 $ 42,580 Investment in Sunoco LP 16,476 6,767 — Adjustments and Eliminations (9,496 ) (6,767 ) — Total costs of products sold $ 34,009 $ 48,414 $ 42,580 Depreciation, depletion and amortization: Investment in ETP $ 1,929 $ 1,669 $ 1,296 Investment in Sunoco LP 278 86 — Investment in Lake Charles LNG 39 39 39 Corporate and Other 17 16 16 Adjustments and Eliminations (184 ) (86 ) (38 ) Total depreciation, depletion and amortization $ 2,079 $ 1,724 $ 1,313 Years Ended December 31, 2015 2014 2013 Equity in earnings of unconsolidated affiliates: Investment in ETP $ 469 $ 332 $ 236 Adjustments and Eliminations (193 ) — — Total equity in earnings of unconsolidated affiliates $ 276 $ 332 $ 236 Years Ended December 31, 2015 2014 2013 Segment Adjusted EBITDA: Investment in ETP $ 5,714 $ 5,710 $ 4,404 Investment in Sunoco LP 719 332 — Investment in Lake Charles LNG 196 195 187 Corporate and Other (104 ) (97 ) (43 ) Adjustments and Eliminations (590 ) (300 ) (181 ) Total Segment Adjusted EBITDA 5,935 5,840 4,367 Depreciation, depletion and amortization (2,079 ) (1,724 ) (1,313 ) Interest expense, net of interest capitalized (1,643 ) (1,369 ) (1,221 ) Gain on sale of AmeriGas common units — 177 87 Impairment losses (339 ) (370 ) (689 ) Gains (losses) on interest rate derivatives (18 ) (157 ) 53 Non-cash unit-based compensation expense (91 ) (82 ) (61 ) Unrealized gains (losses) on commodity risk management activities (65 ) 116 48 Losses on extinguishments of debt (43 ) (25 ) (162 ) Inventory valuation adjustments (249 ) (473 ) 3 Adjusted EBITDA related to discontinued operations — (27 ) (76 ) Adjusted EBITDA related to unconsolidated affiliates (713 ) (748 ) (727 ) Equity in earnings of unconsolidated affiliates 276 332 236 Non-operating environmental remediation — — (168 ) Other, net 22 (73 ) (2 ) Income from continuing operations before income tax expense $ 993 $ 1,417 $ 375 December 31, 2015 2014 2013 Total assets: Investment in ETP $ 65,173 $ 62,518 $ 49,900 Investment in Sunoco LP 8,842 8,773 — Investment in Lake Charles LNG 1,369 1,210 1,338 Corporate and Other 638 1,119 720 Adjustments and Eliminations (4,833 ) (9,341 ) (1,628 ) Total $ 71,189 $ 64,279 $ 50,330 Years Ended December 31, 2015 2014 2013 Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): Investment in ETP $ 8,167 $ 5,494 $ 3,327 Investment in Sunoco LP 491 154 — Investment in Lake Charles LNG 1 1 2 Adjustments and Eliminations (123 ) (90 ) 13 Total $ 8,536 $ 5,559 $ 3,342 December 31, 2015 2014 2013 Advances to and investments in affiliates: Investment in ETP $ 5,003 $ 3,760 $ 4,050 Adjustments and Eliminations (1,541 ) (101 ) (36 ) Total $ 3,462 $ 3,659 $ 4,014 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 Sunoco LP. Investment in ETP Years Ended December 31, 2015 2014 2013 Intrastate Transportation and Storage $ 1,912 $ 2,645 $ 2,242 Interstate Transportation and Storage 1,008 1,057 1,270 Midstream 2,622 4,770 3,220 Liquids Transportation and Services 3,232 3,730 2,025 Investment in Sunoco Logistics 10,302 17,920 16,480 Retail Marketing 12,478 22,484 21,004 All Other 2,738 2,869 2,094 Total revenues 34,292 55,475 48,335 Less: Intersegment revenues 136 — — Revenues from external customers $ 34,156 $ 55,475 $ 48,335 Investment in Sunoco LP Years Ended December 31, 2015 2014 2013 Retail operations $ 8,257 $ 3,095 $ — Wholesale operations 10,203 4,248 — Total revenues 18,460 7,343 — Less: Intersegment revenues 11 — — Revenues from external customers $ 18,449 $ 7,343 $ — Investment in Lake Charles LNG Lake Charles LNG’s revenues of $216 million , $216 million and $216 million for the years ended December 31, 2015, 2014 and 2013, respectively, were related to LNG terminalling.

Quarterly Financial Data (Una38

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 10,380 $ 11,594 $ 10,616 $ 9,536 $ 42,126 Operating income 617 896 650 236 2,399 Net income (loss) 221 772 238 (138 ) 1,093 Limited Partners’ interest in net income 282 298 291 312 1,183 Basic net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Diluted net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,080 $ 14,143 $ 14,987 $ 13,481 $ 55,691 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 $ 0.15 $ 0.15 $ 0.18 $ 0.11 $ 0.58 Diluted net income per limited partner unit $ 0.15 $ 0.15 $ 0.18 $ 0.11 $ 0.57 The three months ended December 31, 2015 and 2014 reflected the unfavorable impacts of $171 million and $456 million , respectively, related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2015 and 2014 reflected the recognition of impairment losses of $339 million and $370 million , respectively. Impairment losses in 2015 were primarily related to ETP’s Lone Star Refinery Services operations and ETP’s Transwestern pipeline, and in 2014 , impairment losses were primarily related to Regency’s Permian Basin gathering and processing operations.

Supplemental Financial Statem39

Supplemental Financial Statement Information (Tables) - Parent Company [Member]	12 Months Ended
	Dec. 31, 2015
Schedule Of Balance Sheets	BALANCE SHEETS December 31, 2015 2014 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 1 $ 2 Accounts receivable from related companies 34 14 Other current assets — 1 Total current assets 35 17 PROPERTY, PLANT AND EQUIPMENT, net 20 — ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 5,764 5,390 INTANGIBLE ASSETS, net 6 10 GOODWILL 9 9 OTHER NON-CURRENT ASSETS, net 10 12 Total assets $ 5,844 $ 5,438 LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES: Accounts payable to related companies $ 111 $ 11 Interest payable 66 58 Accrued and other current liabilities 1 3 Total current liabilities 178 72 LONG-TERM DEBT, less current maturities 6,332 4,646 NOTE PAYABLE TO AFFILIATE 265 54 OTHER NON-CURRENT LIABILITIES 1 2 COMMITMENTS AND CONTINGENCIES PARTNERS’ CAPITAL: General Partner (2 ) (1 ) Limited Partners: Limited Partners – Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding at December 31, 2015 and 2014, respectively) (952 ) 648 Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) 22 22 Accumulated other comprehensive income (loss) — (5 ) Total partners’ capital (932 ) 664 Total liabilities and partners’ capital $ 5,844 $ 5,438
Schedule Of Statements Of Operations	STATEMENTS OF OPERATIONS Years Ended December 31, 2015 2014 2013 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (112 ) $ (111 ) $ (56 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (294 ) (205 ) (210 ) Equity in earnings of unconsolidated affiliates 1,601 955 617 Gains on interest rate derivatives — — 9 Loss on extinguishment of debt — — (157 ) Other, net (5 ) (5 ) (8 ) INCOME BEFORE INCOME TAXES 1,190 634 195 Income tax expense (benefit) 1 1 (1 ) NET INCOME 1,189 633 196 GENERAL PARTNER’S INTEREST IN NET INCOME 3 2 — CLASS D UNITHOLDER’S INTEREST IN NET INCOME 3 2 — LIMITED PARTNERS’ INTEREST IN NET INCOME $ 1,183 $ 629 $ 196
Schedule Of Statements Of Cash Flows	STATEMENTS OF CASH FLOWS Years Ended December 31, 2015 2014 2013 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 1,103 $ 816 $ 768 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction (817 ) — — Proceeds from ETP Holdco Transaction — — 1,332 Contributions to unconsolidated affiliates — (118 ) (8 ) Capital expenditures (19 ) — — Purchase of additional interest in Regency — (800 ) — Payments received on note receivable from affiliate — — 166 Net cash provided by (used in) investing activities (836 ) (918 ) 1,490 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 3,672 3,020 2,080 Principal payments on debt (1,985 ) (1,142 ) (3,235 ) Distributions to partners (1,090 ) (821 ) (733 ) Proceeds from affiliate 210 54 — Redemption of Preferred Units — — (340 ) Units repurchased under buyback program (1,064 ) (1,000 ) — Debt issuance costs (11 ) (15 ) (31 ) Net cash provided by (used in) financing activities (268 ) 96 (2,259 ) DECREASE IN CASH AND CASH EQUIVALENTS (1 ) (6 ) (1 ) CASH AND CASH EQUIVALENTS, beginning of period 2 8 9 CASH AND CASH EQUIVALENTS, end of period $ 1 $ 2 $ 8

Operations And Organization (Na

Operations And Organization (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended	12 Months Ended
	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Mar. 31, 2016	Dec. 31, 2015
LNG Storage Capacity					9
Payments to Acquire Businesses, Gross	$ 382
Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.					100
Citrus [Member]
Interest ownership					50.00%
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.					2,600,000
Sunoco Logistics [Member]
General Partner Interest					0.10%
Sunoco Logistics [Member] | ETP [Member]
Incentive Distribution Rights					99.90%
Dropdown of Sunoco LLC Interest [Member]
Payments to Acquire Businesses, Gross			$ 775
Dropdown of Sunoco LLC Interest [Member] | Sunoco LP [Member]
Payments to Acquire Businesses, Gross				$ 2,200
Sale of Stock, Number of Shares Issued in Transaction				5,700,000
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				68.42%
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				100.00%
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares		21,000,000
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share			0.4124
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			172,200,000
Relinquishment of Incentive Distributions					$ 320
Relinquishment, Year 1 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions					80
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions					$ 60
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.					81,000,000
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			15,500,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			1,900,000

Estimates, Significant Accoun41

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 29, 2014	Mar. 21, 2014
Inventory Write-down		$ 249
Tangible Asset Impairment Charges		110
ARO Underlying Asset		18
Impairment of Intangible Assets, Finite-lived		24
Asset Retirement Obligation, Legally Restricted Assets, Fair Value		6
Deferred Tax Liabilities, Gross		4,945	$ 4,653
Long-term Debt, Fair Value		33,220	31,680
Goodwill, Period Increase (Decrease)		(392)
Impairment losses		205	370
Goodwill acquired		31	2,340
Goodwill		7,473	7,865	$ 5,894
Long-term Debt		36,968	30,485
Investment In ETP [Member]
Impairment losses		205	370
Goodwill acquired		0	2,340
Goodwill		5,428	7,642	5,856
Liquids Transportation And Services [Member]
Impairment losses		(106)
Interstate Transportation and Storage [Member]
Impairment losses		(99)
Retail Marketing [Member]
Excise Taxes Collected		$ 3,050	2,460	$ 2,220
Amount Reclassed From ASU 2015-17 [Member]
Deferred Tax Liabilities, Gross			$ 85
Susser Merger [Member]
Goodwill					$ 1,734
PVR Acquisition [Member]
Goodwill	[1]					$ 370
[1]	(1)None of the goodwill is expected to be deductible for tax purposes.

Estimates (Schedule Of Net Chan

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Accounts receivable	$ 856	$ 600	$ (556)
Accounts receivable from related companies	(5)	30	64
Inventories	(430)	51	(254)
Exchanges receivable	14	18	(8)
Other current assets	239	(133)	81
Other non-current assets, net	250	(6)	(23)
Accounts payable	(1,127)	(850)	541
Accounts payable to related companies	400	5	(140)
Exchanges payable	(79)	(99)	128
Accrued and other current liabilities	(618)	(59)	192
Other non-current liabilities	(261)	(73)	147
Derivative assets and liabilities, net	75	19	(159)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (1,164)	$ (231)	$ (149)

Estimates (Schedule Of Non-Cash

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 910	$ 643	$ 226
Net gains (losses) from subsidiary common unit transactions	(526)	744	(384)
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	34	0	0
Long term debt exchanged in connection with acquisitions	0	499	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,800	1,416	1,256
Cash paid for income taxes	72	345	58
Subsidiary units issued in PVR, Hoover and Eagle Rock Midstream Acquisitions [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	4,281	0
Subsidiary units issued in Susser Merger [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	908	0
PVR Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$ 0	$ 1,887	$ 0

Estimates (Schedule of Inventor

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Unamortized financing costs(1)	[1]	$ 29	$ 41
Inventory, Net [Abstract]
Natural gas and NGLs		415	392
Crude oil		424	364
Refined products		420	392
Spare parts and other		377	319
Total inventories		$ 1,636	$ 1,467
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Estimates (Other Current Assets

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Information [Abstract]
Deposits paid to vendors	$ 74	$ 65
Income taxes receivable	326	17
Prepaid expenses and other	172	205
Total other current assets	$ 572	$ 287

Estimates (Property, Plant and

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 54,979	$ 45,018
Less - Accumulated depreciation	(6,296)	(4,726)
Property, Plant and Equipment, Net	48,683	40,292
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	686	1,307
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,526	1,922
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	32,677	27,149
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	390	1,214
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,853	4,010
Tanks and other equipment (5 to 40 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,488	58
Retail equipment (2 to 99 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	401	515
Vehicles [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	220	203
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,573	2,451
Furniture and fixtures (2 to 25 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	57	59
Linepack [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	61	119
Pad gas [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	44	44
Natural Resources [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	484	454
Other (1 to 30 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,675	999
Construction work-in-process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 7,844	$ 4,514

Estimates (Schedule Of Property

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Depreciation and depletion expense	$ 1,776	$ 1,457	$ 1,128
Capitalized interest, excluding AFUDC	$ 163	$ 113	$ 43

Estimates, Significant Accoun48

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2015
Minimum [Member] | Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Minimum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	2 years
Minimum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	5 years
Minimum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment, useful life, minimum (years)	2 years
Minimum [Member] | Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Minimum [Member] | Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	20 years
Minimum [Member] | Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] | Other (1 to 15 years)
Intangible assets, useful life, minimum (years)	1 year
Maximum [Member] | Buildings and improvements [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Maximum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment, useful life, minimum (years)	46 years
Maximum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment, useful life, minimum (years)	40 years
Maximum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment, useful life, minimum (years)	99 years
Maximum [Member] | Vehicles [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Maximum [Member] | Right of way (20 to 83 years)
Property, plant and equipment, useful life, minimum (years)	83 years
Maximum [Member] | Furniture and Fixtures [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, plant and equipment, useful life, minimum (years)	30 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] | Trade names (15 years)
Intangible assets, useful life, minimum (years)	15 years
Maximum [Member] | Patents (9 years)
Intangible assets, useful life, minimum (years)	9 years
Maximum [Member] | Other (1 to 15 years)
Intangible assets, useful life, minimum (years)	15 years

Estimates (Schedule of Other No

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Unamortized financing costs(1)	[1]	$ 29	$ 41
Regulatory assets		90	85
Deferred charges		198	220
Restricted funds		192	177
Other		221	209
Total other non-current assets, net		$ 730	$ 732
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Estimates (Components Of Intang

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Gross Carrying Amount	$ 6,217	$ 6,100
Accumulated Amortization	786	518
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	5,254	5,144
Accumulated Amortization	738	485
Trade names (15 years)
Gross Carrying Amount	48	48
Accumulated Amortization	16	11
Patents (9 years)
Gross Carrying Amount	559	556
Accumulated Amortization	25	15
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	5,876	5,784
Accumulated Amortization	786	518
Trademarks [Member]
Gross Carrying Amount	341	316
Accumulated Amortization	0	0
Other Amortizable Intangible Assets [Member]
Gross Carrying Amount	15	36
Accumulated Amortization	$ 7	$ 7

Estimates (Aggregate Amortizati

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 303	$ 219	$ 120

Estimates (Estimated Aggregate

Estimates (Estimated Aggregate Amortization Expense) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
2,016	$ 242
2,017	242
2,018	241
2,019	239
2,020	239
Gross Carrying Amount	$ 6,217	$ 6,100

Estimates (Schedule Of Goodwill

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill	$ 7,865	$ 5,894
Goodwill acquired	31	2,340
Goodwill	7,473	7,865
Goodwill impairment	(205)	(370)
Goodwill, Other Changes	(218)	1
Goodwill, Written off Related to Sale of Business Unit	0	0
Investment In ETP [Member]
Goodwill [Roll Forward]
Goodwill	7,642	5,856
Goodwill acquired	0	2,340
Goodwill	5,428	7,642
Goodwill impairment	(205)	(370)
Goodwill, Other Changes	9	0
Goodwill, Written off Related to Sale of Business Unit	(2,018)	(184)
Investment In Sunoco LP [Member]
Goodwill [Roll Forward]
Goodwill	3,143	0
Goodwill acquired	31	3,143
Goodwill	3,111	3,143
Goodwill impairment	0	0
Goodwill, Other Changes	(63)	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Investment in Lake Charles LNG [Member]
Goodwill [Roll Forward]
Goodwill	184	184
Goodwill acquired	0	0
Goodwill	184	184
Goodwill impairment	0	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Corporate, Other and Eliminations [Member]
Goodwill [Roll Forward]
Goodwill	(3,104)	(146)
Goodwill acquired	0	(3,143)
Goodwill	(1,250)	(3,104)
Goodwill impairment	0	0
Goodwill, Other Changes	(164)	1
Goodwill, Written off Related to Sale of Business Unit	$ 2,018	$ 184

Estimates, Significant Accoun54

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Asset Retirement Obligations) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation	$ 212	$ 188
Interstate Transportation and Storage [Member]
Asset Retirement Obligation	58	60
Retail Marketing [Member]
Asset Retirement Obligation	66	87
Sunoco Logistics [Member]
Asset Retirement Obligation	$ 88	$ 41

Estimates (Accrued And Other Cu

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Other Information [Abstract]
Unamortized financing costs(1)	[1]	$ 29	$ 41
Interest payable		519	440
Customer advances and deposits		114	103
Accrued capital expenditures		743	673
Accrued wages and benefits		218	233
Taxes payable other than income taxes		76	236
Other		632	417
Accrued and other current liabilities		$ 2,302	$ 2,102
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Estimates (Fair Value Of Financ

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Total liabilities	$ (532)
Level 1 [Member]
Total liabilities	(324)
Level 2 [Member]
Total liabilities	(203)
Level 3 [Member]
Total liabilities	(5)
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives	0	$ 3
Commodity derivatives:	454	745
Total assets	454	748
Interest rate derivatives	(171)	(155)
Embedded derivatives in the ETP Preferred Units	(5)	(16)
Commodity derivatives:	(356)	(578)
Total liabilities		(749)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Interest rate derivatives	0	0
Commodity derivatives:	420	632
Total assets	420	632
Interest rate derivatives	0	0
Embedded derivatives in the ETP Preferred Units	0	0
Commodity derivatives:	(324)	(551)
Total liabilities		(551)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Interest rate derivatives	0	3
Commodity derivatives:	34	113
Total assets	34	116
Interest rate derivatives	(171)	(155)
Embedded derivatives in the ETP Preferred Units	0	0
Commodity derivatives:	(32)	(27)
Total liabilities		(182)
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 ETP Preferred Units	(5)	(16)
Commodity derivatives:	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		16
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] | Options - Calls [Member]
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Options - Puts [Member]
Commodity derivatives:	1
Commodity derivatives:	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Commodity derivatives:	22	3
Commodity derivatives:	22	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:	3	4
Commodity derivatives:	2	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Calls [Member]
Commodity derivatives:	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Puts [Member]
Commodity derivatives:	1
Commodity derivatives:	(1)
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:	3	4
Commodity derivatives:	2	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Calls [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Puts [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	22	3
Commodity derivatives:	22	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Options - Calls [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Options - Puts [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	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Commodity derivatives:		21
Commodity derivatives:	5	(7)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Commodity derivatives:	15
Commodity derivatives:	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:		21
Commodity derivatives:	5	(7)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	15
Commodity derivatives:	(6)
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
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
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Commodity derivatives:	9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [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:	16	19
Commodity derivatives:	(16)	(18)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	10	26
Commodity derivatives:	(12)	(25)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	274	566
Commodity derivatives:	(203)	(490)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	4	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	16	19
Commodity derivatives:	(16)	(18)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	2	1
Commodity derivatives:	(2)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	274	541
Commodity derivatives:	(203)	(490)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0	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:	8	25
Commodity derivatives:	(10)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	25
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	4	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	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Commodity derivatives:	99	69
Commodity derivatives:	(89)	(32)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	99	46
Commodity derivatives:	(89)	(32)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	23
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	$ 0

Estimates, Significant Accoun57

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Fair Value Schedule of Unobservable Inputs) (Details)	Dec. 31, 2015
Unobservable Inputs [Abstract]
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	5.33%
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	37.00%

Estimates (Reconciliation For L

Estimates (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net unrealized gains included in other income (expense)	$ 11
Liabilities, Fair Value Disclosure, Recurring	532
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liabilities, Fair Value Disclosure, Recurring		$ 749
Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liabilities, Fair Value Disclosure, Recurring	$ 5
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		$ 16

Acquisitions and Related Tran59

Acquisitions and Related Transactions Acquisitions (Pending Transactions) (Details) - USD ($)	1 Months Ended		3 Months Ended	12 Months Ended
	Oct. 31, 2015	Apr. 30, 2015	Mar. 31, 2016	Dec. 31, 2015
Limited Partner interest in the Partnership, percentage				99.53%
Payments to Acquire Businesses, Gross	$ 382,000,000
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Consideration Transferred		$ 816,000,000
Payments to Acquire Businesses, Gross		$ 775,000,000
Equity and Cash Option [Member] | Proposed WMB Merger [Member]
Proposed Business Combination, Cash Consideration, Per Share				$ 8
Business Acquisition, Number Of Share Received In Exchange Of Each Share				1.5274
Equity Option [Member] | Proposed WMB Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share				1.8716
Cash Option [Member] | Proposed WMB Merger [Member]
Proposed Business Combination, Cash Consideration				$ 43.50
WPZ [Member]
Limited Partner interest in the Partnership, percentage				60.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				2.00%
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			68.42%
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Sunoco LP [Member] | Dropdown of Sunoco LLC Interest [Member]
Business Combination, Consideration Transferred			$ 2,230,000,000
Payments to Acquire Businesses, Gross			$ 2,200,000,000
Sale of Stock, Number of Shares Issued in Transaction			5,700,000

Acquisitions and Related Tran60

Acquisitions and Related Transactions Acquisitions (2015 Narrative) (Details) $ in Millions, gallons in Billions	1 Months Ended				3 Months Ended		12 Months Ended
	Oct. 31, 2015USD ($)shares	Jul. 31, 2015USD ($)shares	Apr. 30, 2015USD ($)gallonsshares	Mar. 31, 2015USD ($)shares	Mar. 31, 2016USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Payments to Acquire Businesses, Gross	$ 382
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage			31.58%
Business Combination, Consideration Transferred			$ 816
Gallons of motor fuel distributed | gallons			5.3
Payments to Acquire Businesses, Gross			$ 775
Equity Issued in Business Combination, Fair Value Disclosure			$ 41
Dropdown of Susser [Member]
Payments to Acquire Businesses, Gross		$ 970
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		$ 970
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares | shares		21,000,000
IDR Subsidies		$ 35
Term of IDR Subsidy		10 years
Bakken Pipeline Transaction [Member]
Class I Distributions							$ 30	$ 55
Business Combination, Consideration Transferred				$ 879
Partners' Capital Account, Units, Redeemed | shares				30,800,000
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share | shares			0.4124
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			172,200,000
Relinquishment of Incentive Distributions								$ 320
Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
Susser [Member] | Dropdown of Susser [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Sunoco LP [Member]
Partners' Capital Account, Sale of Units						$ 405
Sunoco LP [Member] | Dropdown of Sunoco LLC Interest [Member]
Business Combination, Consideration Transferred					$ 2,230
Payments to Acquire Businesses, Gross					$ 2,200
Sale of Stock, Number of Shares Issued in Transaction | shares					5,700,000
Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares		22,000,000
Sunoco GP [Member] | Sunoco LP Exchange [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Parent Company [Member] | Bakken Pipeline Transaction [Member]
Percent of total equity ownership of a subsidiary				45.00%
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	40.00%
Class I Units [Member] | Bakken Pipeline Transaction [Member]
Partners' Capital Account, Units | shares				100
Class B Units [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	9,400,000
Class A Units [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares		79,308
Class H Units [Member]
Partners' Capital Account, Units | shares				50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent								50.05%
Class H Units [Member] | Bakken Pipeline Transaction [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent				90.05%
Partners' Capital Account, Units, Redeemed | shares				30,800,000
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares		10,900,000
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions								$ 60
Relinquishment, Year 1 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions								$ 80
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			15,500,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			1,900,000

Acquisitions and Related Tran61

Acquisitions and Related Transactions Acquisitions (2014 Narrative) (Details) $ / shares in Units, $ in Millions	1 Months Ended							3 Months Ended								6 Months Ended	12 Months Ended
	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)shares	Oct. 31, 2014USD ($)shares	Aug. 31, 2014USD ($)shares	Jul. 31, 2014USD ($)	Mar. 21, 2014USD ($)$ / sharesshares	Feb. 28, 2014shares	Dec. 31, 2015USD ($)shares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)shares	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2014USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 01, 2014	Aug. 29, 2014	Jul. 01, 2014USD ($)	Jan. 10, 2014USD ($)shares
Guarantor Obligations, Current Carrying Value																							$ 600
Related Party Transaction, Amounts of Transaction																	$ 75
Payments to Acquire Businesses, Gross	$ 382
Revenues								$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080		42,126	$ 55,691	$ 48,335
Net income								$ (138)	$ 238	$ 772	$ 221	(294)	$ 470	$ 500	$ 448		$ 1,093	1,124	$ 315
Debt Instrument, Interest Rate, Stated Percentage								4.50%									4.50%
Number of Regency Common Units to be Issued in Acquisition Per Share | shares						1.02
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 | shares			4,000,000	11,000,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed | shares							18,700,000
Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares		172,200,000
Susser Merger [Member]
Business Combination, Consideration Transferred				$ 875
Payments to Acquire Businesses, Gross				$ 1,800
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares				15,800,000
Number of Stores																					630
Dealer-operated [Member] | MACS Transaction [Member]
Number of Stores																				200
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
Sunoco LP [Member]
Proceeds from Issuance of Common Stock																	$ 213
Partners' Capital Account, Sale of Units												$ 405
Partners' Capital Account, Units, Sale of Units | shares												9,100,000					5,500,000
Regency [Member]
Senior Notes		$ 5,100
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares								100									100
Regency [Member] | PVR Acquisition [Member]
Business Combination, Consideration Transferred						$ 5,700
Payments to Acquire Businesses, Gross						$ 36
Business Acquisition, Share Price | $ / shares						$ 27.82
Proceeds from divestiture of business						$ 1,800
Regency [Member] | Eagle Rock Midstream Acquisition [Member]
Proceeds from Issuance of Common Stock																$ 400
Stock Issued During Period, Shares, Acquisitions | shares																8,200,000
Business Combination, Consideration Transferred					$ 1,300
ETP [Member]
Incentive Distribution Rights								100.00%									100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares								2,600,000									2,600,000
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
Debt Instrument, Interest Rate, Stated Percentage																						8.38%
Panhandle [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares																							31,400,000
Panhandle [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares																							2,200,000
Class F Units [Member] | Panhandle [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares																							6,300,000

Acquisitions and Related Tran62

Acquisitions and Related Transactions Acquisitions (2013 Narrative) (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended					12 Months Ended
	Jul. 31, 2014	Mar. 21, 2014	Dec. 31, 2013	Sep. 30, 2013	Apr. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Proceeds from the sale of other assets						$ 26	$ 62	$ 89
SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred					$ 463
Cash Acquired from Acquisition					$ 30
Regency [Member] | PVR Acquisition [Member]
Business Acquisition [Line Items]
Proceeds from divestiture of business		$ 1,800
Business Combination, Consideration Transferred		$ 5,700
Regency [Member] | Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,300
Regency [Member] | Common Units [Member] | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					31.4
Regency [Member] | Class F Units [Member] | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					6.3
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 (Schedule Of Asset

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions		Aug. 29, 2014	Jul. 01, 2014	Mar. 21, 2014
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Current assets			$ 120
Property, plant and equipment			1,295
Goodwill			49
Other assets			4
Current liabilities			116
Long-term debt obligations, less current maturities			499
Other non-current liabilities			12
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Total assets acquired			1,468
Total liabilities assumed			627
Total consideration			$ 841
PVR Acquisition [Member]
Business Acquisition [Line Items]
Current assets				$ 149
Property, plant and equipment				2,716
Goodwill	[1]			370
Intangible assets				2,717
Investments in unconsolidated affiliates				62
Other assets				18
Total assets acquired				6,032
Current liabilities				168
Long-term debt obligations, less current maturities				1,788
Premium related to senior notes				99
Other non-current liabilities				30
Total liabilities assumed				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
Total assets acquired		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
Total liabilities assumed		2,094
Total consideration		1,783
Cash received		67
Total consideration, net of cash received		$ 1,716
[1]	(1)None of the goodwill is expected to be deductible for tax purposes.

Acquisitions and Related Tran64

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

Advances to and Investments i65

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) shares in Millions, $ in Millions	Jan. 12, 2012	Oct. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Payments to Acquire Businesses, Gross		$ 382
Proceeds from the sale of other assets			$ 26	$ 62	$ 89
AmeriGas common units sold by ETP			(18.9)	(7.5)
Cash proceeds from the sale of AmeriGas common units			$ 0	$ (814)	(346)
Advances to and investments in unconsolidated affiliates			3,462	3,659	4,014
Goodwill			7,473	7,865	5,894
Equity in earnings from unconsolidated affiliates			$ 276	332	$ 236
Citrus [Member]
Interest ownership			50.00%
Business Acquisition, Percentage of Voting Interests Acquired			50.00%
Advances to and investments in unconsolidated affiliates			$ 2,000
Goodwill			$ 1,030
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	29.6
Cash proceeds from the sale of AmeriGas common units			$ 814	$ 346
Investment Owned, Balance, Shares			3.1

Advances to and Investments i66

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Advances to and investments in unconsolidated affiliates	$ 3,462	$ 3,659	$ 4,014
RIGS Haynesville Partnership Co. [Member]
Advances to and investments in unconsolidated affiliates	402	422
Other Affiliates [Member]
Advances to and investments in unconsolidated affiliates	466	495
Citrus [Member]
Advances to and investments in unconsolidated affiliates	1,739	1,823
AmeriGas [Member]
Advances to and investments in unconsolidated affiliates	80	94
FEP [Member]
Advances to and investments in unconsolidated affiliates	115	130
MEP [Member]
Advances to and investments in unconsolidated affiliates	$ 660	$ 695

Investments in Affiliates (Summ

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Investment In Affiliates [Abstract]
Current assets	$ 632	$ 889
Property, plant and equipment, net	10,213	10,520
Other assets	2,649	2,687
Total assets	13,494	14,096
Current Liabilities	841	1,983
Non-current liabilities	7,950	7,359
Equity	4,703	4,754
Total liabilities and equity	$ 13,494	$ 14,096

Investments in Affiliates (Su68

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investment In Affiliates [Abstract]
Revenues	$ 4,026	$ 4,925	$ 4,695
Operating Income	1,302	1,071	1,197
Net income	$ 807	$ 577	$ 699

Net Income Per Limited Partne69

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Income from continuing operations	$ 1,093	$ 1,060	$ 282
Less: Income (loss) from continuing operations attributable to noncontrolling interest	(96)	434	99
Income from continuing operations, net of noncontrolling interest	1,189	626	183
Less: General Partner’s interest in income from continuing operations	3	2	0
Less: Class D Unitholder’s interest in income from continuing operations	3	2	0
Income from continuing operations available to Limited Partners	1,183	622	183
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(2)	(2)	0
Diluted income from continuing operations available to Limited Partners	$ 1,181	$ 620	$ 183
Weighted average limited partner units	1,062.8	1,088.6	1,121.8
Basic income from continuing operations per Limited Partner unit	$ 1.11	$ 0.58	$ 0.17
Basic income from discontinued operations per Limited Partner unit	$ 0	$ 0	$ 0.01
Dilutive effect of unconverted unit awards	1.6	2.2	0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,064.4	1,090.8	1,121.8
Diluted income from continuing operations per Limited Partner Unit	$ 1.11	$ 0.57	$ 0.17
Diluted income from discontinued operations per Limited Partner unit	$ 0	$ 0	$ 0.01

Debt Obligations Debt Obligat70

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ 96
Other Long-term Debt		157			$ 223
Long-term Debt		36,968			30,485
Current maturities of long-term debt		131			1,008
Long-term debt, less current maturities		36,837			29,477
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		17			(3)
Deferred Finance Costs, Noncurrent, Net		(38)			(34)
Long-term Debt		6,332			4,646
Long-term debt, less current maturities		6,332			4,646
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,187			1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		1,150			1,150
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			0
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt		2,190		$ 2,250	1,400
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due December 18, 2018 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		860			940
ETP [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(21)			(1)
Deferred Finance Costs, Noncurrent, Net		(147)			(55)
Long-term Debt		20,633			11,404
ETP [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		277			277
ETP [Member] | 4.05% Senior Notes due March 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			0
ETP [Member] | 4.75% Senior Notes due January 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			0
ETP [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		267			267
ETP [Member] | 4.90% Senior Notes due March 2035 [Member]
Debt Instrument [Line Items]
Senior Notes		500			0
ETP [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Senior Notes		400			400
ETP [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Senior Notes		550			550
ETP [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Senior Notes		700			700
ETP [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			1,000
ETP [Member] | 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450			450
ETP [Member] | 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450			450
ETP [Member] | 5.15% Senior Notes due March 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			0
ETP [Member] | 6.125% Senior Notes due December 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			0
ETP [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		545			546
ETP [Member] | ETP Credit Facility due November 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,362			570
ETP [Member] | 5.95% Senior Notes, due February 1, 2015 [Member]
Debt Instrument [Line Items]
Senior Notes		0			750
ETP [Member] | 6.125% Senior Notes, due February 15, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		400			400
ETP [Member] | 2.50% Senior Notes due June 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		650			0
ETP [Member] | 6.7% Senior Notes, due July 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		600			600
ETP [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		400			400
ETP [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		450			450
ETP [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		400			0
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,050			700
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		900			0
ETP [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		700			0
ETP [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		600			0
ETP [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		350			350
ETP [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		500			0
ETP [Member] | Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		800			800
ETP [Member] | Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000			1,000
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		700			0
ETP [Member] | 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800			800
Regency [Member]
Debt Instrument [Line Items]
Senior Notes			$ 5,100
Deferred Finance Costs, Noncurrent, Net					58
Long-term Debt	[1]	0			6,583
Sunoco [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(20)			(35)
Long-term Debt		485			750
Sunoco [Member] | 9.625% Senior Notes, due 2015 [Member]
Debt Instrument [Line Items]
Senior Notes		0			250
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		400			400
Sunoco [Member] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Subordinated Debt		65			65
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		85			100
Deferred Finance Costs, Noncurrent, Net		(32)			(26)
Long-term Debt		5,590			4,234
Sunoco Logistics [Member] | 6.125% Senior Notes, due May 15, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	[2]	175			175
Sunoco Logistics [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		250			250
Sunoco Logistics [Member] | Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		300			300
Sunoco Logistics [Member] | 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		350			350
Sunoco Logistics [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Senior Notes		250			250
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		500			500
Sunoco Logistics [Member] | 5.95% Senior Notes due December 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		400			0
Sunoco Logistics [Member] | Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		300			300
Sunoco Logistics [Member] | 5.30% Senior Notes due April 1, 2044 [Member]
Debt Instrument [Line Items]
Senior Notes		700			700
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		800			800
Sunoco Logistics [Member] | 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		350			350
Sunoco Logistics [Member] | Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	[3]	0			35
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		562			150
Sunoco LP [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(18)			0
Long-term Debt		1,832			683
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		600			0
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800			0
Sunoco LP [Member] | Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		450			683
Transwestern [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(1)			(1)
Deferred Finance Costs, Noncurrent, Net		(2)			(3)
Long-term Debt		779			778
Transwestern [Member] | 5.54% Senior Unsecured Notes, due November 17, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes		125			125
Transwestern [Member] | 5.64% Senior Unsecured Notes, due May 24, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		82			82
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		175			175
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		150			150
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		175			175
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes		75			75
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(75)			(99)
Long-term Debt		1,160			1,184
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		82			82
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
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]
Senior Notes		300			300
Panhandle [Member] | 7.00% Senior Notes, due June 15, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		400			400
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		150			150
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 66			$ 66
[1]	(3) The Regency senior notes were redeemed and/or assumed by ETP. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated.
[2]	(1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.
[3]	(2) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.50 billion Revolving Credit Facility.

Debt Obligations Debt Obligat71

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
2,016	$ 308
2,017	1,189
2,018	2,515
2,019	5,007
2,020	4,729
Thereafter	23,316
Long-term Debt	36,968	$ 30,485
Excluding unamortized premiums and fair value adjustments [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 37,064

Debt Obligations (Senior Notes

Debt Obligations (Senior Notes and Term Loans Narrative) (Details) shares in Millions, $ in Millions		1 Months Ended	3 Months Ended								12 Months Ended
		Aug. 30, 2015USD ($)	Dec. 31, 2015USD ($)shares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)shares	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)	Apr. 30, 2015USD ($)	Feb. 18, 2015USD ($)	Jul. 01, 2014USD ($)	May 01, 2014USD ($)	Feb. 28, 2014USD ($)	Jan. 10, 2014	Oct. 05, 2012USD ($)
Noncontrolling interest			$ 24,530				$ 21,650				$ 24,530	$ 21,650
Less: Net income (loss) attributable to noncontrolling interest											$ (96)	491	$ 119
Leverage Ratio Maximum											6
Net income			(138)	$ 238	$ 772	$ 221	(294)	$ 470	$ 500	$ 448	$ 1,093	1,124	315
Maximum Leverage Ratio Permitted											7
Required repayment of term loan											$ 50
Repayments of Long-term Debt											19,828	13,886	11,951
Long-term Debt			$ 36,968				30,485				$ 36,968	30,485
Debt instrument, interest rate, stated percentage			4.50%								4.50%
Proceeds from borrowings											$ 26,455	18,375	12,934
Line of Credit Facility, Current Borrowing Capacity															$ 1,500
Advances to and investments in unconsolidated affiliates			$ 3,462				3,659				3,462	3,659	4,014
Equity in earnings from unconsolidated affiliates											276	332	236
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								150
Line of Credit Facility, Current Borrowing Capacity			600								600						$ 1,200	$ 800
Line of Credit Facility, Maximum Borrowing Capacity			1,000								1,000
Sunoco Merger [Member]
Senior Notes			465								$ 465									$ 965
7.60% Senior Notes, due February 1, 2024 [Member]
Debt instrument, interest rate, stated percentage																			7.60%
LIBOR [Member] | Senior Secured Term Loan B Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate											2.50%
LIBOR [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate											3.25%
Base Rate Loans [Member] | Senior Secured Term Loan B Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate											1.50%
Base Rate Loans [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate											2.25%
Regency [Member]
Senior Notes														$ 5,100
Long-term Debt	[1]		0				6,583				$ 0	6,583
Regency [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Senior Notes		$ 600
Debt instrument, interest rate, stated percentage		4.50%
Regency [Member] | 8.375% Senior Notes due June 1, 2019 [Member]
Early Repayment of Senior Debt					$ 499
Debt instrument, interest rate, stated percentage					8.375%
Regency [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Redemption Premium		$ 24
Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member]
Redemption Premium		$ 40
Regency [Member] | 8.375% Senior Notes due June 1, 2019 [Member]
Senior Notes																$ 499
Debt instrument, interest rate, stated percentage																8.38%
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								$ 54
Parent Company [Member]
Repayments of Long-term Debt											1,985	1,142	3,235
Long-term Debt			6,332				4,646				6,332	4,646
Proceeds from borrowings											3,672	3,020	2,080
Advances to and investments in unconsolidated affiliates			5,764				5,390				5,764	5,390
Equity in earnings from unconsolidated affiliates											1,601	955	617
Parent Company [Member] | Amended and Restated Commitment Letter [Member]
Line of Credit Facility, Current Borrowing Capacity			6,050								$ 6,050
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum											5.50%
Parent Company [Member] | Senior Secured Term Loan B Agreement [Member]
Secured Debt			1,400								$ 1,400
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Senior Notes			$ 1,000				0				$ 1,000	0
Debt instrument, interest rate, stated percentage			5.50%								5.50%
Debt Instrument, Maturity Date											Jun. 1, 2027
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes			$ 1,150				1,150				$ 1,150	1,150
Debt instrument, interest rate, stated percentage			5.88%								5.88%
Debt Instrument, Maturity Date											Jan. 15, 2024
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Secured Debt			$ 2,190			2,250	1,400				$ 2,190	1,400
Debt Instrument, Maturity Date											Dec. 2, 2019
Parent Company [Member] | Increase in term loan [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Secured Debt						850
Panhandle [Member]
Long-term Debt			1,160				1,184				$ 1,160	1,184
ETP [Member]
Leverage Ratio Maximum											5
Maximum Leverage Ratio Permitted											5.5
Long-term Debt			$ 20,633				11,404				$ 20,633	11,404
Proceeds from borrowings					$ 2,980	2,480
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares			2.6								2.6
ETP [Member] | 5.15% Senior Notes due March 2045 [Member]
Senior Notes						$ 1,000
Debt instrument, interest rate, stated percentage						5.15%
ETP [Member] | 2.50% Senior Notes due June 2018 [Member]
Senior Notes					$ 650
Debt instrument, interest rate, stated percentage					2.50%
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Senior Notes					$ 350
Debt instrument, interest rate, stated percentage					4.15%
ETP [Member] | 4.75% Senior Notes due January 2026 [Member]
Senior Notes					$ 1,000
Debt instrument, interest rate, stated percentage					4.75%
ETP [Member] | 6.125% Senior Notes due December 2045 [Member]
Senior Notes					$ 1,000
Debt instrument, interest rate, stated percentage					6.125%
ETP [Member] | 4.05% Senior Notes due March 2025 [Member]
Senior Notes						$ 1,000
Debt instrument, interest rate, stated percentage						4.05%
ETP [Member] | 4.90% Senior Notes due March 2035 [Member]
Senior Notes						$ 500
Debt instrument, interest rate, stated percentage						4.90%
ETP [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument, Interest Rate, Effective Percentage			3.645%								3.645%
Debt instrument, interest rate, stated percentage			7.20%								7.20%
Debt Instrument, Maturity Date											Nov. 1, 2066
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Senior Notes			$ 900				0				$ 900	0
Debt instrument, interest rate, stated percentage			5.88%								5.88%
Debt Instrument, Maturity Date											Mar. 1, 2022
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Senior Notes			$ 700				0				$ 700	0
Debt instrument, interest rate, stated percentage			5.00%								5.00%
Debt Instrument, Maturity Date											Oct. 1, 2022
Sunoco Logistics [Member]
Long-term Debt			$ 5,590				4,234				$ 5,590	4,234
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Senior Notes			$ 800				800				$ 800	800
Debt instrument, interest rate, stated percentage			5.35%								5.35%
Debt Instrument, Maturity Date											May 15, 2045
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes			$ 500				500				$ 500	500
Debt instrument, interest rate, stated percentage			4.25%								4.25%
Debt Instrument, Maturity Date											Apr. 1, 2024
Sunoco Logistics [Member] | 4.40% Senior Notes due April 2021 [Member]
Senior Notes			$ 600				0				$ 600	0
Debt instrument, interest rate, stated percentage			4.40%								4.40%
Debt Instrument, Maturity Date											Apr. 1, 2021
Sunoco LP [Member]
Leverage Ratio Maximum											5.50
Maximum Leverage Ratio Permitted											6
Long-term Debt			$ 1,832				683				$ 1,832	683
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Senior Notes			$ 600				0				$ 600	0
Debt instrument, interest rate, stated percentage			5.50%								5.50%
Debt Instrument, Maturity Date											Aug. 1, 2020
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Senior Notes			$ 800				0				$ 800	0
Debt instrument, interest rate, stated percentage			6.375%								6.375%
Debt Instrument, Maturity Date											Apr. 1, 2023
Letter of Credit [Member] | Maximum [Member] | ETE Credit Facility [Member]
Debt Instrument, Basis Spread on Variable Rate											2.50%
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								$ 1,000
ETE Senior Secured Term Loan due December 2, 2019 [Member] | After increase in capacity [Member]
Line of Credit Facility, Current Borrowing Capacity			1,400								1,400
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Increase in term loan [Member]
Line of Credit Facility, Current Borrowing Capacity			400								400
ETP [Member] | ETP GP [Member]
Noncontrolling interest			$ 20,530				11,940				20,530	11,940
Less: Net income (loss) attributable to noncontrolling interest											$ 334	823	$ (50)
ETP [Member] | ETE Common Holdings [Member]
Advances to and investments in unconsolidated affiliates							$ 1,720					1,720
Equity in earnings from unconsolidated affiliates												$ 292
ETE Common Holdings [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares							30.9					30.9
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest												7.50%
ETE Common Holdings [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares							5.2					5.2
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. | shares			81								81
Class H Units [Member] | ETE Common Holdings [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares							50.2					50.2
[1]	(3) The Regency senior notes were redeemed and/or assumed by ETP. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated.

Debt Obligations (Credit Facili

Debt Obligations (Credit Facilities Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Apr. 30, 2015	Feb. 18, 2015	Dec. 31, 2014	May 01, 2014	Feb. 28, 2014
Revolving credit facility				$ 1,500
Long-term Debt		$ 36,968			$ 30,485
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Parent Company [Member]
Long-term Debt		$ 6,332			4,646
ETP [Member]
Long-term Debt		20,633			11,404
Sunoco Logistics [Member]
Long-term Debt		5,590			4,234
Sunoco LP [Member]
Long-term Debt		1,832			683
Regency [Member]
Senior Notes			$ 5,100
Long-term Debt	[1]	0			6,583
ETE Credit Facility [Member]
Revolving credit facility		600				$ 1,200	$ 800
Letters Of Credit Availablity		150
Line of Credit Facility, Maximum Borrowing Capacity		1,000
Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] | Sunoco Logistics [Member]
Revolving credit facility		2,500
Line of Credit Facility, Maximum Borrowing Capacity		$ 3,250
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member]
Debt Instrument, Maturity Date		Dec. 1, 2025
Senior Notes		$ 400			0
Debt Instrument, Interest Rate, Stated Percentage		5.95%
ETP Credit Facility due November 2019 [Member] | ETP [Member]
Long-term Line of Credit		$ 1,362			570
Amount available for future borrowings		2,240
Letters of Credit Outstanding, Amount		$ 145
Line of Credit Facility, Interest Rate at Period End		1.86%
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Revolving credit facility		$ 1,500			1,250
Long-term Line of Credit		450			$ 683
Line of Credit Facility, Maximum Borrowing Capacity		$ 250
Maximum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate		1.50%
Maximum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate		2.50%
Minimum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate		0.75%
Minimum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt instrument, basis spread on variable rate		1.75%
ETP Revolving Credit Facility, due October 27, 2019 [Member]
Revolving credit facility		$ 3,750
[1]	(3) The Regency senior notes were redeemed and/or assumed by ETP. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated.

Debt Obligations Debt Obligat74

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
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
ETP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5
Maximum Leverage Ratio Permitted	5.5
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio	5
Adjusted EBITDA Ratio	3.6
Sunoco LP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5.50
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 Obligat75

Debt Obligations Debt Obligations (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Jul. 01, 2014
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Parent Company [Member]
Deferred Finance Costs, Noncurrent, Net	$ (38)	$ (34)
ETP [Member]
Deferred Finance Costs, Noncurrent, Net	(147)	(55)
Regency [Member]
Deferred Finance Costs, Noncurrent, Net		58
Sunoco Logistics [Member]
Deferred Finance Costs, Noncurrent, Net	(32)	(26)
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	$ (2)	$ (3)
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Oct. 15, 2020
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Jan. 15, 2024
5.5% Senior Notes due June 1, 2027 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Jun. 1, 2027
ETE Senior Secured Term Loan due December 2, 2018 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 2, 2018
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 2, 2019
5.95% Senior Notes, due February 1, 2015 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Feb. 1, 2015
6.125% Senior Notes, due February 15, 2017 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Feb. 15, 2017
2.50% Senior Notes due June 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Maturity Date	Jun. 15, 3028
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.70%
Debt Instrument, Maturity Date	Jul. 1, 2018
9.7% Senior Notes, due March 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%
Debt Instrument, Maturity Date	Mar. 15, 2019
9.0% Senior Notes due April 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt Instrument, Maturity Date	Oct. 1, 2020
Senior Notes 4.65% Due June 1, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Jun. 1, 2021
Senior Notes 5.20% Due February 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt Instrument, Maturity Date	Feb. 1, 2022
3.6% Senior Notes due February 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	Feb. 1, 2023
4.9% Senior Notes due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Feb. 1, 2024
6.625% Senior Notes, due October 15, 2036 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument, Maturity Date	Oct. 15, 2036
4.90% Senior Notes due March 2035 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Mar. 15, 2035
7.5% Senior Notes, due July 1, 2038 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Jul. 1, 2038
Senior Notes 6.05% Due June 1, 2041 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt Instrument, Maturity Date	Jun. 1, 2041
Senior Notes 6.50% Due February 1, 2042 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Oct. 1, 2043
5.15% Senior Notes due March 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Mar. 15, 2045
6.125% Senior Notes due December 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Dec. 15, 2045
6.20% Senior Notes, due November 1, 2017 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Debt Instrument, Maturity Date	Nov. 1, 2017
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jun. 15, 2018
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Debt Instrument, Maturity Date	Jun. 1, 2019
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jul. 15, 2029
Term Loan due February 23, 2015 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.84%
Debt Instrument, Maturity Date	Feb. 23, 2015
5.75% Senior Notes due September 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Sep. 1, 2020
5.875% Senior Notes due April 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Mar. 1, 2022
5.5% Senior Notes, due April 15, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Apr. 15, 2023
4.5% Senior Notes due November 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Nov. 1, 2023
6.5% Senior Notes due May 15, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	May 15, 2021
8.375% Senior Notes due June 1, 2019 [Member] | Regency [Member]
Debt Instrument, Interest Rate, Stated Percentage			8.38%
5.0% Senior Notes due October 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Oct. 1, 2022
7.60% Senior Notes, due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
7.60% Senior Notes, due February 1, 2024 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
4.05% Senior Notes due March 2025 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.05%
Debt Instrument, Maturity Date	Mar. 15, 2025
4.75% Senior Notes due January 2026 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Debt Instrument, Maturity Date	Jan. 15, 2026
8.25% Senior Notes, due November 14, 2029 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 15, 2029
8.25% Senior Notes, due November 14, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 14, 2029
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt Instrument, Maturity Date	Nov. 1, 2066
9.625% Senior Notes, due 2015 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.63%
Debt Instrument, Maturity Date	Apr. 15, 2015
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Jan. 15, 2017
9.00% Debentures, due 2024 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Nov. 1, 2024
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	May 15, 2016
5.50% Senior Notes, due February 15, 2020 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2020
4.40% Senior Notes due April 2021 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.40%
Debt Instrument, Maturity Date	Apr. 1, 2021
Senior Note 4.65% Due February 15, 2022 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Feb. 15, 2022
3.45% Senior Notes due January 2023 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt Instrument, Maturity Date	Jan. 15, 2023
4.25% Senior Notes due April 1, 2024 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Apr. 1, 2024
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Dec. 1, 2025
6.85% Senior Notes, due February 15, 2040 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt Instrument, Maturity Date	Feb. 15, 2040
Senior Note 6.10%, due February 15, 2042 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Feb. 15, 2042
4.95% Senior Notes due January 2043 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	Jan. 15, 2043
5.30% Senior Notes due April 1, 2044 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.35%
Debt Instrument, Maturity Date	May 15, 2045
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.54%
Debt Instrument, Maturity Date	Nov. 17, 2016
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.64%
Debt Instrument, Maturity Date	May 24, 2017
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt Instrument, Maturity Date	Dec. 9, 2020
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt Instrument, Maturity Date	May 24, 2022
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt Instrument, Maturity Date	Dec. 9, 2024
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt Instrument, Maturity Date	May 24, 2037

Redeemable Preferred Units (Det

Redeemable Preferred Units (Details) shares in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015shares	Dec. 31, 2015USD ($)	Dec. 31, 2013USD ($)	Apr. 30, 2015USD ($)$ / commonunitshares
Mandatory redeemable price of units outstanding				$ 35,000,000
Conversion of Stock, Amount Converted		$ 0	$ (41,000,000)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares	0.9
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit				0.445
Preferrred Units Issued Stated Price				$ 18.30
Conversion Price of Preferred Units				$ 44.37
Regency Merger [Member]
Preferred Units, Issued | shares				1.9

Equity (Narrative) (Details)

Equity (Narrative) (Details) $ / shares in Units, $ in Millions	1 Months Ended						3 Months Ended	6 Months Ended	12 Months Ended
	Apr. 30, 2015USD ($)shares	Mar. 31, 2015USD ($)shares	Aug. 31, 2014USD ($)	Jul. 31, 2014USD ($)	Mar. 21, 2014USD ($)	Apr. 30, 2013USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Sep. 30, 2015	Feb. 18, 2015USD ($)	Dec. 31, 2012shares	Oct. 05, 2012shares
Stock Issued During Period, Shares, New Issues | shares										924,000	0	0
Stock Repurchase Program, Authorized Amount | $										$ 2,000		$ 1,000
Partners' Capital Account, Units, Unit-based Compensation | shares										33,600,000	42,300,000	0
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $										$ 936
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares										3,000,000
Common Units Issued Inconnection With The Equity Distribution Agreement | shares										21,100,000
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding										20.00%
Limited Partners' Capital Account, Units Outstanding | shares							1,077,533,798	1,077,533,798		1,044,767,336	1,077,533,798	1,119,800,000			1,119,800,000
Limited Partner interest in the Partnership, percentage										99.53%
Gain from subsidiary issuances of common units | $										$ (526)	$ 744	$ (384)
Distribution Reinvestment Plan, Purchase Discount										0.01			0.05
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $										$ 1,070
Equity Distribution Agreements, Value of Units Available to be Issued | $										$ 328
Class E Unit Distribution Rate										11.10%
Class E Unit Maximum Distribution | $ / shares										$ 1.41
Class F Unit Distribution Rate										35.00%
Class F Unit Maximum Distribution | $ / shares										$ 3.75
Line of Credit Facility, Current Borrowing Capacity | $														$ 1,500
ETP [Member]
Stock Issued During Period, Shares, Dividend Reinvestment Plan | shares										12,800,000
Stock Issued During Period, Value, Dividend Reinvestment Plan | $										$ 360	155	$ 109
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | shares										11,500,000
Partners' Capital Account, Units, Sold in Public Offering | shares						13,800,000
Proceeds from Issuance of Common Limited Partners Units | $						$ 657
Sunoco Logistics [Member]
Stock Issued During Period, Shares, New Issues | shares	2,000,000
Common Units Issued Inconnection With The Equity Distribution Agreement | shares										26,800,000
Proceeds from Issuance of Common Stock | $	$ 82	$ 547									362
Fees and Commissions | $										$ 10
Equity Distribution Agreement, maximum aggregate value of common units sold | $										2,250	$ 1,250
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $										890
Partners' Capital Account, Units, Sale of Units | shares		13,500,000									7,700,000
Sunoco LP [Member]
Proceeds from Issuance of Common Stock | $										$ 213
Partners' Capital Account, Units, Sale of Units | shares							9,100,000			5,500,000
Partners' Capital Account, Sale of Units | $							$ 405
Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares										3,080,000
Limited Partners' Capital Account, Units Outstanding | shares							3,080,000	3,080,000		2,156,000	3,080,000
Class F Units [Member] | Sunoco [Member]
Partners' Capital Account, Units | shares										40,000,000
Class H Units [Member]
Partners' Capital Account, Units | shares		50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent										50.05%
Holdco Transaction [Member] | Class G Units [Member]
Partners' Capital Account, Units | shares																90,700,000
PVR Acquisition [Member] | Regency [Member]
Business Combination, Consideration Transferred | $					$ 5,700
Eagle Rock Midstream Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, Acquisitions | shares								8,200,000
Proceeds from Issuance of Common Stock | $								$ 400
Business Combination, Consideration Transferred | $				$ 1,300
Susser Merger [Member]
Business Combination, Consideration Transferred | $			$ 875
Bakken Pipeline Transaction [Member]
Class I Distributions | $									$ 30	$ 55
Partners' Capital Account, Units, Redeemed | shares		30,800,000
Business Combination, Consideration Transferred | $		$ 879
Bakken Pipeline Transaction [Member] | Parent Company [Member]
Percent of total equity ownership of a subsidiary		45.00%
Bakken Pipeline Transaction [Member] | Class H Units [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent		90.05%
Partners' Capital Account, Units, Redeemed | shares		30,800,000
Bakken Pipeline Transaction [Member] | Class I Units [Member]
Partners' Capital Account, Units | shares		100
Additional Units [Member] | Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares										80,000
March 2015 [Member]
Vesting Schedule, Percent of Class D Units Vesting										30.00%
March 2018 [Member]
Vesting Schedule, Percent of Class D Units Vesting										35.00%
March 2020 [Member]
Vesting Schedule, Percent of Class D Units Vesting										35.00%
Equity Distribution Agreement [Member]
Fees and Commissions | $										$ 11
Class E Units [Member] | ETP [Member]
Limited Partners' Capital Account, Units Outstanding | shares										8,900,000
Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity | $										$ 2,500
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Line of Credit Facility, Current Borrowing Capacity | $							$ 1,250	$ 1,250		$ 1,500	$ 1,250

Equity (Change In ETE Common Un

Equity (Change In ETE Common Units) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Stock Issued During Period, Shares, New Issues		924,000	0	0
Unamortized financing costs(1)	[1]				$ 29	$ 41
Outstanding		1,044,767,336	1,077,533,798	1,119,800,000	1,044,767,336	1,077,533,798	1,119,800,000
Issuance of restricted Common Units under long-term incentive plans		(33,600,000)	(42,300,000)	0
Number of Common Units, end of period		1,044,767,336	1,077,533,798	1,119,800,000
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Equity (Quarterly Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) - USD ($) $ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Partners' Capital Account, Distributions

$ 1,090

$ 821

$ 733

Sunoco LP [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 5, 2016

Nov. 17, 2015

Aug. 18, 2015

May 19, 2015

Feb. 17, 2015

Nov. 18, 2014

Distribution Made to Limited Partner, Distribution Date

Feb. 16, 2016

Nov. 27, 2015

Aug. 28, 2015

May 29, 2015

Feb. 27, 2015

Nov. 28, 2014

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8013

$ 0.7454

$ 0.6934

$ 0.6450

$ 0.6000

$ 0.5457

Sunoco Logistics [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 8, 2016

Nov. 9, 2015

Aug. 10, 2015

May 11, 2015

Feb. 9, 2015

Nov. 7, 2014

Aug. 8, 2014

May 9, 2014

Feb. 10, 2014

Nov. 8, 2013

Aug. 8, 2013

May 9, 2013

Feb. 8, 2013

Distribution Made to Limited Partner, Distribution Date

Feb. 12, 2016

Nov. 13, 2015

Aug. 14, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

May 15, 2014

Feb. 14, 2014

Nov. 14, 2013

Aug. 14, 2013

May 15, 2013

Feb. 14, 2013

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4790

$ 0.4580

$ 0.4380

$ 0.4190

$ 0.4000

$ 0.3825

$ 0.3650

$ 0.3475

$ 0.3312

$ 0.3150

$ 0.3000

$ 0.2863

$ 0.2725

Parent Company [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 4, 2016

Nov. 5, 2015

Aug. 6, 2015

May 8, 2015

Feb. 6, 2015

Nov. 3, 2014

Aug. 4, 2014

May 5, 2014

Feb. 7, 2014

Nov. 4, 2013

Aug. 5, 2013

May 6, 2013

Feb. 7, 2013

Distribution Made to Limited Partner, Distribution Date

Feb. 19, 2016

Nov. 19, 2015

Aug. 19, 2015

May 19, 2015

Feb. 19, 2015

Nov. 19, 2014

Aug. 19, 2014

May 19, 2014

Feb. 19, 2014

Nov. 19, 2013

Aug. 19, 2013

May 17, 2013

Feb. 19, 2013

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2850

$ 0.2850

$ 0.2650

$ 0.2450

$ 0.2250

$ 0.2075

$ 0.1900

$ 0.1794

$ 0.1731

$ 0.1681

$ 0.1638

$ 0.1613

$ 0.1588

ETP [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 8, 2016

Nov. 5, 2015

Aug. 6, 2015

May 8, 2015

Feb. 6, 2015

Nov. 3, 2014

Aug. 4, 2014

May 5, 2014

Feb. 7, 2014

Nov. 4, 2013

Aug. 5, 2013

May 6, 2013

Feb. 7, 2013

Distribution Made to Limited Partner, Distribution Date

Feb. 16, 2016

Nov. 16, 2015

Aug. 14, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

May 15, 2014

Feb. 14, 2014

Nov. 14, 2013

Aug. 14, 2013

May 15, 2013

Feb. 14, 2013

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 1.0550

$ 1.0550

$ 1.0350

$ 1.0150

$ 0.9950

$ 0.9750

$ 0.9550

$ 0.9350

$ 0.9200

$ 0.9050

$ 0.8938

$ 0.8938

$ 0.8938

Equity (Accumulated Other Compr

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Partners' Capital Notes [Abstract]
Net gains on commodity related hedges	$ 0	$ (1)
Unrealized gains on available-for-sale securities	0	3
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	(4)	(3)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	8	(57)
AOCI attributable to equity method investments	0	2
Subtotal	4	(56)
Amounts attributable to noncontrolling interest	(4)	51
Total AOCI included in partners' capital, net of tax	$ 0	$ (5)

Equity Tax amounts in component

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Other Comprehensive Income Loss Commodity Hedges Tax	$ (2)	$ (1)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	4	2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	7	(37)
Other Comprehensive Income (Loss), Tax	$ 9	$ (36)

Equity (Relinquishments of Ince

Equity (Relinquishments of Incentive Distribution Rights) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Future IDR Relinquishments [Member] | Currently Effective IDRs [Member]
Relinquishment of Incentive Distributions	$ 95	$ 105	$ 128	$ 137

ETE Unit-Based Compensation Pla

ETE Unit-Based Compensation Plans (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		5,300,000
Stock Issued During Period, Shares, New Issues		924,000	0	0
Unvested awards		4,800,000
Fair Value Of Units As Of The Vesting Date		$ 49	$ 26	$ 29
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		12,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		11,367,454
Unvested awards		56,096
Units Vested In Period		26,244
Fair Value Of Units As Of The Vesting Date		$ 0.8
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 1
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term		2 years 8 months
Employee [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted		0
Director [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted		12,748
Class D Units [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	3,080,000
March 2015 [Member]
Vesting Schedule, Percent of Class D Units Vesting		30.00%
March 2018 [Member]
Vesting Schedule, Percent of Class D Units Vesting		35.00%
March 2020 [Member]
Vesting Schedule, Percent of Class D Units Vesting		35.00%

Unit-Based Compensation Plans E

Unit-Based Compensation Plans ETP Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	4.8
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 47.61	$ 53.83
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 35.21	$ 60.85	$ 50.54
Fair Value Of Units As Of The Vesting Date	$ 49	$ 26	$ 29
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 48.67
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 55.44
ETP Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	5 years
Unvested awards	4.8	3.5
Awards granted	2.1
Awards vested	(1.2)
Stock Granted, Value, Share-based Compensation, Forfeited	$ 0.4
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 147
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 1 month 1 day
ETP Cash Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	0.6
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 7
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 4 months 1 day
Regency Awards Converted in Merger [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted	0.8
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 58.88
Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	5 years

Unit-Based Compensation Plans S

Unit-Based Compensation Plans Sunoco Logistics Unit Based Compensation (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	4.8
Sunoco Logistics Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	2.5
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $	$ 52
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	3 years

Unit-Based Compensation Plans86

Unit-Based Compensation Plans Sunoco LP Unit Based Compensation (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)shares
Unvested awards	4.8
Sunoco LP [Member]
Unvested awards	1.1
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $	$ 40
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	3 years 4 months

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 67
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	123
Deferred Tax Liabilities, Gross	4,945	$ 4,653
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	588
Net operating losses and alternative minimum tax credit	217	116
Valuation allowance	(121)	(84)
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	550
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	3
Proceeds from Income Tax Refunds	$ 519
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	519
State	(51)	86	$ (1)
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities	7
Unrecognized Tax Benefits, Interest on Income Taxes Expense	1
Income Tax Examination, Penalties and Interest Accrued	5
Amount Reclassed From ASU 2015-17 [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Liabilities, Gross		$ 85
Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State	46
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	9
Net of federal tax [Member] | Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State	30
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	$ 6

Income Taxes Components of Inco

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Current expense (benefit):
Federal	$ (292)		$ 321		$ 51
State	(51)		86		(1)
Total	(343)		407		50
Deferred expense (benefit):
Federal	272		(53)		(14)
State	(29)		3		57
Total	243		(50)		43
Total income tax expense (benefit) from continuing operations	$ (100)	[1]	$ 357	[1]	$ 93
[1]	Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries.

Income Taxes Reconciliation of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Income tax expense (benefit) at U.S. statutory rate of 35 percent	[1]	$ (19)		$ 212
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill	[1]	0		0
Nondeductible goodwill included in the Lake Charles LNG Transaction	[1]	0		105
Dividend received deduction	[1]	(22)		0
Premium on debt retirement	[1]	0		(10)
Audit settlement	[1]	(7)		0
Foreign taxes	[1]	0		(8)
State income taxes (net of federal income tax effects)	[1]	(26)		55
Other	[1]	(26)		3
Total income tax expense (benefit) from continuing operations		(100)	[1]	357	[1]	$ 93
Corporate Subsidiaries [Member]
Income tax expense (benefit) at U.S. statutory rate of 35 percent	[2]	(19)		212		(172)
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill	[2]	0		0		241
Nondeductible goodwill included in the Lake Charles LNG Transaction	[2]	0		105		0
Dividend received deduction	[2]	(22)		0		0
Premium on debt retirement	[2]	0		(10)		0
Audit settlement	[2]	(7)		0		0
Foreign taxes	[2]	0		(8)		0
State income taxes (net of federal income tax effects)	[2]	(45)		9		31
Other	[2]	(26)		3		(16)
Total income tax expense (benefit) from continuing operations	[2]	$ (119)		$ 311		84
Partnership [Member]
Income tax expense (benefit) at U.S. statutory rate of 35 percent	[1]					(172)
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill	[1]					241
Nondeductible goodwill included in the Lake Charles LNG Transaction	[1]					0
Dividend received deduction	[1]					0
Premium on debt retirement	[1]					0
Audit settlement	[1]					0
Foreign taxes	[1]					0
State income taxes (net of federal income tax effects)	[1]					41
Other	[1]					(17)
Total income tax expense (benefit) from continuing operations	[1]					$ 93
[1]	Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries.
[2]	Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company.

Income Taxes Effects of Tempora

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effects of Temporary Differences that Comprise Net Deferred Income Tax Liability [Abstract]
Settlements	$ 0	$ 5	$ 0
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	217	116
Pension and other postretirement benefits	36	47
Long term debt	61	53
Other	162	111
Deferred Tax Assets, Gross	476	327
Valuation allowance	(121)	(84)
Net deferred income tax assets	355	243
Deferred income tax liabilities:
Properties, plants and equipment	(1,633)	(1,583)
Inventory	0	(153)
Investments in unconsolidated affiliates	(2,976)	(2,530)
Trademarks	(286)	(355)
Other	(50)	(32)
Deferred Tax Liabilities, Gross	4,945	4,653
Deferred Tax Liabilities	$ (4,590)	$ (4,410)	$ (3,984)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of Net Deferred Income Tax [Abstract]
Deferred Tax Liabilities, Net	$ (4,590)	$ (4,410)	$ (3,984)
Increase in Tax Liability Attributable to Sunoco Acquisition	0	(488)
Noncurrent asset	(242)	62
Deferred Tax Liabilities, Other	$ 62	$ 0

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 440	$ 429	$ 27
Additions attributable to tax positions taken in the current year	178	20	0
Additions attributable to tax positions taken in prior years	0	(1)	406
Settlements	0	5	0
Lapse of statute	8	3	4
Balance at end of year	$ 610	$ 440	$ 429

Regulatory Matters, Commitmen93

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)	1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Mar. 31, 2016USD ($)	Sep. 30, 2012USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jan. 10, 2014USD ($)
Payments for Environmental Liabilities					$ 38,000,000	$ 48,000,000
Debt Instrument, Interest Rate, Stated Percentage					4.50%
Lease Expiration Date					Dec. 31, 2058
Operating leases rent expense					$ 225,000,000	159,000,000	$ 151,000,000
Environmental Costs Recognized, Recovery Credited to Expense					19,000,000
Total environmental liabilities					368,000,000	401,000,000
Guarantor Obligations, Current Carrying Value								$ 600,000,000
Operating Leases, Rent Expense, Contingent Rentals					$ 26,000,000	24,000,000	$ 22,000,000
Site Contingency, Number of Sites Needing Remediation					50
Proposed Environmental Penalty					$ 0
Payments to Acquire Businesses, Gross	$ 382,000,000
FGT [Member]
Proceeds from Legal Settlements				$ 100,000,000
Interest Awarded				$ 19,000,000	1,000,000
AmeriGas [Member]
Contingent Residual Support Agreement Obligation					$ 1,550,000,000
Southern Union [Member]
Percentage Of Recovery					50.00%
Loss Contingency, Estimated Recovery from Third Party					150,000
Related To Deductibles [Member]
Accrual for loss contingency					$ 40,000,000	37,000,000
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
New Mexico Environmental Department [Member]
Total environmental liabilities					250,000
Texas Commission on Environmental Quality [Member]
Total environmental liabilities					$ 300,000
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage		31.58%
Payments to Acquire Businesses, Gross		$ 775,000,000
Equity Issued in Business Combination, Fair Value Disclosure		$ 41,000,000
Dropdown of Sunoco LLC Interest [Member] | Sunoco LP [Member]
Payments to Acquire Businesses, Gross			$ 2,200,000,000
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage					6.375%
Senior Notes					$ 800,000,000	$ 0

Regulatory Matters, Commitmen94

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) $ in Millions	Dec. 31, 2015USD ($)
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
2,016	$ 121
2,017	114
2,018	103
2,019	96
2,020	97
Thereafter	602
Total Future Rent Payments	1,133
Future Rental Income	(34)
Net Future Rental Payments	$ 1,099

Regulatory Matters, Commitmen95

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Environmental Remediation Obligations [Abstract]
Current	$ 42	$ 41
Non-current	326	360
Total environmental liabilities	$ 368	$ 401

Regulatory Matters, Commitmen96

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Schedule of Rental Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense	$ 225	$ 159	$ 151
Operating Leases, Rent Expense, Sublease Rentals	(16)	(26)	(24)
Operating Leases, Rent Expense, Net	$ 209	$ 133	$ 127

Derivative Assets And Liabili97

Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)		12 Months Ended
		Dec. 31, 2015bushelsbarrelsMegawattMMbtubbl	Dec. 31, 2014bushelsbarrelsMegawattMMbtu
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount		71,340,000	46,150,000
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		14,380,000	34,304,000
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018	2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016	2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		6,522,500	57,500
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member]
Derivative, Nonmonetary Notional Amount		21,922,484	9,116,777
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount		8,146,800	4,417,400
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount		1,289,000	13,745,755
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Corn [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | bushels		1,185,000	0
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount		0
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		602,500	232,500
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	[1]	31,240,000	13,907,500
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017	2,016
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016	2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount			5,000,000
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		1,300,647	198,556
Term Of Commodity Derivatives		2,016	2,105
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Forwards Swaps [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		357,092	288,775
Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Forwards Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Forwards Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		109,791	156,000
Term Of Commodity Derivatives		2,016	2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Power [Member] | Options - Puts [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		260,534	72,000
Term Of Commodity Derivatives		2,016	2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount		591,000	0
Mark-To-Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,017
Mark-To-Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,016
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		37,555,000	39,287,500
Term Of Commodity Derivatives		2,016	2,015
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		37,555,000	39,287,500
Term Of Commodity Derivatives		2,016	2,015
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Hedged Item - Inventory [Member]
Derivative, Nonmonetary Notional Amount		37,555,000	39,287,500
Term Of Commodity Derivatives		2,016	2,015
[1]	(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Derivative Assets And Liabili98

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Interest Rate Derivatives [Member] - ETP [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
July 2018 [Member]
Notional Amount		$ 1,200	$ 0
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
June 2021 [Member]
Notional Amount		$ 300	0
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
February 2023 [Member]
Notional Amount		$ 0	200
Type	[1]	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%
July 2015 [Member]
Notional Amount	[2]	$ 0	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate
July 2016 [Member]
Notional Amount	[3]	$ 200	200
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
Forward-Starting Swaps [Member] | July 2018 [Member]
Notional Amount	[4]	$ 200	200
Type	[1],[4]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
Forward-Starting Swaps [Member] | July 2019 [Member]
Notional Amount	[4]	$ 200	300
Type	[1],[4]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
Forward-Starting Swaps [Member] | July 2017 [Member]
Notional Amount	[4]	$ 300	$ 300
Type	[1],[4]	Forward-starting to pay a fixed rate of 3.84% and receive a floating rate
[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(2) Represents the effective date. These forward-starting swaps have a term of 10 years with a mandatory 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.

Derivative Assets And Liabili99

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Asset Derivatives	$ 454	$ 770
Liability Derivatives	(532)	(771)
Designated as Hedging Instrument [Member]
Asset Derivatives	38	43
Liability Derivatives	(3)	0
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	38	43
Liability Derivatives	(3)	0
Not Designated as Hedging Instrument [Member]
Asset Derivatives	416	727
Liability Derivatives	(529)	(771)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	353	617
Liability Derivatives	(306)	(577)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Asset Derivatives	63	107
Liability Derivatives	(47)	(23)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Asset Derivatives	0	3
Liability Derivatives	(171)	(155)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	(5)	(16)
Broker cleared derivative contracts [Member]
Asset Derivatives	391	660
Liability Derivatives	$ (309)	$ (577)

Derivative Assets And Liabil100

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Asset Derivatives	$ 454	$ 770
Derivative Liability, Fair Value, Gross Liability	(532)	(771)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(17)	(19)
Derivative Liability, Fair Value, Amount Offset Against Collateral	17	19
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(309)	(577)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	309	577
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	128	174
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(206)	(175)
Without offsetting agreements [Member]
Asset Derivatives	0	3
Derivative Liability, Fair Value, Gross Liability	(176)	(171)
OTC Contracts [Member]
Asset Derivatives	63	107
Derivative Liability, Fair Value, Gross Liability	(47)	(23)
Broker cleared derivative contracts [Member]
Asset Derivatives	391	660
Derivative Liability, Fair Value, Gross Liability	$ (309)	$ (577)

Derivative Assets And Liabil101

Derivative Assets And Liabilities (Derivatives Recognized OCI On Derivatives) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ (1)
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ (1)

Derivative Assets And Liabil102

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 0	$ (3)	$ 4
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	21	(8)	8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(2)	39	24
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	(3)	4
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	21	(8)	8
Interest Rate Derivatives [Member] | Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(18)	(157)	53
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	12	3	6
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	15	199	(21)
Non Trading [Member] | Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	0	(3)
Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (11)	$ (6)	$ (11)

Retirement Benefits (Narrative)

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ETP [Member]
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost Recognized	$ 40	$ 50	$ 47
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%	100.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 16
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 21
Other Postretirement Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	56.00%	53.00%
Fixed Income Securities	33.00%	41.00%
Cash Fund Investments	11.00%	6.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 10
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%

Retirement Benefits (Obligation

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Interest Cost	25	31
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	598
Defined Benefit Plan, Fair Value of Plan Assets	15	598
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	203	223
Defined Benefit Plan, Interest Cost	4	5
Defined Benefit Plan, Plan Amendments	0	1
Defined Benefit Plan, Benefits Paid	(20)	(28)
Defined Benefit Plan, Actuarial Gain (Loss)	(6)	2
Defined Benefit Plan, Benefit Obligation	181	203
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	272	284
Defined Benefit Plan, Actual Return on Plan Assets	0	7
Defined Benefit Plan, Contributions by Employer	9	9
Defined Benefit Plan, Benefits Paid	(20)	(28)
Defined Benefit Plan, Fair Value of Plan Assets	261	272
Defined Benefit Plan, Funded Status of Plan	(80)	(69)
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	103	96
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(2)	(2)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(22)	(25)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	79	69
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)	(21)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	16	18
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(2)	(3)
Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	(691)
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	(691)
Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	718	632
Defined Benefit Plan, Interest Cost	23	28
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(46)	(45)
Defined Benefit Plan, Actuarial Gain (Loss)	16	130
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		(27)
Defined Benefit Plan, Benefit Obligation	20	718
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	598	600
Defined Benefit Plan, Actual Return on Plan Assets	16	70
Defined Benefit Plan, Contributions by Employer	138	0
Defined Benefit Plan, Benefits Paid	(46)	(45)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		(27)
Defined Benefit Plan, Fair Value of Plan Assets	15	598
Defined Benefit Plan, Funded Status of Plan	5	120
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	(5)	(120)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(5)	(120)
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	2	18
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	2	18
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
Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	65	61
Defined Benefit Plan, Interest Cost	2	3
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(8)	(9)
Defined Benefit Plan, Actuarial Gain (Loss)	(2)	10
Defined Benefit Plan, Benefit Obligation	57	65
Change in plan assets:
Defined Benefit Plan, Benefits Paid	(8)	(9)
Defined Benefit Plan, Funded Status of Plan	57	65
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	(48)	(56)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(57)	(65)
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	4	7
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	4	7
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 [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 ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
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	$ 181	$ 203
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	261	272
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	20	718
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	20	718
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	15	598
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	57	65
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	57	65
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	$ 25	$ 31
Defined Benefit Plan, Expected Return on Plan Assets	(16)	(40)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Amortization of Gains (Losses)	0	(1)
Net Periodic Benefit Costs, Settlements	32	(4)
Defined Benefit Plan, Net Periodic Benefit Cost	41	(14)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	4	5
Defined Benefit Plan, Expected Return on Plan Assets	(8)	(8)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	1
Defined Benefit Plan, Amortization of Gains (Losses)	0	(1)
Net Periodic Benefit Costs, Settlements	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ (3)	$ (3)

Retirement Benefits (Benefit As

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.16%	7.09%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.39%	5.41%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,018	2,018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.59%	3.62%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.65%	4.65%
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	2.38%	2.24%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.79%	3.02%
Expected long term return on assets, tax exempt accounts	7.00%	7.00%
Expected long term return on assets, taxable accounts	4.50%	4.50%

Retirement Benefits (Fair Value

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 261	$ 272	$ 284
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	598
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	18	9
Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		25
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	141	138
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	110
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	102	125
Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		463
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	159	147
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	25
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	18	9
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
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	141	138
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
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	102	125
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	573
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
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	0
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	110
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	102	125
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
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	0
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
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	0
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

Retirement Benefits (Benefit Pa

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 16
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	21
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	20
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	19
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	17
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	16
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	58
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	20
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	7
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	7
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	6
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	6
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 2

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue	$ 290	$ 965	$ 1,440

Reportable Segments (Operating

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues	$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080	$ 42,126	$ 55,691	$ 48,335
Cost of products sold									34,009	48,414	42,580
Depreciation, depletion and amortization									2,079	1,724	1,313
Equity in earnings from unconsolidated affiliates									276	332	236
Investment In ETP [Member]
Revenues									34,292	55,475	48,335
Cost of products sold									27,029	48,414	42,580
Depreciation, depletion and amortization									1,929	1,669	1,296
Equity in earnings from unconsolidated affiliates									469	332	236
Investment In Sunoco LP [Member]
Revenues									18,460	7,343	0
Cost of products sold									16,476	6,767	0
Depreciation, depletion and amortization									278	86	0
Investment in Lake Charles LNG [Member]
Depreciation, depletion and amortization									39	39	39
Corporate and Other [Member]
Depreciation, depletion and amortization									17	16	16
Adjustments and Eliminations [Member]
Revenues									(10,842)	(7,343)	(216)
Cost of products sold									(9,496)	(6,767)	0
Depreciation, depletion and amortization									(184)	(86)	(38)
Equity in earnings from unconsolidated affiliates									(193)	0	0
External Customers [Member]
Revenues									18,449	7,343	0
External Customers [Member] | Investment In ETP [Member]
Revenues									34,156	55,475	48,335
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues									18,449	7,343	0
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues									216	216	216
Intersegment [Member] | Investment In ETP [Member]
Revenues									136	0	0
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues									$ 11	$ 0	$ 0

Reportable Segments (Equity in

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ 276	$ 332	$ 236
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	469	332	236
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ (193)	$ 0	$ 0

Reportable Segments Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 5,935	$ 5,840	$ 4,367
Depreciation and amortization	(2,079)	(1,724)	(1,313)
Interest expense, net of interest capitalized	(1,643)	(1,369)	(1,221)
Gain on sale of AmeriGas common units	0	177	87
Impairment losses	339	370	689
Gains (losses) on interest rate derivatives	(18)	(157)	53
Non-cash unit-based compensation expense	(91)	(82)	(61)
Gains (losses) on interest rate derivatives	(65)	116	48
Losses on extinguishments of debt	(43)	(25)	(162)
Inventory valuation adjustments	(249)	(473)	3
Adjusted EBITDA related to discontinued operations	0	(27)	(76)
Adjusted EBITDA related to unconsolidated affiliates	(713)	(748)	(727)
Equity in earnings from unconsolidated affiliates	276	332	236
Non-operating environmental remediation	0	0	(168)
Other, net	22	(73)	(2)
Income from continuing operations before income tax expense	993	1,417	375
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	5,714	5,710	4,404
Depreciation and amortization	(1,929)	(1,669)	(1,296)
Equity in earnings from unconsolidated affiliates	469	332	236
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	719	332	0
Depreciation and amortization	(278)	(86)	0
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	196	195	187
Depreciation and amortization	(39)	(39)	(39)
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(104)	(97)	(43)
Depreciation and amortization	(17)	(16)	(16)
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(590)	(300)	(181)
Depreciation and amortization	184	86	38
Equity in earnings from unconsolidated affiliates	$ (193)	$ 0	$ 0

Reportable Segments (Assets Seg

Reportable Segments (Assets Segments)(Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets	$ 71,189	$ 64,279	$ 50,330
Investment In ETP [Member]
Assets	65,173	62,518	49,900
Investment In Sunoco LP [Member]
Assets	8,842	8,773	0
Investment in Lake Charles LNG [Member]
Assets	1,369	1,210	1,338
Corporate and Other [Member]
Assets	638	1,119	720
Adjustments and Eliminations [Member]
Assets	$ (4,833)	$ (9,341)	$ (1,628)

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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 8,536	$ 5,559	$ 3,342
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	8,167	5,494	3,327
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	491	154	0
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	1	1	2
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ (123)	$ (90)	$ 13

Reportable Segments (Advances t

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ 3,462	$ 3,659	$ 4,014
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	5,003	3,760	4,050
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ (1,541)	$ (101)	$ (36)

Reportable Segments ETP Revenue

Reportable Segments ETP Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue from External Customer [Line Items]
Revenues	$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080	$ 42,126	$ 55,691	$ 48,335
External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									18,449	7,343	0
Investment In ETP [Member]
Revenue from External Customer [Line Items]
Revenues									34,292	55,475	48,335
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,912	2,645	2,242
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,008	1,057	1,270
Investment In ETP [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									2,622	4,770	3,220
Investment In ETP [Member] | Liquids Transportation And Services [Member]
Revenue from External Customer [Line Items]
Revenues									3,232	3,730	2,025
Investment In ETP [Member] | Investment in Sunoco Logistics [Member]
Revenue from External Customer [Line Items]
Revenues									10,302	17,920	16,480
Investment In ETP [Member] | Retail Marketing [Member]
Revenue from External Customer [Line Items]
Revenues									12,478	22,484	21,004
Investment In ETP [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									2,738	2,869	2,094
Investment In ETP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									34,156	55,475	48,335
Investment In ETP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									$ 136	$ 0	$ 0

Reportable Segments Regency Rev

Reportable Segments Regency Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue from External Customer [Line Items]
Revenues	$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080	$ 42,126	$ 55,691	$ 48,335
External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									18,449	7,343	0
Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues									18,460	7,343	0
Investment In Sunoco LP [Member] | Retail [Member]
Revenue from External Customer [Line Items]
Revenues									8,257	3,095	0
Investment In Sunoco LP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									18,449	7,343	0
Investment In Sunoco LP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									11	0	0
Investment In Sunoco LP [Member] | Wholesale [Member]
Revenue from External Customer [Line Items]
Revenues									$ 10,203	$ 4,248	$ 0

Reportable Segments (Lake Charl

Reportable Segments (Lake Charles Revenue) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues	$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080	$ 42,126	$ 55,691	$ 48,335
External Customers [Member]
Revenues									18,449	7,343	0
Investment in Lake Charles LNG [Member] | External Customers [Member]
Revenues									$ 216	$ 216	$ 216

Quarterly Financial Data (Un120

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 9,536	$ 10,616	$ 11,594	$ 10,380	$ 13,481	$ 14,987	$ 14,143	$ 13,080	$ 42,126	$ 55,691	$ 48,335
Operating income	236	650	896	617	165	822	773	710	2,399	2,470	1,551
Net income (loss)	(138)	238	772	221	(294)	470	500	448	1,093	1,124	315
Limited Partners’ interest in net income	$ 312	$ 291	$ 298	$ 282	$ 111	$ 188	$ 163	$ 167	$ 1,183	$ 629	$ 196
Basic net income per limited partner unit	$ 0.30	$ 0.28	$ 0.28	$ 0.26	$ 0.11	$ 0.18	$ 0.15	$ 0.15	$ 1.11	$ 0.58	$ 0.18
Diluted net income per limited partner unit	$ 0.30	$ 0.28	$ 0.28	$ 0.26	$ 0.11	$ 0.18	$ 0.15	$ 0.15	$ 1.11	$ 0.57	$ 0.18

Quarterly Financial Data (Un121

Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Inventory Valuation Reserves	$ 171	$ 456
Impairment losses	$ 339	$ 370	$ 689

Supplemental Financial State122

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash and cash equivalents	$ 606	$ 847	$ 590	$ 372
Accounts receivable from related companies	119	35
Other current assets	572	287
Total current assets	5,410	6,139
Property, Plant and Equipment, Net	48,683	40,292
Advances to and investments in unconsolidated affiliates	3,462	3,659	4,014
Intangible assets, net	5,431	5,582
Goodwill	7,473	7,865	5,894
OTHER NON-CURRENT ASSETS, net	730	732
Total assets	71,189	64,279	50,330
Accounts payable to related companies	28	19
Interest payable	519	440
Accrued and other current liabilities	2,302	2,102
Total current liabilities	4,910	6,683
Long-term debt, less current maturities	36,837	29,477
Other non-current liabilities	1,069	1,193
COMMITMENTS AND CONTINGENCIES
General Partner	(2)	(1)
Limited Partners – Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding at December 31, 2015 and 2014, respectively)	(952)	648
Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively)	22	22
Accumulated other comprehensive loss	0	(5)
Total partners’ capital	(932)	664
Total liabilities and equity	71,189	64,279
Parent Company [Member]
Cash and cash equivalents	1	2	$ 8		$ 9
Accounts receivable from related companies	34	14
Other current assets	0	1
Total current assets	35	17
Property, Plant and Equipment, Net	20	0
Advances to and investments in unconsolidated affiliates	5,764	5,390
Intangible assets, net	6	10
Goodwill	9	9
OTHER NON-CURRENT ASSETS, net	10	12
Total assets	5,844	5,438
Accounts payable to related companies	111	11
Interest payable	66	58
Accrued and other current liabilities	1	3
Total current liabilities	178	72
Long-term debt, less current maturities	6,332	4,646
NOTE PAYABLE TO AFFILIATE	265	54
Other non-current liabilities	1	2
COMMITMENTS AND CONTINGENCIES
General Partner	(2)	(1)
Limited Partners – Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding at December 31, 2015 and 2014, respectively)	(952)	648
Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively)	22	22
Accumulated other comprehensive loss	0	(5)
Total partners’ capital	(932)	664
Total liabilities and equity	$ 5,844	$ 5,438

Supplemental Financial State123

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									$ (639)		$ (611)		$ (533)
Interest expense, net of interest capitalized									(1,643)		(1,369)		(1,221)
Equity in earnings from unconsolidated affiliates									276		332		236
Gains on interest rate derivatives									(18)		(157)		53
Losses on extinguishments of debt									(43)		(25)		(162)
Other, net									22		(11)		(1)
Income tax expense (benefit)									(100)	[1]	357	[1]	93
NET INCOME ATTRIBUTABLE TO PARTNERS									1,189		633		196
General Partner’s interest in net income									3		2		0
Class D Unitholder’s interest in net income									3		2		0
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 312	$ 291	$ 298	$ 282	$ 111	$ 188	$ 163	$ 167	1,183		629		196
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									(112)		(111)		(56)
Interest expense, net of interest capitalized									(294)		(205)		(210)
Equity in earnings from unconsolidated affiliates									1,601		955		617
Gains on interest rate derivatives									0		0		9
Losses on extinguishments of debt									0		0		(157)
Other, net									(5)		(5)		(8)
INCOME BEFORE INCOME TAXES									1,190		634		195
Income tax expense (benefit)									1		1		(1)
NET INCOME ATTRIBUTABLE TO PARTNERS									1,189		633		196
General Partner’s interest in net income									(3)		(2)		0
Class D Unitholder’s interest in net income									3		2		0
LIMITED PARTNERS’ INTEREST IN NET INCOME									$ 1,183		$ 629		$ 196
[1]	Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries.

Supplemental Financial State124

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 3,068	$ 3,175	$ 2,419
Cash paid for Bakken Pipeline Transaction	(835)	(2,367)	(405)
Proceeds from the sale of other assets	26	62	89
Contributions to unconsolidated affiliates	45	334	3
Capital expenditures	(9,386)	(5,381)	(3,505)
Net cash used in investing activities	(10,094)	(6,795)	(2,347)
Proceeds from borrowings	26,455	18,375	12,934
Repayments of long-term debt	(19,828)	(13,886)	(11,951)
Distributions to partners	(1,090)	(821)	(733)
Redemption of Preferred Units	0	0	(340)
Units repurchased under buyback program	(1,064)	(1,000)	0
Debt issuance costs	(75)	(77)	(87)
Net cash provided by financing activities	6,785	3,877	146
Increase (decrease) in cash and cash equivalents	(241)	257	218
Cash and cash equivalents, beginning of period	847	590	372
Cash and cash equivalents, end of period	606	847	590
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	1,103	816	768
Cash paid for Bakken Pipeline Transaction	(817)	0	0
Proceeds from the sale of other assets	0	0	1,332
Contributions to unconsolidated affiliates	0	118	8
Capital expenditures	(19)	0	0
Payments to Acquire Additional Interest in Subsidiaries	0	(800)	0
Payments received on note receivable from affiliate	0	0	166
Net cash used in investing activities	(836)	(918)	1,490
Proceeds from borrowings	3,672	3,020	2,080
Repayments of long-term debt	(1,985)	(1,142)	(3,235)
Distributions to partners	(1,090)	(821)	(733)
Proceeds from Related Party Debt	210	54	0
Redemption of Preferred Units	0	0	(340)
Units repurchased under buyback program	(1,064)	(1,000)	0
Debt issuance costs	(11)	(15)	(31)
Net cash provided by financing activities	(268)	96	(2,259)
Increase (decrease) in cash and cash equivalents	(1)	(6)	(1)
Cash and cash equivalents, beginning of period	2	8
Cash and cash equivalents, end of period	$ 1	$ 2	$ 8

Supplemental Financial State125

Supplemental Financial Statement Information Supplemental Financial Information (Parenthetical) (Details) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Authorized	1,044,767,336	1,077,533,798
Issued	1,044,767,336	1,077,533,798
Outstanding	1,044,767,336	1,077,533,798	1,119,800,000	1,119,800,000
Class D Units [Member]
Authorized	2,156,000	3,080,000
Issued	2,156,000	3,080,000
Outstanding	2,156,000	3,080,000