View Filing Data

Equity in earnings from unconsolidated affiliates

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)

276

332

236

Gain on sale of AmeriGas common units

177

Losses on extinguishments of debt

(43)

(25)

(162)

Gains (losses) on interest rate derivatives

(18)

(157)

Non-operating environmental remediation

(168)

Other, net

(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]

INCOME FROM CONTINUING OPERATIONS

1,093

1,060

282

Income from discontinued operations

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

Class D Unitholder’s interest in net income

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 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 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 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

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.

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 Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2015

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 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.

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

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

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 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 Remediation

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

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

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.

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2015, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2015 and 2014 based on inputs used to derive their fair values:



	Fair Value Measurements at December 31, 2015
	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 December 31, 2014
	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	)

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	%

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

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2015.



Balance, December 31, 2014	$	(16	)
Net unrealized gains included in other income (expense)	11
Balance, December 31, 2015	$	(5	)

Contributions in Aid of Construction Cost

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

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses

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

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by 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

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

Income Taxes

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

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

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

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

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

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

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

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

Unit-Based Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pensions and Other Postretirement Benefit Plans

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

Allocation of Income

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

Acquisitions and Related Transactions

12 Months Ended

Dec. 31, 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.

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

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Investments In Affiliates

Advances to and Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2015

Investment In Affiliates [Abstract]

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 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

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	12 Months Ended
Redeemable Preferred Units	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

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 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

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]

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

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

Environmental Remediation

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


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


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


•	Currently operating Sunoco, Inc. retail sites.


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

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2015, Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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



	December 31,
	2015		2014
Current	$	42	$	41
Non-current	326		360
Total environmental liabilities	$	368	$	401

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

During the years ended December 31, 2015 and 2014, the Partnership recorded $38 million and $48 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position.

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

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

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, 2015	December 31, 2014
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

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Compensation and Retirement Disclosure [Abstract]

Retirement Benefits

12 Months Ended

Dec. 31, 2015

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 postretirement 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	12 Months Ended
Related Party Transactions	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.

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

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.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

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 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 Accounting Policies and Balance Sheet Detail (Policy)

12 Months Ended

Dec. 31, 2015

New Accounting Pronouncements, Policy [Policy Text Block]

Use of Estimates

New Accounting Pronouncements

Revenue Recognition

Investment in ETP

Investment in Sunoco LP

Investment in Lake Charles LNG

Regulatory Accounting - Regulatory Assets and Liabilities

Regulatory Accounting – Regulatory Assets and Liabilities

Cash, Cash Equivalents and Supplemental Cash Flow Information

Accounts Receivable

Inventories

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

Exchanges

Property, Plant and Equipment

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

Advances to and Investments in Affiliates

Other Non-Current Assets, net

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

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

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.

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

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

Accrued and Other Current Liabilities Policy [Text Block]

Redeemable Noncontrolling Interest [Text Block]

Redeemable Noncontrolling Interests

Environmental Costs, Policy [Policy Text Block]

Environmental Remediation

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

Contributions In Aid Of Construction Costs Policy Text Block

Contributions in Aid of Construction Cost

Shipping and Handling Costs

Costs and Expenses

Issuances of Subsidiary Units

Income Taxes

Accounting for Derivative Instruments and Hedging Activities

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

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Unit-Based Compensation

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

Pensions and Other Postretirement Benefit Plans

Allocation of Income (Loss)

Allocation of Income

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

12 Months Ended

Dec. 31, 2015

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



	Fair Value Measurements at December 31, 2015
	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 December 31, 2014
	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



Balance, December 31, 2014	$	(16	)
Net unrealized gains included in other income (expense)	11
Balance, December 31, 2015	$	(5	)

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]



	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

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.

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

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.

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
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Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates

Advances to and Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2015

Investment In Affiliates [Abstract]

Summarized Financial Information



	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 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 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



2016	$	308
2017	1,189
2018	2,515
2019	5,007
2020	4,729
Thereafter	23,316
Total	$	37,064

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
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-Subparagraph (SX 210.5-02.22)
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Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]

Equity (Tables)

12 Months Ended

Dec. 31, 2015

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

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
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-Section 45
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-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e689-108580

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

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

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

12 Months Ended

Dec. 31, 2015

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 (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]



	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]



	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]



	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, 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]



	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 Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Offsetting Assets [Table Text Block]



		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, 2015	December 31, 2014
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

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

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-Publisher FASB
-Name Accounting Standards Codification
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Compensation and Retirement Disclosure [Abstract]

Retirement Benefits Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

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.

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments



	Pension Benefits
Years	Funded Plans		Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
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)

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 (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

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 (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					9.0
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 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

Impairment of Intangible Assets, Finite-lived

Asset Retirement Obligation, Legally Restricted Assets, Fair Value

Deferred Tax Liabilities, Gross

4,945

$ 4,653

Long-term Debt, Fair Value

33,220

31,680

Goodwill, Period Increase (Decrease)

(392)

205

370

Goodwill acquired

2,340

Investment In ETP [Member]

7,473

7,865

$ 5,894

Long-term Debt

36,968

30,485

205

370

Goodwill acquired

2,340

Liquids Transportation And Services [Member]

5,428

7,642

5,856

Interstate Transportation and Storage [Member]

(106)

Retail Marketing [Member]

(99)

Excise Taxes Collected

$ 3,050

2,460

$ 2,220

Amount Reclassed From ASU 2015-17 [Member]

Deferred Tax Liabilities, Gross

$ 85

Susser Merger [Member]

$ 1,734

PVR Acquisition [Member]

^[1]

$ 370

[1]	(1)None of the goodwill is expected to be deductible for tax purposes.

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 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 Inventory) (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

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) (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 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, 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 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 Non-Current Assets, net) (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Unamortized financing costs(1)

^[1]

$ 29

$ 41

Regulatory assets

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 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 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 Amortization Expense) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
2016	$ 242
2017	242
2018	241
2019	239
2020	239
Gross Carrying Amount	$ 6,217	$ 6,100

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 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 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

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, 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 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 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				$ 8.00
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 Transactions Acquisitions (2015 Narrative) (Details) $ in Millions, gallons in Billions	1 Months Ended				3 Months Ended		12 Months Ended
	Oct. 31, 2015 USD ($) shares	Jul. 31, 2015 USD ($) shares	Apr. 30, 2015 USD ($) gallons shares	Mar. 31, 2015 USD ($) shares	Mar. 31, 2016 USD ($) shares	Dec. 31, 2014 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
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 Transactions Acquisitions (2014 Narrative) (Details) $ / shares in Units, $ in Millions	1 Months Ended							3 Months Ended								6 Months Ended	12 Months Ended
	Oct. 31, 2015 USD ($)	Apr. 30, 2015 USD ($) shares	Oct. 31, 2014 USD ($) shares	Aug. 31, 2014 USD ($) shares	Jul. 31, 2014 USD ($)	Mar. 21, 2014 USD ($) $ / shares shares	Feb. 28, 2014 shares	Dec. 31, 2015 USD ($) shares	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) shares	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2014 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 01, 2014	Aug. 29, 2014	Jul. 01, 2014 USD ($)	Jan. 10, 2014 USD ($) 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 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 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]

Property, plant and equipment

Current assets

$ 120

1,295

Long-term debt obligations, less current maturities

Other assets

Current liabilities

116

499

Other non-current liabilities

Eagle Rock Midstream Acquisition [Member]

Total liabilities assumed

Total assets acquired

1,468

627

Total consideration

$ 841

PVR Acquisition [Member]

Property, plant and equipment

Current assets

$ 149

2,716

Investments in unconsolidated affiliates

^[1]

370

Intangible assets

2,717

Other assets

Total assets acquired

6,032

Current liabilities

168

Long-term debt obligations, less current maturities

1,788

Premium related to senior notes

Other non-current liabilities

Total liabilities assumed

2,085

Total consideration

$ 3,947

Susser Merger [Member]

Property, plant and equipment

Current assets

$ 446

1,069

Long-term debt obligations, less current maturities

1,734

Intangible assets

611

Other assets

Total assets acquired

3,877

Current liabilities

377

564

Deferred income taxes

488

Other non-current liabilities

Noncontrolling interest

626

Total liabilities assumed

2,094

Total consideration

1,783

Cash received

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

Amount before tax of income (loss) from a discontinued operation. Includes, but is not limited to, the income (loss) from operations during the phase-out period, gain (loss) on disposal, gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and adjustments to a prior period gain (loss) on disposal.

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended	12 Months Ended
	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 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 (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

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

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

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

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

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