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Document And Entity Information $ in Millions	12 Months Ended
Document And Entity Information $ in Millions	Dec. 31, 2015 USD ($) shares
Document Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Entity Registrant Name	Panhandle Eastern Pipe Line Co LP
Entity Central Index Key	0000076063
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float \| $	$ 0
Entity Common Stock, Shares Outstanding \| shares	0

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 3	$ 32
Accounts receivable, net	48	58
Accounts receivable from related companies	172	128
Exchanges receivable	5	11
Inventories	113	119
Other current assets	9	10
Total current assets	350	358
Property, plant and equipment
Total property, plant and equipment	3,338	3,395
Accumulated depreciation	(286)	(269)
Net property, plant and equipment	3,052	3,126
Investments in unconsolidated affiliates	15	1,443
Goodwill	923	1,152
NOTE RECEIVABLE FROM RELATED PARTY	574	0
OTHER NON-CURRENT ASSETS, net	122	109
Due from Related Parties, Noncurrent	258	0
Total assets	5,294	6,188
Current liabilities:
Current maturities of long-term debt	1	1
Accounts payable and accrued liabilities	3	6
Accounts payable to related companies	99	38
Exchanges payable	94	114
Accrued interest	12	12
Customer Advances and Deposits, Current	9	10
Other current liabilities	55	56
Total current liabilities	273	237
Long-term debt, less current maturities	1,165	1,189
Deferred income taxes	695	1,508
ADVANCES FROM AFFILIATES	0	51
Other non-current liabilities	222	278
Commitments and contingencies
Partners’ capital:
Partners’ capital	2,937	2,925
Accumulated other comprehensive income	2	0
Total partners’ capital	2,939	2,925
Total liabilities and partners’ capital	$ 5,294	$ 6,188

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES:
Transportation and storage of natural gas	$ 528	$ 555	$ 576
LNG terminalling	0	0	216
Other	20	26	293
Total operating revenues	548	581	1,085
OPERATING EXPENSES:
Cost of Goods Sold	4	3	228
Operating, maintenance and general	216	209	248
General and Administrative Expense	42	46	113
Depreciation and amortization	133	130	189
Goodwill Impairment	0	0	689
Total operating expenses	395	388	1,467
Operating Income (Loss)	153	193	(382)
OTHER INCOME (EXPENSE):
Interest expense, net	(50)	(66)	(111)
Income (loss) from unconsolidated affiliates	26	(12)	15
Interest income — affiliates	23	23	9
Other, net	5	5	(3)
Total other expenses, net	4	(50)	(90)
Income (Loss) from Continuing Operations Before Income Tax Expense	157	143	(472)
Income tax expense from continuing operations	32	146	98
Income (Loss) from Continuing Operations	125	(3)	(570)
Income From Discontinued Operations	0	0	35
Net Income (Loss)	125	(3)	(535)
Net Income (Loss) Attributable to Noncontrolling Interest	0	6	(36)
Net Income (Loss) Attributable to Partners	$ 125	$ (9)	(499)
Successor
OPERATING EXPENSES:
Goodwill Impairment			$ 689

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Income and Comprehensive Income [Line Items]
Net income (loss)	$ 125	$ (3)	$ (535)
Other comprehensive income (loss), net of tax:
Change in fair value of commodity hedges	0	0	(3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	0	0	(6)
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $0, $1, and ($15), respectively	2	(3)	25
Total other comprehensive income (loss)	2	(3)	28
Comprehensive income (loss)	$ 127	$ (6)	$ (507)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Income Taxes - Actuarial Gain Loss - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax	$ 0	$ 1	$ (15)

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Trunkline LNG Transaction [Member]	Panhandle Merger [Member]	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Trunkline LNG Transaction [Member]	Accumulated Other Comprehensive Income (Loss) Panhandle Merger [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member] Trunkline LNG Transaction [Member]	Noncontrolling Interest [Member] Panhandle Merger [Member]	Limited Partner [Member]	Limited Partner [Member] Trunkline LNG Transaction [Member]	Limited Partner [Member] Panhandle Merger [Member]
Balance at Dec. 31, 2012	$ 4,028			$ (9)			$ (13)			$ 4,050
Dividends paid to Southern Union stockholders	(313)			0			(313)			0
Other comprehensive income, net of tax	11			12			(1)			0
SUGS Contribution	(135)			0			(135)			0
Net income (loss)	(535)			0			(36)			(499)
Lake Charles LNG Transaction	12			0			12			0
Balance at Dec. 31, 2013	3,068			3			(486)			3,551
Other comprehensive income, net of tax	(2)			(2)			0			0
Net income (loss)	(3)			0			6			(9)
Distribution to partners	(102)			0			0			(102)
Unit-based compensation expense	1			0			0			1
Panhandle Merger	6	$ (43)	$ 0	0	$ 0	$ (1)	0	$ (23)	$ 503	6	$ (20)	$ (502)
Balance at Dec. 31, 2014	2,925			0			0			2,925
Other comprehensive income, net of tax	2			2			0			0
Net income (loss)	125			0			0			125
Distribution to partners	(125)			0			0			(125)
Unit-based compensation expense	2			0			0			2
Panhandle Merger	38			0			0			38
Contribution to SUG Holding	28			0			0			28
Balance at Dec. 31, 2015	$ 2,939			$ 2			$ 0			$ 2,937

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Cash Flows [Abstract]
Proceeds from SUGS Contribution	$ 0	$ 0	$ 482
OPERATING ACTIVITIES:
Net income (loss)	125	(3)	(535)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	133	130	189
Goodwill Impairment	0	0	689
Deferred income taxes	14	(139)	181
Amortization of deferred financing fees	(23)	(22)	(30)
Unrealized gain on derivatives	0	(25)	(52)
(Income) loss from unconsolidated affiliates	(26)	12	(15)
Distributions of earnings received from unconsolidated affiliates	9	6	15
Other non-cash	13	6	33
Changes in operating assets and liabilities	(69)	192	(159)
Net cash flows provided by operating activities	176	157	316
INVESTING ACTIVITIES:
Proceeds from SUGS Contribution	0	20	0
Proceeds from sale of MGE assets, net of transaction costs	0	0	1,008
Proceeds from affiliates	40	0	0
Increase (Decrease) in Notes Receivable, Related Parties, Current	(40)	0	0
Capital expenditures	(128)	(109)	(250)
Distributions from unconsolidated affiliates in excess of cumulative earnings	46	65	39
Other	2	(16)	5
Net cash flows (used in) provided by investing activities	(80)	(40)	1,284
FINANCING ACTIVITIES:
Distribution Made to Limited Partner, Cash Distributions Paid	125	102	313
Issuance of loans from affiliates	0	0	1,669
Repayments of loans from affiliates	0	0	(975)
Repayment of long-term debt	0	0	(1,795)
Net change in revolving credit facilities	0	0	(210)
Other	0	0	(8)
Net cash flows used in financing activities	(125)	(102)	(1,632)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(29)	15	(32)
CASH AND CASH EQUIVALENTS, beginning of period	32	17	49
CASH AND CASH EQUIVALENTS, end of period	$ 3	$ 32	$ 17

Description of the Business	12 Months Ended
Description of the Business	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Business	OPERATIONS AND ORGANIZATION: Panhandle Eastern Pipe Line Company, LP (“PEPL”) and its subsidiaries (the “Company”) are primarily engaged in interstate pipelines that transport natural gas from the Gulf of Mexico, south Texas and the panhandle region of Texas and Oklahoma to major United States markets in the Midwest and Great Lakes regions and storage of natural gas and are subject to the rules and regulations of the FERC. The Company’s subsidiaries are Trunkline Gas Company, LLC (“Trunkline”), Sea Robin Pipeline Company, LLC (“Sea Robin”) and Pan Gas Storage LLC (“Southwest Gas”). Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETP, owns a 1% general partnership interest in PEPL and ETP indirectly owns a 99% limited partnership interest in PEPL. The Company’s consolidated results of operations for the year ended December 31, 2013 includes Southern Union’s former natural gas gathering and processing operations, which were contributed to an affiliate in 2013, and Southern Union’s former local distribution operations, which were sold in 2013 and were presented as discontinued operations. Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Basis of Presentation. The Company’s consolidated financial statements have been prepared in accordance with GAAP. The consolidated financial statements include the accounts of all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The Company does not apply regulatory-based accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. If regulatory-based accounting policies were applied, certain transactions would be recorded differently, including, among others, recording of regulatory assets, the capitalization of an equity component of invested funds on regulated capital projects and depreciation differences. The Company periodically reviews its level of discounting and negotiated rate contracts, the length of rate moratoriums and other related factors to determine if the regulatory-based authoritative guidance should be applied.

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 disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Pronouncements. In May 2014, the 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 Company is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

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 of December 31, 2014, $3 million in current deferred tax assets were reclassified in the consolidated balance sheet from other current assets to deferred income taxes liability.

Cash and Cash Equivalents. Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. The Company places cash deposits and temporary cash investments with high credit quality financial institutions. At times, cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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



	Years Ended December 31,
	2015			2014		2013
Non-cash investing activities:
Contribution from affiliate	$	—		$	376	$	—
Note receivable issued in exchange for investment in ETP	(1,369		)	—		—
Settlement of affiliate liability	793			—		—
Supplemental cash flow information:
Accrued capital expenditures	$	21		$	15	$	13
Cash paid for interest, net of interest capitalized	76			75		142
Cash received for interest on note receivable from affiliate	16			—		—

Inventories. System natural gas and operating supplies consist of natural gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while natural gas owed back to customers is valued at market. The natural gas held for operations that the Company does not expect to consume in its operations in the next twelve months is reflected in non-current assets.

The following table presents the components of inventory:



	December 31,
	2015		2014
Natural gas ⁽¹⁾	$	98	$	105
Materials and supplies	15		14
	$	113	$	119


⁽¹⁾	Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 TBtu, respectively.

Natural Gas Imbalances. Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. The Company records natural gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system natural gas balances, respectively. Net imbalances that have reduced system natural gas are valued at the cost basis of the system natural gas, while net imbalances that have increased system natural gas and are owed back to customers are priced, along with the corresponding system natural gas, at market.

Fuel Tracker. The fuel tracker is the cumulative balance of compressor fuel volumes owed to the Company by its customers or owed by the Company to its customers. The customers, pursuant to each pipeline’s tariff and related contracts, provide all compressor fuel to the pipeline based on specified percentages of the customer’s natural gas volumes delivered into the pipeline. The percentages are designed to match the actual natural gas consumed in moving the natural gas through the pipeline facilities, with any difference between the volumes provided versus volumes consumed reflected in the fuel tracker. The tariff of Trunkline Gas, in conjunction with the customers’ contractual obligations, allows the Company to record an asset and direct bill customers for any fuel ultimately under-recovered. The other FERC-regulated PEPL entities record an expense when fuel is under-recovered or record a credit to expense to the extent any under-recovered prior period balances are subsequently recouped as they do not have such explicit billing rights specified in their tariffs. Liability accounts are maintained for net volumes of compressor fuel natural gas owed to customers collectively. The pipelines’ fuel reimbursement is in-kind and non-discountable.

Property, Plant and Equipment.

The following table presents the components of property, plant and equipment:



		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

Additions. Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Such indirect construction costs primarily include capitalized interest costs and labor and related costs of departments associated with supporting construction activities. The indirect capitalized labor and related costs are largely based upon results of periodic time studies or management reviews of time allocations, which provide an estimate of time spent supporting construction projects. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.

Retirements. When ordinary retirements of property, plant and equipment occur, the original cost less salvage value is removed by a charge to accumulated depreciation and amortization, with no gain or loss recorded. When entire regulated operating units of property, plant and equipment are retired or sold, the original cost less salvage value and related accumulated depreciation and amortization accounts are removed, with any resulting gain or loss recorded in earnings.

Depreciation. The Company computes depreciation expense using the straight-line method.

Interest Cost Capitalized. The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets.

Asset Impairment. An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.

Goodwill. Goodwill resulting from a purchase business combination is tested for impairment at the Company’s reporting unit level at least annually during the fourth quarter by applying a fair-value based test. The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value. 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.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014. The Company’s annual goodwill impairment test for the year ended December 31, 2013 resulted in a $689 million goodwill impairment related to the Lake Charles LNG reporting unit.

Changes in the carrying amount of goodwill were as follows:



	Total
Balance, December 31, 2013	$	1,336
Lake Charles LNG Transaction	(184		)
Balance, December 31, 2014	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	$	923

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP and other affiliates. Other income includes interest income on a note receivable from a related party.

PEPL and certain of its subsidiaries are not treated as separate taxpayers for federal and certain state income tax purposes. Instead, the Company’s income is taxable to its parent, SUG Holding Company. The Company has entered into a tax sharing agreement with SUG Holding Company pursuant to which the Company will be required to make payments to SUG Holding Company in order to reimburse SUG Holding Company for federal and state taxes that it pays on the Company’s income, or to receive payments from SUG Holding Company to the extent that tax losses generated by the Company are utilized by SUG Holding Company. In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by SUG Holding Company. The Company’s liability generally is equal to the liability that the Company and its subsidiaries would have incurred based upon the Company’s taxable income if the Company was a taxpayer filing separately from SUG Holding Company, except that the Company will receive credit under an intercompany note for any increased liability resulting from its tax basis in its assets having been reduced as a result of the like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended. The tax sharing agreement may be amended from time to time.

Investments in Unconsolidated Affiliates. Investments in unconsolidated affiliates over which the Company may exercise significant influence are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. A loss in value of an investment, other than a temporary decline, is recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments.

Other Current Liabilities. Accrued and other current liabilities consisted of the following:



	December 31,
	2015		2014
Accrued capital expenditures	$	21	$	15
Accrued property taxes	5		9
Other	29		32
Total other current liabilities	$	55	$	56

Environmental Expenditures. Environmental expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

Revenues. The Company’s revenues from transportation and storage 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 are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered for the customer, based on the tariff of that particular PEPL entity, with any differences in volumes received and delivered resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers. Because PEPL is subject to FERC regulation, revenues collected during the pendency of a rate proceeding may be required by FERC to be refunded in the final order. PEPL establishes reserves for such potential refunds, as appropriate.

Accounts Receivable and Allowance for Doubtful Accounts. The Company has a concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company manages trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security.

The Company establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.

Amounts related to the allowance for doubtful accounts were not material as of and during the years ended December 31, 2015 and 2014.

The following table presents the relative contribution to the Company’s total operating revenue from continuing operations of each customer that comprised at least 10% of its operating revenues:



	Years Ended December 31,
	2015		2014		2013
Customer A⁽¹⁾	—	%	—	%	10	%
Customer B⁽²⁾	—		—		22
Customer C	11		11		6
Customer D	10		—		—
Other top 10 customers	28		40		20
Remaining customers	51		49		42
Total percentage	100	%	100	%	100	%


⁽¹⁾	SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.


⁽²⁾	Customer B is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

Accumulated Other Comprehensive Income. The main components of accumulated other comprehensive income are a net actuarial gain and prior service costs on pension and other postretirement benefit plans at December 31, 2015.

Retirement Benefits. 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 other comprehensive income in partners’ capital in the year in which the change occurs.

Derivatives and Hedging Activities. All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in accumulated other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use.

Fair Value Measurement. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which is primarily comprised of credit risk (both the Company’s own credit risk and counterparty credit risk) and the risks inherent in the inputs to any applicable valuation techniques. The Company places more weight on current market information concerning credit risk (e.g. current credit default swap rates) as opposed to historical information (e.g. historical default probabilities and credit ratings). These inputs can be readily observable, market corroborated, or generally unobservable. The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value, is as follows:


•	Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;

•

Level 2 – Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and

•

Level 3 – Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy.

The Company did not have any material assets or liabilities that are measured at fair value on a recurring basis at December 31, 2015 and 2014. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value.

Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred, if a reasonable estimate of fair value can be made. Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation, and profit margins that third parties would demand to settle the amount of the future obligation. The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated. Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset. The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability. To the extent the Company is permitted to collect and has reflected in its financials amounts previously collected from customers and expensed, such amounts serve to reduce what would be reflected as capitalized costs at the initial establishment of an ARO.

Income Taxes. Income taxes are accounted for 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.

As a limited partnership, the Company is treated as a disregarded entity for federal income tax purposes. Accordingly, the Company and its subsidiaries are not treated as separate taxpayers; instead, their income is directly taxable to the Company’s parent. Under the Company’s tax sharing arrangement with its parent, the Company pays its share of taxes based on taxable income, which will generally equal the liability that the Company would have incurred as a separate taxpayer.

Commitments and Contingencies. The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability.

Mergers and Other Transactions

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Business Combinations Disclosure

MERGERS, DECONSOLIDATIONS AND RELATED TRANSACTIONS:

2015 Transactions

Regency Merger

In April 2015, ETP completed its acquisition of Regency. Under the terms of the definitive merger agreement, holders of Regency common units received 0.4066 ETP Common Units for each Regency common unit. Regency unitholders also received at closing an additional $0.32 per common unit in the form of ETP Common Units (based on the price for ETP Common Units prior to the merger closing). The Regency common units and Regency Class F units converted to 15.5 million ETP common units. The Company’s investment was accounted for in our consolidated financial statements using the equity method.

Investment in ETP

Effective September 1, 2015, the Company exchanged its investment in the ETP common units received during the Regency transaction, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion.

2014 Transactions

Panhandle Merger

On January 10, 2014, the Company consummated a merger with Southern Union, the indirect parent of the Company, and PEPL Holdings, the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings, a wholly-owned subsidiary of Southern Union, were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and Floating Rate 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 the Company and noncontrolling interest in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units) and ETP (2.2 million common units). In connection with the Panhandle Merger, the Company also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Lake Charles LNG Transaction

On February 19, 2014, PEPL transferred to ETP all of the interests in Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the cancellation of a $1.09 billion note payable to ETP that was assumed by the Company in the merger with Southern Union on January 10, 2014. Also on February 19, 2014, ETE and ETP completed the transfer to ETE of Lake Charles LNG from ETP in exchange for the redemption by ETP of 18.7 million ETP common units held by ETE. The transaction was effective as of January 1, 2014, at which time PEPL deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Company’s consolidated financial statements due to the expected continuing involvement among the entities.

2013 Transactions

Sale of Southern Union’s Distribution Operations

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

MGE and NEG have been classified as discontinued operations in the consolidated statements of operations.

Summarized financial information for MGE and NEG is as follows:



	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 31.4 million Regency common units to Southern Union, (ii) the issuance of 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units had the same rights, terms and conditions as the Regency common units, except that the Company, as successor to Southern Union, did not receive distributions on the Regency Class F units.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section 50
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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 4: 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 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions

RELATED PARTY TRANSACTIONS:

Accounts receivable from related companies reflected on the consolidated balance sheets primarily related to services provided to ETE, ETP and other affiliates. Accounts payable to related companies and advance from affiliates reflected on the consolidated balance sheets related to various services provided by ETP and other affiliates.

The following tables provide a summary of related party activity included in our consolidated statements of operations:



	Years Ended December 31,
	2015		2014			2013
Operating revenues	$	18	$	33		$	56
Cost of natural gas and other energy	—		—			17
Operating and maintenance	16		16			—
General and administrative	31		33			71
Interest expense, net	—		—			(31		)
Interest income — affiliates	23		23			9
Income (loss) from unconsolidated affiliates	26		(12		)	15

The following table provides a summary of distributions received from related parties:



	Years Ended December 31,
	2015		2014		2013
Distributions related to investment in:
ETP	$	39	$	9	$	8
Regency	16		61		44

- Definition

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

+ References + Details

INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Notes)

12 Months Ended

Dec. 31, 2015

Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]

Investments in and Advances to Affiliates, Schedule of Investments [Text Block]

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The Company’s investment in Regency consisted of 31.4 million Regency common units and 6.3 million Regency Class F units at December 31, 2014. In connection with the merger of ETP and Regency in April 2015, the Regency common units and Regency Class F units converted to 15.5 million ETP common units. The Company’s investment was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrues interest annually at 4.75% and is due on September 1, 2035. In connection with this transaction, the Company also recorded a reduction in goodwill of $229 million and net deferred tax liabilities of $825 million, which amounts were associated with the exchanged ETP common units as a result of previous transactions whereby the Company had acquired ETP common units (and previously, Regency common units and Class F units) in exchange for other assets.

The following tables present aggregated selected balance sheet and income statement data for ETP (on a 100% basis for all periods presented).



	December 31,
	2015		2014
Current assets	$	4,698	$	6,029
Property, plant and equipment, net	45,087		38,907
Other assets	15,388		17,582
Total assets	$	65,173	$	62,518

Current liabilities	$	4,121	$	6,585
Non-current liabilities	34,021		30,622
Equity	27,031		25,311
Total liabilities and equity	$	65,173	$	62,518



	Years Ended December 31,
	2015		2014		2013
Revenue	$	34,292	$	55,475	$	48,335
Operating income	2,259		2,443		1,619
Net income	1,521		1,299		746

The Company has other equity method investments which are not, individually or in the aggregate, significant to our consolidated financial statements.

Debt Obligations

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

The following table sets forth the debt obligations of the Company:



	December 31,
	2015		2014
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		400
8.125% Senior Notes due 2019	150		150
7.60% Senior Notes due 2024	82		82
7.00% Senior Notes due 2029	66		66
8.25% Senior Notes due 2029	33		33
Floating Rate Junior Subordinated Notes due 2066	54		54
Other long term debt	5		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company’s consolidated debt obligations at December 31, 2015 and 2014 was $1.20 billion and $1.24 billion, respectively. The fair value of the Company’s consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

As of December 31, 2015, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
Thereafter	240
Total	$	1,090

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, PEPL assumed Southern Union’s long-term debt obligations. As of December 31, 2015, the long-term debt assumed in the Panhandle Merger consisted of $82 million in aggregate principal amount of 7.60% Senior Notes due 2024, $33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066 outstanding. The amounts recorded in the consolidated balance sheet also reflected unamortized fair value adjustments, which were $12 million in the aggregate at December 31, 2015.

Floating Rate Junior Subordinated Notes

The interest rate on the remaining portion of PEPL’s $600 million junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.295% at December 31, 2015.

Compliance With Our Covenants

The Company’s notes are subject to certain requirements, such as the maintenance of a fixed charge coverage ratio and a leverage ratio, which if not maintained, restrict the ability of the Company to make certain payments and impose limitations on the ability of the Company to subject its property to liens. Other covenants impose limitations on restricted payments, including dividends and loans to affiliates, and additional indebtedness. As of December 31, 2015, the Company is in compliance with these covenants.

Benefits

12 Months Ended

Dec. 31, 2015

Postemployment Benefits [Abstract]

Benefits

RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the years ended December 31, 2015 and 2014 reflect the impact of changes the Company 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 the Company’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of the Company 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.

Obligations and Funded Status

Other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following tables contain information at the dates indicated about the obligations and funded status of the Company’s other postretirement plans.



	December 31,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	24		$	25
Interest cost	1			1
Actuarial (gain) loss	(2		)	1
Benefits paid, net	(2		)	(2		)
Dispositions	—			(1		)
Benefit obligation at end of period	$	21		$	24
Change in plan assets:
Fair value of plan assets at beginning of period	$	114		$	110
Return on plan assets and other	(1		)	4
Employer contributions	7			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			(5		)
Fair value of plan assets at end of period	$	118		$	114

Amount overfunded at end of period ⁽¹⁾	$	(97	)	$	(90	)

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(10	)	$	(16	)
Prior service cost	14			15
	$	4		$	(1	)


⁽¹⁾	Recorded as a non-current asset in the consolidated balance sheets.

Components of Net Periodic Benefit Cost

The following tables set forth the components of net periodic benefit cost of the Company’s postretirement benefit plan for the periods presented:



	Years Ended December 31,
	2015			2014			2013
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(5		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(4	)	$	(4	)

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2016 is $1 million.

Assumptions. The weighted-average discount rate used in determining benefit obligations was 3.84% and 3.68% at December 31, 2015 and 2014, respectively.

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



	Years Ended December 31,
	2015		2014		2013
Discount rate	3.60	%	4.29	%	3.66	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets with proper consideration for diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. 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 check for reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by the plans are shown in the table below:



	December 31,
	2015		2014
Health care cost trend rate	8.10	%	7.60	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71	%	4.90	%
Year that the rate reaches the ultimate trend rate	2021		2021

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:



	One Percentage Point Increase		One Percentage Point Decrease
Effect on accumulated postretirement benefit obligation	$	1	$	(1	)

Plan Assets. The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, the Company 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%. These target allocations are monitored by the Investment Committee of ETP’s Board of Directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.

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



	December 31,
	2015		2014
Cash and cash equivalents	$	3	$	3
Mutual fund ⁽¹⁾	115		111
Total	$	118	$	114


⁽¹⁾	This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities and 10% cash. As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% cash.

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their fair values are based on active market quotes.

Contributions. The Company expects to make $8 million contributions to its other postretirement plans in 2016 and annually thereafter until modified by rate case proceedings.

Benefit Payments. The Company’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.



Years	Expected Benefit Payments
2016	$	2
2017	2
2018	1
2019	1
2020	1
2021 – 2025	6

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 plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. The Company was eligible for such subsidies through December 31, 2013. As a result of changes the Company made to the retiree medical plan effective January 1, 2014, the Company no longer receives such subsidy payments for coverage provided after December 31, 2013.

Defined Contribution Plan

The Company participates in ETP’s defined contribution savings plan (“Savings Plan”) that is available to virtually all employees. The Company provided matching contributions of 100% of the first 5% of the participant’s compensation paid into the Savings Plan. Company contributions to the Savings Plan during the years ended December 31, 2015, 2014, and 2013 were $2 million, $3 million, and $6 million, respectively.

In addition, the Company provides a 3% discretionary profit sharing contribution to eligible employees with annual base compensation below a specific threshold. Company contributions are 100% vested after five years of continuous service. The Company’s discretionary profit sharing contributions during the years ended December 31, 2015, 2014, and 2013 were $1 million, $2 million, and $3 million, respectively.

Taxes on Income

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Taxes on Income

INCOME TAXES:

The following table provides a summary of the current and deferred components of income tax expense (benefit) from continuing operations:



	Years Ended December 31,
	2015			2014			2013
Current expense (benefit):
Federal	$	22		$	261		$	(52	)
State	(4		)	24			(7		)
Total	18			285			(59		)
Deferred expense (benefit):
Federal	$	26		$	(114	)	$	119
State	(12		)	(25		)	38
Total	14			(139		)	157
Total income tax expense	$	32		$	146		$	98

The differences between the Company’s effective income tax rate and the U.S. federal income tax statutory rate were as follows:



	Years Ended December 31,
	2015			2014			2013
Computed statutory income tax expense (benefit) at 35%	$	55		$	50		$	(165	)
Changes in income taxes resulting from:
Premium on debt retirement	—			(10		)	—
State income taxes, net of federal income tax benefit	(10		)	4			21
Non-deductible goodwill impairment	—			—			241
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			105			—
Audit settlements	(7		)	—			—
Other	(6		)	(3		)	1
Income tax expense	$	32		$	146		$	98

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



	December 31,
	2015			2014
Deferred income tax assets:
Other postretirement benefits	$	5		$	5
Debt amortization	56			40
Other	31			26
Total deferred income tax assets	92			71
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	90		$	69

Deferred income tax liabilities:
Property, plant and equipment	$	(780	)	$	(776	)
Investment in unconsolidated affiliates	(4		)	(795		)
Other	(1		)	(6		)
Total deferred income tax liabilities	(785		)	(1,577		)
Net deferred income tax liability	$	(695	)	$	(1,508	)

As of December 31, 2015, the Company has $15 million ($10 million, net of federal tax) of unrecognized tax benefits, $9 million of which would impact the Company’s effective income tax rate if recognized. The Company expects that its unrecognized tax benefits will be reduced by $2 million within the next 12 months.

The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its consolidated statement of operations, which is consistent with the recognition of these items in prior reporting periods.

The Company and Southern Union are no longer subject to U.S. federal, state or local examinations for the tax periods prior to 2012. The Company was under examination by the Internal Revenue Service (IRS) for the tax years 2004 through 2009. In July of 2015, the Company and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, the Company recognized a net tax benefit of $7 million.

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

ASSETS AND LIABILITIES:

The Company recognizes all derivative assets and liabilities at fair value on the consolidated balance sheets. The Company had no outstanding interest rate swap agreements as of December 31, 2015 and 2014 .

The following table summarizes the location and amount (excluding income tax effects) of derivative instrument (gains) and losses reported in the Company’s consolidated financial statements:



	Years Ended December 31,
	2015		2014			2013
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Change in fair value – decrease in accumulated other comprehensive income	$	—	$	—		$	(3	)
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—		(7		)	29
Commodity contracts:
Change in fair value — decrease in deferred natural gas purchases	—		—			(7		)

Credit Risk

Credit risk refers to the risk that a shipper may default on its contractual obligations resulting in a credit loss to the Company. A credit policy has been approved and implemented to govern the Company’s portfolio of shippers with the objective of mitigating credit losses. This policy establishes guidelines, controls, and limits, consistent with FERC filed tariffs, to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential shippers, monitoring agency credit ratings, and by implementing credit practices that limit credit exposure according to the risk profiles of the shippers. Furthermore, the Company may, at times, require collateral under certain circumstances in order to mitigate credit risk as necessary.

The Company’s shippers consist of a diverse portfolio of customers across the energy industry, including oil and gas producers, midstream companies, municipalities, utilities, and commercial and industrial end users. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact our shippers 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 shipper non-performance.

- Definition

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

+ References

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+ Details

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS:

The Company’s recorded asset retirement obligations are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, the Company is legally or contractually required to abandon in place or remove the asset. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’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.

Individual component assets have been and will continue to be replaced, but the pipeline system 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. The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets may be replaced, the pipeline system itself will remain intact indefinitely.

The Company had recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. Long-lived assets related to AROs aggregated $18 million and were reflected as plant, property and equipment on our balance sheet as of December 31, 2015 and 2014. In addition, the Company had $6 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015.

The following table is a reconciliation of the carrying amount of the ARO liability reflected as liabilities on our balance sheet for the periods presented. Changes in assumptions regarding the timing, amount, and probabilities associated with the expected cash flows, as well as the difference in actual versus estimated costs, will result in a change in the amount of the liability recognized.



	Years Ended December 31,
	2015			2014			2013
Beginning balance	$	58		$	55		$	46
Revisions	—			3			11
Settled	(3		)	(3		)	(1		)
Disposals	—			—			(4		)
Accretion expense	3			3			3
Ending balance	$	58		$	58		$	55

Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies [Abstract]

Commitments and Contingencies Disclosure

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Trunkline Transfer Applications

In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline’s offshore facilities, and certain related onshore facilities, by sale and transfer to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively. Several parties filed interventions and protests of this filing. On June 21, 2012, FERC issued an order granting Trunkline permission and approval to proceed with the transfer, subject to compliance with certain regulatory requirements. On July 31, 2012 Sea Robin and Trunkline made the necessary compliance filings with FERC. The transfer of the offshore facilities to Sea Robin was effective September 1, 2012.

On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate, and such facilities are contemplated to be converted to crude oil transportation service. This sale was approved by the FERC on November 7, 2013, and the transaction was consummated on December 1, 2015.

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 seeks 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 of 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 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.

PEPL Holdings Guarantee of Collection

The Company fully and unconditionally guaranteed (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, until May 28, 2105, at which time 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, the Company’s obligations under the Panhandle Guarantee were released.

Contingent Residual Support Agreement with ETP

In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under a contingent residual support agreement with ETP and Citrus ETP Finance LLC, pursuant to which the Company provides contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to the Company) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

Environmental Matters

The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

The Company is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing PCBs in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. The Company has implemented a program to remediate such contamination. The primary remaining remediation activity on the PEPL systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location. The PCB assessments are ongoing and the related estimated remediation costs are subject to further change. Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share liability associated with contamination with other potentially related parties. The Company may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

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.

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.

The table below reflects the amount of accrued liabilities recorded in the consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable. The Company is not able to estimate the possible loss or range of loss in excess of amounts accrued. The Company does not have any material environmental remediation matters assessed as reasonably possible.



	December 31,
	2015		2014
Current	$	—	$	1
Non-current	3		3
Total environmental liabilities	$	3	$	4

Litigation and Other Claims

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

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 $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s 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. The Company (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, the Company will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Liabilities for Litigation and Other Claims

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable. When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made. As of December 31, 2015 and 2014, the Company recorded litigation and other claim-related accrued liabilities of $22 million and $21 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and examination for compliance with these requirements. The Company is currently being examined by a third party auditor on behalf of nine states for compliance with unclaimed property laws.

QUARTERLY OPERATIONS

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED):

The following table provides certain quarterly financial information for the periods presented:



	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015		December 31, 2015			Total
Operating revenues	$	155		$	128		$	126	$	139		$	548
Operating income	53			31			26		43			153
Net income (loss)	31			(6		)	76		24			125
Net income (loss) attributable to partners	31			(6		)	76		24			125

	Quarters Ended
	March 31, 2014			June 30, 2014			September 30, 2014		December 31, 2014			Total
Operating revenues	$	178		$	128		$	132	$	143		$	581
Operating income	90			34			31		38			193
Net income (loss)	(35		)	16			23		(7		)	(3		)
Net income (loss) attributable to partners	(41		)	16			23		(7		)	(9		)

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies [Policy Text Block]

Consolidation, Policy [Policy Text Block]

The Company’s consolidated financial statements have been prepared in accordance with GAAP. The consolidated financial statements include the accounts of all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method

Use of Estimates, Policy [Policy Text Block]

New Accounting Pronouncements, Policy [Policy Text Block]

Cash and Cash Equivalents, Policy [Policy Text Block]

Inventory, Policy [Policy Text Block]

Natural Gas Exchanges [Policy Text Block]

Fuel Tracker [Policy Text Block]

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment.

The following table presents the components of property, plant and equipment:



		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

Depreciation. The Company computes depreciation expense using the straight-line method.

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Goodwill and Intangible Assets, Policy [Policy Text Block]

Changes in the carrying amount of goodwill were as follows:



	Total
Balance, December 31, 2013	$	1,336
Lake Charles LNG Transaction	(184		)
Balance, December 31, 2014	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	$	923

Equity Method Investments, Policy [Policy Text Block]

Environmental Cost, Expense Policy [Policy Text Block]

Revenue Recognition, Policy [Policy Text Block]

Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]

Amounts related to the allowance for doubtful accounts were not material as of and during the years ended December 31, 2015 and 2014.

Accumulated Other Comprehensive Loss [Policy Text Block]

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

Derivatives, Policy [Policy Text Block]

Fair Value of Financial Instruments, Policy [Policy Text Block]


•	Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;

•

Asset Retirement Obligations, Policy [Policy Text Block]

Income Tax, Policy [Policy Text Block]

Commitments and Contingencies, Policy [Policy Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies [Abstract]

Other Current Liabilities [Table Text Block]



	December 31,
	2015		2014
Accrued capital expenditures	$	21	$	15
Accrued property taxes	5		9
Other	29		32
Total other current liabilities	$	55	$	56

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

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



	Years Ended December 31,
	2015			2014		2013
Non-cash investing activities:
Contribution from affiliate	$	—		$	376	$	—
Note receivable issued in exchange for investment in ETP	(1,369		)	—		—
Settlement of affiliate liability	793			—		—
Supplemental cash flow information:
Accrued capital expenditures	$	21		$	15	$	13
Cash paid for interest, net of interest capitalized	76			75		142
Cash received for interest on note receivable from affiliate	16			—		—

Property, Plant and Equipment [Table Text Block]



		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

Schedule of Inventory, Current [Table Text Block]

The following table presents the components of inventory:



	December 31,
	2015		2014
Natural gas ⁽¹⁾	$	98	$	105
Materials and supplies	15		14
	$	113	$	119


⁽¹⁾	Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 TBtu, respectively.

Revenue from External Customers by Products and Services [Table Text Block]

The following table presents the relative contribution to the Company’s total operating revenue from continuing operations of each customer that comprised at least 10% of its operating revenues:



	Years Ended December 31,
	2015		2014		2013
Customer A⁽¹⁾	—	%	—	%	10	%
Customer B⁽²⁾	—		—		22
Customer C	11		11		6
Customer D	10		—		—
Other top 10 customers	28		40		20
Remaining customers	51		49		42
Total percentage	100	%	100	%	100	%


⁽¹⁾	SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.


⁽²⁾	Customer B is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

ETE Merger and Other Transactions (Tables)

12 Months Ended

Dec. 31, 2015

ETE Merger and Holdco Transaction [Abstract]

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

Summarized financial information for MGE and NEG is as follows:



	Year Ended December 31, 2013
Revenue from discontinued operations	$	415
Net income of discontinued operations, excluding effect of taxes and overhead allocations	65

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721533-107759

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+ Details

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

The following tables provide a summary of related party activity included in our consolidated statements of operations:



	Years Ended December 31,
	2015		2014			2013
Operating revenues	$	18	$	33		$	56
Cost of natural gas and other energy	—		—			17
Operating and maintenance	16		16			—
General and administrative	31		33			71
Interest expense, net	—		—			(31		)
Interest income — affiliates	23		23			9
Income (loss) from unconsolidated affiliates	26		(12		)	15

dividends received from unconsolidated affiliates [Table Text Block]

The following table provides a summary of distributions received from related parties:



	Years Ended December 31,
	2015		2014		2013
Distributions related to investment in:
ETP	$	39	$	9	$	8
Regency	16		61		44

INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investment, Balance Sheet Summary [Line Items]

Equity Method Investment, Balance Sheet Summary [Table Text Block]

The following tables present aggregated selected balance sheet and income statement data for ETP (on a 100% basis for all periods presented).



	December 31,
	2015		2014
Current assets	$	4,698	$	6,029
Property, plant and equipment, net	45,087		38,907
Other assets	15,388		17,582
Total assets	$	65,173	$	62,518

Current liabilities	$	4,121	$	6,585
Non-current liabilities	34,021		30,622
Equity	27,031		25,311
Total liabilities and equity	$	65,173	$	62,518

INVESTMENTS IN UNCONSOLIDATED AFFILIATES Equity Method Investment, income Statement Summary (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investment, Income Statement Summary [Table Text Block]



	Years Ended December 31,
	2015		2014		2013
Revenue	$	34,292	$	55,475	$	48,335
Operating income	2,259		2,443		1,619
Net income	1,521		1,299		746

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Debt Instrument

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

The following table sets forth the debt obligations of the Company:



	December 31,
	2015		2014
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		400
8.125% Senior Notes due 2019	150		150
7.60% Senior Notes due 2024	82		82
7.00% Senior Notes due 2029	66		66
8.25% Senior Notes due 2029	33		33
Floating Rate Junior Subordinated Notes due 2066	54		54
Other long term debt	5		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

As of December 31, 2015, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
Thereafter	240
Total	$	1,090

Assumption of Southern Union Debt

Floating Rate Junior Subordinated Notes

Compliance With Our Covenants

Schedule Of Debt Instruments

The following table sets forth the debt obligations of the Company:



	December 31,
	2015		2014
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		400
8.125% Senior Notes due 2019	150		150
7.60% Senior Notes due 2024	82		82
7.00% Senior Notes due 2029	66		66
8.25% Senior Notes due 2029	33		33
Floating Rate Junior Subordinated Notes due 2066	54		54
Other long term debt	5		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

Schedule of Maturities of Long-term Debt

As of December 31, 2015, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
Thereafter	240
Total	$	1,090

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Benefits (Tables)

12 Months Ended

Dec. 31, 2015

Postemployment Benefits [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following tables contain information at the dates indicated about the obligations and funded status of the Company’s other postretirement plans.



	December 31,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	24		$	25
Interest cost	1			1
Actuarial (gain) loss	(2		)	1
Benefits paid, net	(2		)	(2		)
Dispositions	—			(1		)
Benefit obligation at end of period	$	21		$	24
Change in plan assets:
Fair value of plan assets at beginning of period	$	114		$	110
Return on plan assets and other	(1		)	4
Employer contributions	7			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			(5		)
Fair value of plan assets at end of period	$	118		$	114

Amount overfunded at end of period ⁽¹⁾	$	(97	)	$	(90	)

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(10	)	$	(16	)
Prior service cost	14			15
	$	4		$	(1	)


⁽¹⁾	Recorded as a non-current asset in the consolidated balance sheets.

Schedule of Net Benefit Costs [Table Text Block]

The following tables set forth the components of net periodic benefit cost of the Company’s postretirement benefit plan for the periods presented:



	Years Ended December 31,
	2015			2014			2013
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(5		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(4	)	$	(4	)

Schedule of Assumptions Used [Table Text Block]

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



	Years Ended December 31,
	2015		2014		2013
Discount rate	3.60	%	4.29	%	3.66	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%

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 the plans are shown in the table below:



	December 31,
	2015		2014
Health care cost trend rate	8.10	%	7.60	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71	%	4.90	%
Year that the rate reaches the ultimate trend rate	2021		2021

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]



	One Percentage Point Increase		One Percentage Point Decrease
Effect on accumulated postretirement benefit obligation	$	1	$	(1	)

Schedule of Allocation of Plan Assets [Table Text Block]

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



	December 31,
	2015		2014
Cash and cash equivalents	$	3	$	3
Mutual fund ⁽¹⁾	115		111
Total	$	118	$	114


⁽¹⁾	This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities and 10% cash. As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% cash.

Schedule of Expected Benefit Payments [Table Text Block]



Years	Expected Benefit Payments
2016	$	2
2017	2
2018	1
2019	1
2020	1
2021 – 2025	6

Taxes on Income (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense (Benefit) and Effective Income Tax Rate

The following table provides a summary of the current and deferred components of income tax expense (benefit) from continuing operations:



	Years Ended December 31,
	2015			2014			2013
Current expense (benefit):
Federal	$	22		$	261		$	(52	)
State	(4		)	24			(7		)
Total	18			285			(59		)
Deferred expense (benefit):
Federal	$	26		$	(114	)	$	119
State	(12		)	(25		)	38
Total	14			(139		)	157
Total income tax expense	$	32		$	146		$	98

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

The differences between the Company’s effective income tax rate and the U.S. federal income tax statutory rate were as follows:



	Years Ended December 31,
	2015			2014			2013
Computed statutory income tax expense (benefit) at 35%	$	55		$	50		$	(165	)
Changes in income taxes resulting from:
Premium on debt retirement	—			(10		)	—
State income taxes, net of federal income tax benefit	(10		)	4			21
Non-deductible goodwill impairment	—			—			241
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			105			—
Audit settlements	(7		)	—			—
Other	(6		)	(3		)	1
Income tax expense	$	32		$	146		$	98

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

The table below summarizes the principal components of the Company’s deferred tax assets (liabilities) as follows:



	December 31,
	2015			2014
Deferred income tax assets:
Other postretirement benefits	$	5		$	5
Debt amortization	56			40
Other	31			26
Total deferred income tax assets	92			71
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	90		$	69

Deferred income tax liabilities:
Property, plant and equipment	$	(780	)	$	(776	)
Investment in unconsolidated affiliates	(4		)	(795		)
Other	(1		)	(6		)
Total deferred income tax liabilities	(785		)	(1,577		)
Net deferred income tax liability	$	(695	)	$	(1,508	)

Derivative Instrument and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives Effect On Income Table

The following table summarizes the location and amount (excluding income tax effects) of derivative instrument (gains) and losses reported in the Company’s consolidated financial statements:



	Years Ended December 31,
	2015		2014			2013
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Change in fair value – decrease in accumulated other comprehensive income	$	—	$	—		$	(3	)
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—		(7		)	29
Commodity contracts:
Change in fair value — decrease in deferred natural gas purchases	—		—			(7		)

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment



		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation



	Years Ended December 31,
	2015			2014			2013
Beginning balance	$	58		$	55		$	46
Revisions	—			3			11
Settled	(3		)	(3		)	(1		)
Disposals	—			—			(4		)
Accretion expense	3			3			3
Ending balance	$	58		$	58		$	55

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies [Abstract]

Environmental Liabilities Table



	December 31,
	2015		2014
Current	$	—	$	1
Non-current	3		3
Total environmental liabilities	$	3	$	4

QUARTERLY OPERATIONS Quarterly Operations (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

The following table provides certain quarterly financial information for the periods presented:



	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015		December 31, 2015			Total
Operating revenues	$	155		$	128		$	126	$	139		$	548
Operating income	53			31			26		43			153
Net income (loss)	31			(6		)	76		24			125
Net income (loss) attributable to partners	31			(6		)	76		24			125

	Quarters Ended
	March 31, 2014			June 30, 2014			September 30, 2014		December 31, 2014			Total
Operating revenues	$	178		$	128		$	132	$	143		$	581
Operating income	90			34			31		38			193
Net income (loss)	(35		)	16			23		(7		)	(3		)
Net income (loss) attributable to partners	(41		)	16			23		(7		)	(9		)

Description of the Business (Details)	12 Months Ended
Description of the Business (Details)	Dec. 31, 2015
General partnership
Description of the Business
General partnership interest	1.00%
Limited partnership
Description of the Business
Limited partnership interest	99.00%

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Cash and Cash Equivalents Items
Non-cash contribution from affiliate	$ 0	$ 376	$ 0
Notes Receivable, Related Parties, Noncurrent	(1,369)	0	0
non-cash payment from subsidiary of ETP	793	0	0
Accrued Capital Expenditures	21	15	13
Interest Paid, Net	76	75	142
Increase (Decrease) in Notes Receivables	$ 16	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Inventory (Details)
MMbtu in Millions, $ in Millions

Dec. 31, 2015

USD ($)

MMbtu

Dec. 31, 2014

USD ($)

MMbtu

Natural Gas Volumes | MMbtu

43.2

34.3

Natural Gas Inventory

^[1]

$ 98

$ 105

Inventory, Raw Materials and Supplies

Inventories

113

119

Energy Related Inventory

$ 113

$ 119

[1]	Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 TBtu, respectively.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of significant accounting policies - goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 19, 2014
Goodwill	$ 923	$ 1,152	$ 1,336
Goodwill, Other Changes	(229)
Goodwill, Impairment Loss	$ 0	0	689
Successor
Goodwill, Impairment Loss			$ 689
Lake Charles LNG Transaction [Member]
Goodwill				$ 184
Goodwill, Other Changes		$ (184)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Top Customers (Details)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Entity-Wide Revenue, Major Customer, Percentage

100.00%

Phillips 66 Company [Member]

Entity-Wide Revenue, Major Customer, Percentage

^[1]

0.00%

10.00%

BG LNG Services

Entity-Wide Revenue, Major Customer, Percentage

^[2]

0.00%

22.00%

Ameren Corporation [Member]

Entity-Wide Revenue, Major Customer, Percentage

11.00%

6.00%

Exelon Generation Company [Member] [Member]

Entity-Wide Revenue, Major Customer, Percentage

10.00%

0.00%

Other Top 10 Customers

Entity-Wide Revenue, Major Customer, Percentage

28.00%

40.00%

20.00%

Remaining Customers

Entity-Wide Revenue, Major Customer, Percentage

51.00%

49.00%

42.00%

[1]	SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.
[2]	is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - PPE (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,338	$ 3,395
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	286	269
Net property, plant and equipment	$ 3,052	$ 3,126

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Liabilities, Current [Abstract]
Accrued Capital Expenditures	$ 21	$ 15	$ 13
Accrued Property Tax	5	9
Customer advances and deposits	29	32
Other current liabilities	$ 55	$ 56

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - New Accounting Pronouncements (Details) $ in Millions	Dec. 31, 2014 USD ($)
Accounting Policies [Abstract]
Deferred Tax Assets, Net, Current	$ 3

Mergers and Other Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2014	Dec. 31, 2013	Apr. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Jan. 31, 2015	Sep. 30, 2014	Feb. 19, 2014	Jun. 24, 2013
Disposal Group, Including Discontinued Operation, Revenue						$ 415
Proceeds from sale of MGE assets, net of transaction costs				$ 0	$ 0	1,008
Goodwill		$ 1,336		$ 923	$ 1,152	1,336
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax						65
Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.					31,400,000				31,400,000
ETP [Member]
Notes Receivable, Related Parties							$ 1,370
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.							15,500,000
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					2,200,000
NOTE PAYABLE TO RELATED PARTY										$ 1,090
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%
Regency 4.50% Senior Notes Due 2023 [Member]
Debt Instrument, Interest Rate, Stated Percentage				4.50%
Guarantor Obligations, Current Carrying Value				$ 600
Class F Units [Member] \| Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.					6,300,000				6,300,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed	18,700,000
Goodwill										184
Intangible Assets, Net (Excluding Goodwill)										$ 50
SUGS Contribution [Member]
Business Combination, Consideration Transferred			$ 463
Cash Acquired from Acquisition			$ 30
New England Gas Company [Member]
Proceeds from sale of MGE assets, net of transaction costs		40
Noncash or Part Noncash Divestiture, Amount of Consideration Received		$ 20
Missouri Gas Energy
Proceeds from sale of MGE assets, net of transaction costs						$ 975
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share								0.4066
Business Acquisition, Share Price								$ 0.32

Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction
Non-current notes receivable from related party — ETP	$ 574	$ 0
Advances from affiliates	$ 0	$ 51

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction
Interest income — affiliates	$ 23	$ 23	$ 9
Income (loss) from unconsolidated affiliates	26	(12)	15
Southern Union
Related Party Transaction
Revenue from Related Parties	18	33	56
Interest income — affiliates	23	23	9
Affiliated Entity
Related Party Transaction
Cost of natural gas and other energy	0	0	17
Related Party Transaction, Expenses from Transactions with Related Party	16	16	0
Related Party Operating, Maintenance and General Expenses	31	33	71
Interest expense, net	0	0	(31)
Income (loss) from unconsolidated affiliates	$ 26	$ (12)	$ 15

RELATED PARTY TRANSACTIONS Related Party Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distributions of earnings received from unconsolidated affiliates	$ 9	$ 6	$ 15
ETP [Member]
Distributions of earnings received from unconsolidated affiliates	39	9	8
Regency [Member]
Distributions of earnings received from unconsolidated affiliates	$ 16	$ 61	$ 44

INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFF. - Schedule of Equity Methold Investments(Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 4,698	$ 6,029
Equity Method Investment Summarized Financial information, PPE	45,087	38,907
Equity Method Investment Summarized Financial information, Other Assets	15,388	17,582
Equity Method Investment, Summarized Financial Information, Assets	65,173	62,518
Equity Method Investment, Summarized Financial Information, Revenue	34,292	55,475	$ 48,335
Equity Method Investment, Summarized Financial Information, Income (Loss) from Continuing Operations before Extraordinary Items	2,259	2,443	1,619
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	1,521	1,299	$ 746
Equity Method Investment, Summarized Financial Information, Current Liabilities	4,121	6,585
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	34,021	30,622
Equity Method Investment Summarized Financial Information, Equity	27,031	25,311
equity method investment summarized financial information, total liabilities and equity	$ 65,173	$ 62,518
Regency [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		31.4		31.4
Class F Units [Member] \| Regency [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		6.3		6.3

INVESTMENTS IN UNCONSOLIDATED AFFILIATES Investment in unconsolidated affiliates detail (Details) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
GOODWILL	$ 923		$ 1,152	$ 1,336
ETP [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		15.5
Notes Receivable, Related Parties		$ 1,370
Investment In ETP [Member]
Schedule of Equity Method Investments [Line Items]
GOODWILL		229
Deferred Tax Liabilities, Deferred Expense		$ 825
SUG Holding Note Receivable [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.75%

Comprehensive Income (Loss) - Tax amounts in other comprehensive income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Income taxes included in other comprehensive income:
Actuarial loss relating to postretirement benefits	$ 0	$ 1	$ (15)

Comprehensive Income (Loss) - Components of AOCI (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Comprehensive Income Loss [Line Items]
Total accumulated other comprehensive income, net of tax	$ 2	$ 0

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Debt Obligations - Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Feb. 19, 2014
Debt Instrument
Junior Subordinated Notes	$ 54	$ 54
Other Long-term Debt	5	6
Unamortized Net Premiums And Fair Value Adjustments	76	99
Total debt outstanding	1,166	1,190
Less: Current maturities of long-term debt	(1)	(1)
Long-term Debt, Excluding Current Maturities	1,165	1,189
6.20% Senior Notes due 2017
Debt Instrument
Senior Notes	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Senior Notes due 2018 [Member]
Debt Instrument
Senior Notes	$ 400	400
Debt Instrument, Interest Rate, Stated Percentage	7.00%
8.125% Senior Notes due 2019
Debt Instrument
Senior Notes	$ 150	150
Debt Instrument, Interest Rate, Stated Percentage	8.125%
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument
Senior Notes	$ 82	82
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Senior Notes Due 2029 [Member]
Debt Instrument
Senior Notes	$ 66	66
Debt Instrument, Interest Rate, Stated Percentage	7.00%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument
Senior Notes	$ 33	$ 33
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Junior Subordinated Debt [Member]
Debt Instrument
Senior Notes	$ 54
Panhandle [Member]
Debt Instrument
Junior Subordinated Notes	$ 600
ETP [Member]
Debt Instrument
NOTE PAYABLE TO RELATED PARTY			$ 1,090

DEBT OBLIGATIONS Debt Obligations - Future Maturities (Details) $ in Millions	Dec. 31, 2015 USD ($)
Debt Instrument
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 0
Long-term Debt, Maturities, Repayments of Principal in Year Two	300
Long-term Debt, Maturities, Repayments of Principal in Year Three	400
Long-term Debt, Maturities, Repayments of Principal in Year Four	150
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	240
Long Term Debt Maturities Repayments Of Principal Total	$ 1,090

Debt Obligations - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Feb. 19, 2014	Jun. 24, 2013
Debt Instrument
Debt Instrument, Unamortized Discount (Premium), Net	$ 12
Debt Instrument, Fair Value Disclosure	1,200	$ 1,240
Long term debt, amount outstanding	1,166	1,190
Junior Subordinated Notes	54	54
Unamortized Net Premiums And Fair Value Adjustments	76	$ 99
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument
Senior Notes	82
Debt Instrument, Interest Rate, Stated Percentage				7.60%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument
Senior Notes	33
Debt Instrument, Interest Rate, Stated Percentage				8.25%
Junior Subordinated Debt [Member]
Debt Instrument
Senior Notes	54
3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		3.0175%
Long-term Debt, Weighted Average Interest Rate				3.295%
ETP [Member]
Debt Instrument
NOTE PAYABLE TO RELATED PARTY			$ 1,090
Panhandle [Member]
Debt Instrument
Junior Subordinated Notes	$ 600

BENEFITS Benefits - Obligations and Funded Status (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Interest cost

$ 1

Fair value of plan assets at beginning of period

114

Fair value of plan assets at end of period

118

114

Other Postretirement Benefit Plan [Member]

Benefit obligation at beginning of period

Interest cost

Actuarial (gain) loss

(2)

Benefits paid, net

(2)

Change in Benefit Obligations, Dispositions

(1)

Benefit obligation at end of period

Fair value of plan assets at beginning of period

114

110

Return on plan assets and other

(1)

Employer contributions

Change in Plan Assets, Dispositions

(5)

Fair value of plan assets at end of period

118

114

$ 110

Amount overfunded at end of period (1)

^[1]

(97)

(90)

Net actuarial loss

(10)

(16)

Prior service cost

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:

$ 4

$ (1)

[1]	Recorded as a non-current asset in the consolidated balance sheets.

Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure
Interest cost	$ 1	$ 1	$ 1
Expected return on plan assets	(6)	(5)	(5)
Prior service credit amortization	1	1	1
Actuarial loss amortization	(1)	(1)	(1)
Net periodic benefit cost	$ (5)	$ (4)	$ (4)

BENEFITS Benefits - Weighted-average Assumptions (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Postemployment Benefits [Abstract]
Discount rate	3.60%	4.29%	3.66%
Tax exempt accounts	7.00%	7.00%	7.00%
Expected long term reurn on assets, taxable accounts	4.50%	4.50%	4.50%

BENEFITS Benefits - Assumed Health Care Cost Trend Rates Used (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Postemployment Benefits [Abstract]
Health care cost trend rate	8.10%	7.60%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71%	4.90%
Year that the rate reaches the ultimate trend rate	2021	2021

BENEFITS Benefits - 1% Change in Assumed Health Care Cost Trend Rates Used (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Postemployment Benefits [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	$ 1
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		$ (1)

BENEFITS Benefits - Fair Value of Assets by Category (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plan, Fair Value of Plan Assets

$ 118

$ 114

Cash and Cash Equivalents

Defined Benefit Plan, Fair Value of Plan Assets

Mutual Fund

Defined Benefit Plan, Fair Value of Plan Assets

^[1]

$ 115

$ 111

[1]

This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities and 10% cash. As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% cash.

BENEFITS Benefits - Estimate of Expected Benefit Payments (Details) - Other Postretirement Benefit Plan [Member] $ in Millions	Dec. 31, 2015 USD ($)
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 2
Defined Benefit Plan, Expected Future Benefit Payments in Year One, net	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two, net	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Three, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Four, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Five, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	6
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter, net	$ 6

BENEFITS Benefits - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure
Defined Contribution Plan Employers Matching Contribution Percentage to Participants Percentage Conribution	100.00%
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 8
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure
Large Cap US Equitiies	36.00%	38.00%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	$ 1
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.84%	3.68%
Fixed Income Securities	54.00%	52.00%
Cash Fund Investments	10.00%	10.00%
Other Postretirement Benefit Plan [Member] \| Equity Securities
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	25.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	35.00%
Other Postretirement Benefit Plan [Member] \| Fixed Income Securities
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	65.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	75.00%
Other Postretirement Benefit Plan [Member] \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	10.00%
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure
Defined Contribution Plan, Employer Matching Contribution, Percent	3.00%
Company Contributions Vested	100.00%
Company Contributions Years	five
Defined Contribution Plan, Cost Recognized	$ 1	$ 2	$ 3
Savings Plan [Member]
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized	$ 2	$ 3	$ 6

Taxes on Income - Current and Deferred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure
Federal	$ 22	$ 261	$ (52)
State	(4)	24	(7)
Current Income Tax Expense (Benefit)	18	285	(59)
Federal	26	(114)	119
State	(12)	(25)	38
Deferred income taxes	14	(139)	157
Total income tax expense	$ 32	$ 146	$ 98

TAXES ON INCOME Income Taxes - Effective Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Computed statutory income tax expense at 35%	$ 55	$ 50	$ (165)
Premium on debt retirement	0	(10)	0
State income taxes, net of federal income tax benefit	(10)	4	21
Non-deductible goodwill impairment	0	0	241
Other	(6)	(3)	1
Effective Income Tax Rate Reconciliation, Audit Settlements	(7)	0	0
Total income tax expense	32	146	98
Trunkline LNG Transaction [Member]
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Other	$ 0	$ 105	$ 0

TAXES ON INCOME Taxes on Income - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other postretirement benefits	$ 5	$ 5
Debt amortization	56	40
Other	31	26
Total deferred income tax assets	92	71
Deferred Tax Assets, Valuation Allowance	(2)	(2)
Deferred Tax Assets, Net	90	69
Property, plant and equipment	(780)	(776)
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	(4)	795
Other	(1)	6
Deferred Tax Liabilities, Gross	785	1,577
Deferred Tax Liabilities, Net	695	1,508
Deferred Tax Liabilities, Net, Noncurrent	$ 695	$ 1,508

TAXES ON INCOME Taxes on Income - Narrative (Details) $ in Millions	Dec. 31, 2015 USD ($)
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 15
Unrecognized tax benfits for state filing positions, net of federal tax	10
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	9
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	2
IRS Audit Settlement	$ 7

TAXES ON INCOME Audit Settlement (Details) $ in Millions	Dec. 31, 2015 USD ($)
Income Tax Disclosure [Abstract]
IRS Audit Settlement	$ 7

Derivative Instrument and Hedging Activities - Income Stmt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain Loss Recognized In Other Comprehensive Income Interest Rate Hedges	$ 0	$ 0	$ (3)
Gain Loss Recognized in Interest Expense	0	(7)	29
Gain Loss Recognized In Distribution Commodity Contracts	$ 0	$ 0	$ (7)

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - PPE Type (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 3,338	$ 3,395
Accumulated depreciation	(286)	(269)
Net property, plant and equipment	3,052	3,126
Land and Land Improvements [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	8	8
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	340	340
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	2,387	2,353
Natural Gas Storage [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	329	323
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	24	23
Right Of Way [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	23	23
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	34	33
Linepack [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	57	57
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	99	192
Construction work in progress
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 37	$ 43

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2015
Building Improvements [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P6Y0M
Building Improvements [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P22Y0M
Pipelines And Equipment [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Pipelines And Equipment [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Natural Gas Storage [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Natural Gas Storage [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Vehicles [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Vehicles [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Right Of Way [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P36Y0M
Right Of Way [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M
Furniture and Fixtures [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Furniture and Fixtures [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P12Y0M
Property, Plant and Equipment, Other Types [Member] \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P2Y0M
Property, Plant and Equipment, Other Types [Member] \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P19Y0M

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Assets (Details) $ in Millions	Dec. 31, 2015 USD ($)
ARO Underlying Asset	$ 6
Other ARO Assets
ARO Underlying Asset	$ 18

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Schedule of Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Beginning balance	$ 58	$ 55	$ 46
Revisions	0	3	11
Settled	$ (3)	$ (3)	$ (1)
Asset Retirement Obligations, Significant Changes	0	0	-4
Accretion expense	$ 3	$ 3	$ 3
Ending balance	$ 58	$ 58	$ 55

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ARO Underlying Asset	$ 6
Asset Retirement Obligation, Revision of Estimate	0	$ 3	$ 11
Asset Retirement Obligation, Liabilities Settled	$ (3)	$ (3)	$ (1)
Asset Retirement Obligations, Significant Changes	0	0	-4
Other ARO Assets
ARO Underlying Asset	$ 18

Commitments and Contingencies - Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Current	$ 0	$ 1
Non-current	3	3
Total environmental liabilities	$ 3	$ 4

Commitment and Contingenices (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Refundable Gas Costs		$ 11,000,000
Contingent Residual Support Agreement, Amount	$ 2,000,000,000
Estimated litigation liability	22,000,000		$ 21,000,000
Regency 4.50% Senior Notes Due 2023 [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Current Carrying Value	$ 600,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Attorney General of Commonwealth [Member]
Loss Contingencies [Line Items]
Legal Fees	$ 19,000,000
Percentage Of Recovery	50.00%
Reimbursement expert and consultant cost, maximum	$ 150,000

QUARTERLY OPERATIONS Quarterly Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues	$ 139	$ 126	$ 128	$ 155	$ 143	$ 132	$ 128	$ 178	$ 548	$ 581	$ 1,085
Operating income	43	26	31	53	38	31	34	90	153	193	(382)
Net income (loss)	24	76	(6)	31	(7)	23	16	(35)	125	(3)	(535)
Net income (loss) attributable to partners	$ 24	$ 76	$ (6)	$ 31	$ (7)	$ 23	$ 16	$ (41)	$ 125	$ (9)	$ (499)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details