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Document And Entity Information $ in Millions	12 Months Ended
Document And Entity Information $ in Millions	Dec. 31, 2013 USD ($) shares
Document Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 1
Accounts receivable, net	63	$ 74
Accounts receivable from related companies	4	14
Exchanges receivable	19	10
System natural gas and operating supplies	203	144
Other	22	20
Total current assets	311	262
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	4,138	4,076
Construction work in progress	69	45
Total property, plant and equipment	4,207	4,121
Accumulated depreciation and amortization	(211)	(57)
Net property, plant and equipment	3,996	4,064
GOODWILL	1,096	1,785
NOTE RECEIVABLE FROM RELATED PARTY	532	831
OTHER NON-CURRENT ASSETS, net	137	108
Total assets	6,072	7,050
CURRENT LIABILITIES:
Current portion of long-term debt	0	258
Accounts payable	6	12
Accounts payable to related companies	14	27
Exchanges payable	207	130
Accrued taxes	9	13
Accrued interest	7	13
Customer advances and deposits	17	4
Other	41	65
Total current liabilities	301	522
LONG-TERM DEBT, less current portion	1,023	1,499
DEFERRED INCOME TAXES	911	853
OTHER NON-CURRENT LIABILITIES	283	135
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS’ CAPITAL:
Partners’ capital	3,551	4,050
Accumulated other comprehensive income (loss)	3	(9)
Total partners’ capital	3,554	4,041
Total liabilities and partners’ capital	6,072	7,050
Successor
CURRENT ASSETS:
Cash and cash equivalents	0	0
PARTNERS’ CAPITAL:
Total partners’ capital	$ 3,554	$ 4,041

PARENTHETICAL DISCLOSURE OF CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2011	Dec. 31, 2010
Successor
Allowance for doubtful accounts	$ 1	$ 1	$ 1
Predecessor
Allowance for doubtful accounts			$ 1	$ 1	$ 1

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
OPERATING REVENUES:
Transportation and storage of natural gas		$ 417	$ 575
LNG terminalling		166	216
Other		9	10
Total operating revenues		592	801
OPERATING EXPENSES:
Operating, maintenance and general		262	281
Depreciation and amortization		125	164
Goodwill, Impairment Loss		0	689
Total operating expenses		387	1,134
OPERATING INCOME (LOSS)		205	(333)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(43)	(50)
Interest income - affiliates		2	2
Total other expenses, net		(41)	(48)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE		164	(381)
Income tax expense		76	118
NET INCOME (LOSS)		$ 88	$ (499)
Predecessor
OPERATING REVENUES:
Transportation and storage of natural gas	$ 140			$ 574
LNG terminalling	51			220
Other	3			10
Total operating revenues	194			804
OPERATING EXPENSES:
Operating, maintenance and general	76			314
Depreciation and amortization	30			128
Goodwill, Impairment Loss	0			0
Total operating expenses	106			442
OPERATING INCOME (LOSS)	88			362
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(25)			(108)
Interest income - affiliates	2			9
Total other expenses, net	(23)			(99)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	65			263
Income tax expense	25			95
NET INCOME (LOSS)	$ 40			$ 168

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Statement of Income and Comprehensive Income [Line Items]
Net income (loss)		$ 88	$ (499)
Other comprehensive income (loss), net of tax:
Reclassification of unrealized loss on interest rate hedges into earnings		0	0
Change in fair value of interest rate hedges		0	0
Actuarial gain (loss) relating to postretirement benefits		(9)	12
Reclassification of prior service credit relating to other postretirement benefits into earnings		0	0
Total other comprehensive income, net of tax		(9)	12
Comprehensive income (loss)		$ 79	$ (487)
Predecessor
Statement of Income and Comprehensive Income [Line Items]
Net income (loss)	$ 40			$ 168
Other comprehensive income (loss), net of tax:
Reclassification of unrealized loss on interest rate hedges into earnings	3			13
Change in fair value of interest rate hedges	0			(1)
Actuarial gain (loss) relating to postretirement benefits	0			(10)
Reclassification of prior service credit relating to other postretirement benefits into earnings	0			(1)
Total other comprehensive income, net of tax	3			1
Comprehensive income (loss)	$ 43			$ 169

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Partners’ Capital	Accumulated Other Comprehensive Income (Loss)	Tax Sharing Note Receivable-Related Party
Balance (Predecessor) at Dec. 31, 2010	$ 1,621	$ 1,641	$ (17)	$ (3)
Tax sharing receivable - Southern Union \| Predecessor	2	0	0	2
Net income \| Predecessor	168	168	0	0
Other comprehensive income, net of tax \| Predecessor	1	0	1	0
Balance (Predecessor) at Dec. 31, 2011	1,792	1,809	(16)	(1)
Net income \| Predecessor	40	40	0	0
Other comprehensive income, net of tax \| Predecessor	3	0	3	0
Balance (Predecessor) at Mar. 25, 2012	1,835	1,849	(13)	(1)
Balance (Successor) at Mar. 25, 2012	3,961	3,962	0	(1)
Tax sharing receivable - Southern Union \| Successor	1	0	0	1
Net income \| Successor	88	88	0	0
Other comprehensive income, net of tax \| Successor	(9)	0	(9)	0
Balance (Successor) at Dec. 31, 2012	4,041	4,050	(9)	0
Balance at Dec. 31, 2012	4,041
Net income \| Successor	(499)	(499)	0	0
Other comprehensive income, net of tax \| Successor	12	0	12	0
Balance (Successor) at Dec. 31, 2013	3,554	$ 3,551	$ 3	$ 0
Balance at Dec. 31, 2013	$ 3,554

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 8: 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
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

+ Details

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Reconciliation of net income to net cash provided by operating activities:
Net gain on curtailment of OPEB plan benefits		$ (11)
CASH FLOWS FROM FINANCING ACTIVITIES:
CASH AND CASH EQUIVALENTS, end of period			$ 1
Successor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		88	(499)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		125	164
Goodwill, Impairment Loss		0	689
Deferred income taxes		86	51
Amortization included in interest expense		(24)	(28)
Net gain on curtailment of OPEB plan benefits		(11)	0
Changes in operating assets and liabilities, net of Merger impact		(77)	56
Net cash flows provided by operating activities		187	433
CASH FLOWS FROM INVESTING ACTIVITIES:
Net decrease (increase) in note receivable - related parties		(55)	299
Net increase (decrease) in income taxes payable - related parties		(43)	68
Additions to property, plant and equipment		(90)	(94)
Other		0	2
Net cash flows provided by (used in) investing activities		(188)	275
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt		0	0
Repayment of debt		0	(705)
Other		1	(3)
Net cash flows (used in) provided by financing activities		1	(708)
INCREASE IN CASH AND CASH EQUIVALENTS		0	0
CASH AND CASH EQUIVALENTS, beginning of period		0	0
CASH AND CASH EQUIVALENTS, end of period	$ 0	0	$ 0
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	40			$ 168
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	30			128
Goodwill, Impairment Loss	0			0
Deferred income taxes	19			76
Amortization included in interest expense	0			0
Net gain on curtailment of OPEB plan benefits	0			0
Changes in operating assets and liabilities, net of Merger impact	23			(28)
Net cash flows provided by operating activities	112			344
CASH FLOWS FROM INVESTING ACTIVITIES:
Net decrease (increase) in note receivable - related parties	255			(207)
Net increase (decrease) in income taxes payable - related parties	5			(10)
Additions to property, plant and equipment	(28)			(111)
Other	0			0
Net cash flows provided by (used in) investing activities	232			(328)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	455			0
Repayment of debt	(797)			(18)
Other	(2)			2
Net cash flows (used in) provided by financing activities	(344)			(16)
INCREASE IN CASH AND CASH EQUIVALENTS	0			0
CASH AND CASH EQUIVALENTS, beginning of period	0	$ 0		0
CASH AND CASH EQUIVALENTS, end of period	$ 0			$ 0

Description of the Business

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of the Business

OPERATIONS AND ORGANIZATION:

Panhandle is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services and is subject to the rules and regulations of the FERC. The Company’s entities include the following:


•	PEPL, an indirect wholly-owned subsidiary of Southern Union, which is an indirect wholly-owned subsidiary of ETP;


•	Trunkline, a direct wholly-owned subsidiary of PEPL;


•	Sea Robin, an indirect wholly-owned subsidiary of PEPL;


•	LNG Holdings, an indirect wholly-owned subsidiary of PEPL; and


•	Southwest Gas, a direct wholly-owned subsidiary of PEPL.

The Company’s operations consist of interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes region, as well as, owned underground storage capacity. As of December 31, 2013, the Company also owned and operated an LNG import terminal located on Louisiana’s Gulf Coast, as well as, an above ground LNG storage facility.

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETP, serves as the general partner of PEPL and owns a 1% general partnership interest in PEPL. ETP also indirectly owns a 99% limited partnership interest in PEPL.

See Note 3 for information related to the Panhandle Merger and other transactions.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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 Company is subject to regulation by certain state and federal authorities. The Company has accounting policies under GAAP that do not conform to authoritative guidance 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.

Principles of Consolidation. 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.

Business Combination Accounting. Southern Union’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. By the application of “push-down” accounting, PEPL’s assets, liabilities and partners’ capital were accordingly adjusted to fair value on March 26, 2012. Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions. See Note 3 for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting. Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

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.

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. Total cash balances at December 31, 2013, 2012 and 2011 were each less than $1 million, respectively.

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	84	$	75	$	17	$	106
Cash paid for income taxes	—		32		—		35

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,
	2013		2012
Natural gas ⁽¹⁾	$	184	$	124
Materials and supplies	19		20
	$	203	$	144


⁽¹⁾	Natural gas volumes held for operations at December 31, 2013 and 2012 were 42,843,000 MMBtu and 34,891,000 MMBtu, 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 Panhandle 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.

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 (more fully described below in the “Interest Cost Capitalized” accounting policies disclosure) 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.

For additional information, see Note 12.

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 not amortized, but instead 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 the fourth quarter of 2013, we performed a goodwill impairment test on our Trunkline LNG reporting unit. In accordance with GAAP, we performed step one of the goodwill impairment test and determined that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Trunkline LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount. We then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, we estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, we recorded a goodwill impairment of $689 million during the fourth quarter of 2013.

Related Party Transactions. Related party expenses primarily include payments for services provided by Southern Union and ETP. Other income is primarily related to interest income on a note receivable from a related party. See Note 4 for additional information on related party transactions.

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 Southern Union. The Company has entered into a tax sharing agreement with Southern Union pursuant to which the Company will be required to make payments to Southern Union in order to reimburse Southern Union for federal and state taxes that it pays on the Company’s income, or to receive payments from Southern Union to the extent that tax losses generated by the Company are utilized by Southern Union. In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by Southern Union. 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 Southern Union, 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.

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 and LNG terminalling 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 Panhandle 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.

Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards. Customers that do not meet minimum standards are required to provide additional credit support. The Company considers many factors including historical customer collection experience, general and specific economic trends and know specific issues related to individual customers 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.

The following table presents the balance in the allowance for doubtful accounts and activity:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Beginning balance	$	1	$	1	$	1	$	1
Additions: charged to cost and expenses	—		—		—		—
Deductions: write-off of uncollectible accounts	—		—		—		—
Other	—		—		—		—
Ending balance	$	1	$	1	$	1	$	1

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
BG Energy Holdings LTD	30	%	31	%	30	%	30	%
ETC ProLiance (Related Party)	13		12		13		13
Other top 10 customers	24		20		24		21
Remaining customers	33		37		33		36
Total percentage	100	%	100	%	100	%	100	%

Retirement Benefits. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. 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. See Note 8 for additional related information.

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. See Note 10 for information related to derivative instruments and hedging activities.

Stock-Based Compensation. The Company measures all employee stock-based compensation using a fair value method and records the related expense in the consolidated statement of operations. For more information, see Note 13.

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.

See Note 8 and Note 11 for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.

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.

See Note 5 for additional related information.

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 Southern Union. Upon completion of the Holdco transaction on October 5, 2012, Southern Union became a member of a new federal consolidated tax return filing group of which Holdco is the parent company. As a result of the Holdco transaction, Southern Union entered into a tax sharing agreement with Holdco. However, the Company will continue its tax sharing agreement with Southern Union, and will pay its share of taxes based on its taxable income, which will generally equal the liability that the Company would have incurred as a separate taxpayer.

Mergers and Other Transactions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Business Combinations Disclosure

MERGERS, DECONSOLIDATIONS, AND RELATED TRANSACTIONS:

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 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 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.

This transaction was a combination of entities under common control; therefore, the consolidated financial statements of the Company will be retrospectively adjusted to consolidate Southern Union for all periods, beginning when the Company issues financial statements that include the period when the transaction occurred.

Trunkline LNG Transaction

On February 19, 2014, Panhandle transferred to ETP all of the interests in Trunkline 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 Trunkline 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. The results of Trunkline LNG’s operations have not been presented as discontinued operations and Trunkline LNG’s assets and liabilities have not been presented as held for sale in the Company’s consolidated financial statements due to the expected continuing involvement among the entities.

2013 Transaction

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco, the entity formed by ETP and ETE in 2012 (as discussed under “Holdco Transaction” below) to own the equity interests in Southern Union and Sunoco. As a result of this transaction, ETP now owns 100% of Holdco. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

2012 Transactions

ETE Merger

On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE until the Panhandle Merger in 2014. See below for discussion of Holdco Transaction and ETE’s contribution of Southern Union to Holdco.

Under the terms of the merger agreement, Southern Union stockholders received a total of 56,982,160 ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.

In connection with the ETE Merger on March 26, 2012, ETP completed the acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.3 million ETP Common Units.

Holdco Transaction

Immediately following the closing of ETP’s acquisition of Sunoco in 2012, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP controlled Holdco. This transaction did not result in a new basis of accounting for Southern Union or Panhandle.

Allocation of Consideration Transferred

The ETE Merger was accounted for using business combination accounting under applicable accounting principles. Business combination accounting requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The table below represents the amounts allocated to Panhandle’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values. Certain amounts included in the purchase price allocation, as of December 31, 2012, may have been changed from amounts previously reflected based on management’s review of the valuation. The goodwill resulting from the ETE Merger was primarily due to expected commercial and operational synergies and is not deductible for tax purposes.



Cash and cash equivalents	$	—
Other current assets	229
Property and equipment	4,093
Goodwill	1,785
Identified intangibles ⁽¹⁾	55
Other non-current assets	783
Long-term debt, including current portion	(1,780		)
Deferred income taxes	(773		)
Other liabilities	(431		)
Total fair value of partners’ capital	$	3,961


⁽¹⁾	Identified intangibles will be amortized over a life of approximately 17.5 years and are included in Other non-current assets in the consolidated balance sheets.

As a result of the ETE Merger, we recognized $48 million of merger-related costs during the period from March 26, 2012 to December 31, 2012. These included charges related to employment agreements with certain executives that provided for compensation when their employment was terminated and severance costs associated with administrative headcount reductions, as well as an allocation of such charges for Southern Union employees. These expenses were included in operating, maintenance, and general expenses in the consolidated statements of operations.

The Company also recognized an $11 million net gain due to the curtailment of certain other postretirement employee benefit plans in 2012. See Note 8 for more information on the curtailment.

- 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

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+ Details

Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions

RELATED PARTY TRANSACTIONS:

The following table provides a summary of the related party balances included in the consolidated balance sheets:



	December 31,
	2013		2012
Non-current notes receivable from related party — Southern Union	$	532	$	831

Accounts receivable from related companies ⁽¹⁾	$	4	$	14

Cash advances from affiliate	$	120	$	—

Accounts payable to related companies:
Southern Union — other ⁽²⁾	$	—	$	26
Other ⁽³⁾	14		1
	$	14	$	27


⁽¹⁾	Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus and other affiliates.


⁽²⁾	Accounts payable from related companies reflected above primarily related to payroll funding, including merger-related expenses, provided by Southern Union.


⁽³⁾	Accounts payable from related companies reflected above primarily related to various administrative and operating costs paid by ETP and other affiliate companies on behalf of the Company.

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



	Successor			Predecessor
	Year Ended December 31, 2013	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Transportation and storage of natural gas ⁽¹⁾	31	7		$	1	$	3
Operating, maintenance and general	59	61	⁽²⁾	14		58
Interest income — affiliates	2	2		2		9


⁽¹⁾	Represents transportation and storage revenues with ETC and Sunoco, subsidiaries of ETP (in the successor periods) and MGE, a division of Southern Union that was sold in the third quarter of 2013.


⁽²⁾	Primarily represents corporate charges for employee expenses related to the ETE Merger offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

Pursuant to a demand note with Southern Union under a cash management program, the Company loans excess cash, net of repayments, to Southern Union. The Company is credited with interest on the note at a one month LIBOR rate. Given the uncertainties regarding the timing of the Company’s cash flows, including financings, capital expenditures and operating cash flows, the Company has reported the note receivable as a non-current asset. The Company has access to the funds via the demand note and expects repayment to ultimately occur to primarily fund capital expenditures or debt retirements.

- 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

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2013

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. Amounts reflected in long-lived assets related to AROs aggregated approximately $13 million and $1 million and were reflected as non-current assets on our balance sheet as of December 31, 2013 and 2012, respectively.

As of December 31, 2013, the Company had no material legally restricted funds for the purpose of settling AROs.

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.



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Beginning balance	$	42		$	41		$	41	$	57
Incurred	—			1			—		1
Revisions	11			3			—		—
Settled	(1		)	(5		)	—		(17		)
Accretion expense	3			2			—		—
Ending balance	$	55		$	42		$	41	$	41

During 2011, the Company recorded settlements of approximately $17 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike. During 2013, the Company recorded an $11 million upward revision to its prior ARO liability estimates, primarily due to changes in ARO liabilities as a result of a third party evaluation.

Comprehensive Income

12 Months Ended

Dec. 31, 2013

Statement of Comprehensive Income [Abstract]

Comprehensive Income

COMPREHENSIVE INCOME:

The tables below set forth the tax amounts included in the respective components of other comprehensive income:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$	—		$	—		$	2	$	9
Change in fair value of interest rate hedges	—			—			—		(1		)
Actuarial loss relating to postretirement benefits	(2		)	(6		)	—		(6		)
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—			—		(1		)
	$	(2	)	$	(6	)	$	2	$	1

The table below presents the components in accumulated other comprehensive income (loss):



	December 31,
	2013		2012
Other postretirement plan - net actuarial gain (loss) and prior service costs, net	$	3	$	(9	)
Total accumulated other comprehensive income (loss), net of tax	$	3	$	(9	)

- Definition

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

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+ Details

Debt Obligations

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

The following table sets forth the debt obligations of the Company at the dates indicated:



	December 31,
	2013		2012
6.05% Senior Notes due 2013	$	—	$	250
6.20% Senior Notes due 2017	300		300
8.125% Senior Notes due 2019	150		150
7.00% Senior Notes due 2029	66		66
7.00% Senior Notes due 2018	400		400
Term Loan due 2015	—		455
Unamortized fair value adjustments	107		136
Total debt outstanding	1,023		1,757
Current portion of long-term debt	—		(258		)
Total long-term debt	$	1,023	$	1,499

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations at December 31, 2013 and 2012 was $1.06 billion and $1.81 billion, respectively. As of December 31, 2013 and 2012, the aggregate carrying amount of our consolidated debt obligations was $1.02 billion and $1.76 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Senior Notes

Panhandle’s 6.05% Senior Notes in the amount of $250 million matured on August 15, 2013 and were repaid with intercompany borrowings.

Term Loans

On March 26, 2012, the Company retired the $465 million term loan due June 2012 ($342 million of which was outstanding) of its wholly-owned LNG Holdings subsidiary, utilizing a portion of the merger consideration received in connection with the Citrus Merger.

In February 2012, the Company refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt.

In September 2013, ETP issued $1.47 billion total principal amount of Senior Notes. Proceeds from this offering were used to repay $455 million of borrowings under the LNG Holdings term loan due February 2015.

As of December 31, 2013, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2014	$	—
2015	—
2016	—
2017	300
2018	400
Thereafter	216
Total	$	916

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, Panhandle assumed Southern Union’s long-term debt obligations. As of December 31, 2013, there was $83 million in aggregate principal amount of 7.6% 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. See Note 3.

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, 2013, the Company is in compliance with these covenants.

Benefits

12 Months Ended

Dec. 31, 2013

Postemployment Benefits [Abstract]

Benefits

RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the year ended December 31, 2013 reflected the impact of changes the Company adopted as of September 30, 2013 to change its retiree medical benefits program effective January 1, 2014 which placed all retirees on a common cost sharing platform, subject to caps on annual average per capita expenditures by the Company. Postretirement benefits expense for the year ended December 31, 2012 reflected the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated. The Company previously had postretirement health care and life insurance plans (other postretirement plans) that covered substantially all 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.



	Successor						Predecessor
	December 31, 2013			December 31, 2012			March 25, 2012
Change in benefit obligation:
Benefit obligation at beginning of period	$	38		$	93		$	88
Service cost	—			—			1
Interest cost	1			1			1
Amendments	—			16			—
Actuarial loss and other	(16		)	4			3
Benefits paid, net	(2		)	(1		)	—
Curtailments	—			(75		)	—
Benefit obligation at end of period	$	21		$	38		$	93
Change in plan assets:
Fair value of plan assets at beginning of period	$	90		$	82		$	75
Return on plan assets and other	7			3			5
Employer contributions	8			6			2
Benefits paid, net	(2		)	(1		)	—
Fair value of plan assets at end of period	$	103		$	90		$	82

Amount (overfunded) underfunded at end of period ⁽¹⁾	$	(82	)	$	(52	)	$	11

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(20	)	$	(1	)	$	—
Prior service cost	16			16			—
	$	(4	)	$	15		$	—


⁽¹⁾	Underfunded balance is recognized as a non-current liability in the consolidated balance sheets. Overfunded balance is recognized 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:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Service cost	$	—		$	—		$	1		$	2
Interest cost	1			1			1			4
Expected return on plan assets	(5		)	(3		)	(1		)	(3		)
Prior service credit amortization	1			—			(1		)	(2		)
Actuarial loss amortization	(1		)	—			—			—
Curtailment recognition⁽¹⁾	—			(11		)	—			—
Net periodic benefit cost	$	(4	)	$	(13	)	$	—		$	1

⁽¹⁾

Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans to prospectively restrict participation in the plans for certain active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a gross pre-tax curtailment gain of $70 million, $59 million of which is subject to refund to customers; thus, the net curtailment gain recognition was $11 million.

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2014 is $1 million.

Assumptions. The weighted-average discount rate used in determining benefit obligations was 4.26%, 3.51% and 4.24% at December 31, 2013 and in the successor and predecessor periods in 2012, respectively.

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Discount rate	3.70	%	3.64	%	4.26	%	5.54	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	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:



	Successor				Predecessor
	December 31, 2013		December 31, 2012		March 25, 2012
Health care cost trend rate assumed for next year	8.00	%	8.50	%	8.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.90	%	4.50	%	4.75	%
Year that the rate reaches the ultimate trend rate	2021		2020		2019

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 with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, 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 Southern Union’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,
	2013		2012
Cash and cash equivalents	$	2	$	2
Mutual fund ⁽¹⁾	101		88
Total	$	103	$	90

⁽¹⁾

This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2013, the fund was primarily comprised of approximately 19% large-cap U.S. equities, 5% small-cap U.S. equities, 8% international equities, 55% fixed income securities, 7% cash, and 6% in other investments. As of December 31, 2012, the fund was primarily comprised of approximately 17% large-cap U.S. equities, 3% small-cap U.S. equities, 10% international equities, 53% fixed income securities, 10% cash and 7% in other investments.

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. See Note 2 for information related to the framework used by the Company to measure the fair value of its other postretirement plan assets.

Contributions. The Company expects to make $8 million contributions to its other postretirement plans in 2014 and approximately $8 million 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. The Company does not expect to receive any Medicare Part D subsidies in any future periods.



Years	Expected Benefit Payments
2014	$	2
2015	2
2016	2
2017	2
2018	1
2019 – 2023	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 is 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 will no longer receive such subsidy payments for coverage provided after December 31, 2013. Those subsidy payments are instead provided to the Company’s insurance carrier and will be reflected in the insurance charges for coverage for 2014 and beyond. These changes are reflected in the measurement of plan obligations as of December 31, 2013.

Defined Contribution Plan

The Company sponsors a 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 year ended December 31, 2013, the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the year ended December 31, 2011 were $3 million, $3 million, $1 million and $5 million, respectively.

In addition, the Company provides a 3% 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 fixed contributions during the year ended December 31, 2013, the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the year ended December 31, 2011 were $2 million, $2 million, $1 million and $6 million, respectively.

Taxes on Income

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Taxes on Income

TAXES ON INCOME:

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



	Successor					Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Current expense (benefit):
Federal	$	58	$	(8	)	$	5	$	24
State	9		(2		)	1		(5		)
Total	67		(10		)	6		19
Deferred expense:
Federal	$	44	$	72		$	17	$	67
State	7		14			2		9
Total	51		86			19		76
Total income tax expense	$	118	$	76		$	25	$	95

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



	Successor					Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Computed statutory income tax expense at 35%	$	(133	)	$	57	$	23	$	92
Changes in income taxes resulting from:
Non-deductible executive compensation	—			11		—		—
State income taxes, net of federal income tax benefit	10			8		2		3
Non-deductible goodwill impairment	241			—		—		—
Income tax expense	$	118		$	76	$	25	$	95

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,
	2013			2012
Deferred income tax assets:
Other postretirement benefits	$	5		$	13
Debt amortization	43			52
Other	19			18
Total deferred income tax assets	67			83

Deferred income tax liabilities:
Property, plant and equipment	(967		)	(925		)
Other	(2		)	(2		)
Total deferred income tax liabilities	(969		)	(927		)
Net deferred income tax liability	(902		)	(844		)
Less current income tax assets	9			9
Accumulated deferred income taxes	$	(911	)	$	(853	)

As of December 31, 2013, the Company has $1 million ($1 million, net of federal tax) of unrecognized tax benefits, none of which would impact the Company’s effective income tax rate if recognized. The Company does not expect that its unrecognized tax benefits will be reduced 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.

Southern Union and the Company are no longer subject to U.S. federal, state or local examinations for the tax periods prior to 2004.

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company is exposed to certain risks in its ongoing business operations. The primary risk managed by using derivative instruments is interest rate risk. Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time. The Company recognizes all derivative assets and liabilities at fair value in the consolidated balance sheets.

Interest Rate Contracts. The Company may enter into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and may enter into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.

Interest Rate Swaps. The Company had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012 and repaid in September 2013. These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impacted earnings. These swaps terminated in the first quarter of 2012.

Treasury Rate Locks. As of December 31, 2013, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt. During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

The Company had no derivative instruments at December 31, 2013 and December 31, 2012.

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Cash Flow Hedges:
Change in fair value – increase in accumulated other comprehensive income	$	—	$	—	$	—	$	1
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	—		—		4		22

- 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

Fair Value Measurement	12 Months Ended
Fair Value Measurement	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Fair Value Measurement	FAIR VALUE MEASUREMENT: The fair value of the Trunkline LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Trunkline LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business’s ability to attain the projected cash flows. The approximate fair value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

PROPERTY, PLANT AND EQUIPMENT:

The following table provides a summary of property, plant and equipment:



		December 31,
	Lives in Years	2013			2012
Transmission	5 – 46	$	2,649		$	2,580
Gathering	26	96			114
Underground storage	5 – 46	318			306
General plant - LNG	5 – 40	967			966
General plant - other	3 – 40	108			110
Plant in service		4,138			4,076
Construction work in progress		69			45
Total property, plant and equipment		4,207			4,121
Accumulated depreciation and amortization		(211		)	(57		)
Net property, plant and equipment		$	3,996		$	4,064

As of December 31, 2011, property, plant and equipment included capitalized computer software costs of $34 million, net of accumulated amortization of $51 million. Amortization expense of capitalized computer software costs for the year ended December 31, 2011 was $7 million.

As of December 31, 2011, property, plant and equipment included contributions in aid of construction costs of $49 million, net of accumulated amortization of $5 million. Amortization expense of contributions in aid of construction costs for the year ended December 31, 2011 was $2 million.

SHARE-BASED COMPENSATION Share-Based Compensation

12 Months Ended

Dec. 31, 2013

Share-based Compensation [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

STOCK-BASED COMPENSATION

Stock Award Plans. The Third Amended 2003 Plan adopted by the stockholders of Southern Union Company allowed for awards in the form of stock options (either incentive stock options or non-qualified options), SARs, stock bonus awards, restricted stock, performance units or other equity-based rights. The persons eligible to receive awards under the Third Amended 2003 Plan included all of the employees, directors, officers and agents of, and other service providers to, Southern Union Company and its affiliates and subsidiaries. Under the Third Amended 2003 Plan: (i) no participant may receive any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100% of the fair market value of the common stock on the date of grant; and (iii) no award may be granted after September 28, 2013.

The fair value of each stock option and SAR award was estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of Southern Union Company’s common stock. The expected dividend yield was considered for each grant on the date of grant. The Company used the simplified method in determining the expected term of stock options and SARs granted, which resulted in the use of the average midpoint between vesting of the awards and their contractual term for such estimate. The Company utilized the simplified method primarily because Southern Union had experienced several acquisitions and divestitures during the contractual period, resulting in a change in the employee mix and an acceleration of certain stock option and SAR exercise activity. Additionally, Southern Union had not experienced a full life cycle of exercise activity for employees associated with certain of its acquisitions. Because of the impact of these significant structural changes in Southern Union’s business operations and the resulting variations in employee exercise activity, the historical patterns of such exercise activity was not believed to be indicative of future behavior. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant.

All outstanding stock awards vested and were settled in 2012 in connection with the ETE Merger on March 26, 2012; therefore, no 2012 or 2013 amounts have been presented in the following sections.

Stock Options. The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable:



	Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2010	203,903		$	20.27
Exercised	(38,596	)	17.56
Outstanding December 31, 2011	165,307		$	20.90

Exercisable December 31, 2011	165,307		20.90

SARS. The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable:



	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2010	616,803		$	20.71
Exercised	(27,389	)	15.87
Forfeited	(30,512	)	27.41
Outstanding December 31, 2011	558,902		$	20.58

Exercisable December 31, 2011	423,815		19.61

The SARs were scheduled to vest in equal installments on the first three anniversaries of the grant date. Each SAR entitled the holder to shares of Southern Union’s common stock equal to the fair market value of Southern Union’s common stock on the applicable exercise date in excess of the grant date price for each SAR.

The total fair value of options and SARs vested as of December 31, 2011 was $4 million. Compensation expense recognized related to stock options and SARs was approximately $1 million for the year ended December 31, 2011. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2011 was $16 million and $13 million, respectively. The intrinsic value of options and SARs exercised during the year ended December 31, 2011 was approximately $1 million.

Restricted Stock Equity and Liability Units. The Third Amended 2003 Plan also provided for grants of restricted stock equity units, which were settled in shares of Southern Union Company common stock, and restricted stock liability units, which were settled in cash. The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expired equally over a period of three years. Restrictions on restricted stock liability units expired at the end of the applicable period, which was also the requisite service period.

There were no restricted stock equity awards granted during the year ended December 31, 2011.

The following table provides information on restricted stock liability awards granted, released and forfeited for the periods presented.



	Number of Restricted Stock Liability Units Outstanding		Weighted-Average Grant Date Fair Value
Restricted shares at December 31, 2010	165,870		$	20.68
Granted	51,611		42.08
Released	(87,509	)	18.47
Forfeited	(4,918	)	18.97
Restricted shares at December 31, 2011	125,054		$	31.15

The total fair value of restricted stock liability units that were released during the year ended December 31, 2011 was $4 million. Compensation expense recognized related to restricted stock equity and liability units totaled $4 million for the year ended December 31, 2011.

The Company settled the restricted stock liability units released in 2011 with cash payments of $4 million.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

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.

FERC Audit

The FERC recently completed an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit related to the period from January 1, 2010 through December 31, 2011. An audit report was received in August 2013 noting no issues that would have a material impact on the Company’s historical financial position or results of operations.

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. The outcome of the filing will be determined by a regulatory process that includes a hearing currently scheduled for the fourth quarter of 2014, with a Commission order expected in 2015.

PEPL Holdings Guarantee of Collection

On April 30, 2013, Southern Union completed its contribution to Regency of all the membership interest in Southern Union Gathering Company LLC and its subsidiaries, including Southern Union Gas Services (the “SUGS Contribution”). In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution, Regency entered into an agreement with PEPL Holdings, a wholly-owned subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

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.

Environmental Remediation

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 Panhandle 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 PRPs. 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.

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.

Environmental Remediation Liabilities

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 does not have any material environmental remediation matters assessed as reasonably possible.



	December 31,
	2013		2012
Current	$	1	$	1
Non-current	3		5
Total environmental liabilities	$	4	$	6

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.

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, 2013 and 2012, the Company recorded litigation and other claim-related accrued liabilities of $6 million and $6 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

Unclaimed Property Audits. 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.

Future Regulatory Compliance Commitments

Air Quality Control. On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels.

In August 2010, the EPA finalized a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for certain engines regardless of size at Area Sources (sources that emit less than 10 tons per year of any one Hazardous Air Pollutant (“HAP”) or 25 tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit 10 tons per year or more of any one HAP or 25 tons per year of all HAPs). Compliance was required by October 2013, and the Company believes it is in compliance.

Nitrogen oxides are the primary air pollutant from natural gas-fired engines. Nitrogen oxide emissions may form ozone in the atmosphere. In 2008, the EPA lowered the ozone standard to 75 ppb with compliance anticipated in 2013 to 2015. In January 2010, the EPA proposed lowering the standard to 60 to 70 ppb in lieu of the 75 ppb standard, with compliance required in 2014 or later. In September 2011, the EPA decided to rescind the proposed lower ozone standard and begin the process to implement the 75 ppb ozone standard established in 2008.

In January 2010, the EPA finalized a 100 ppb one-hour nitrogen dioxide standard. The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013. This new monitoring may result in additional nitrogen dioxide non-attainment areas. In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

The Company has reviewed the potential impacts of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule, implementation of the 2008 ozone standard and the new nitrogen dioxide standard on its operations and the potential costs associated with the installation of emission control systems on its existing engines. The ultimate costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes, based on the current understanding of the current and proposed rules, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

QUARTERLY OPERATIONS

12 Months Ended

Dec. 31, 2013

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:



			Successor
			Quarters Ended
			March 31, 2013			June 30, 2013		September 30, 2013		December 31, 2013			Total
Operating revenues			$	199		$	232	$	180	$	190		$	801
Operating income (loss)			81			126		71		(611		)	(333		)
Net income (loss)			42			69		37		(647		)	(499		)

	Predecessor		Successor
	Period from January 1, 2012 to March 25, 2012		Period from March 26, 2012 to March 31, 2012			Quarters Ended							Total Period from March 26, 2012 to December 31, 2012
	Period from January 1, 2012 to March 25, 2012		Period from March 26, 2012 to March 31, 2012			June 30, 2012		September 30, 2012		December 31, 2012			Total Period from March 26, 2012 to December 31, 2012
Operating revenues	$	194	$	13		$	185	$	189	$	205		$	592
Operating income (loss)	88		(26		)	65		77		89			205
Net income (loss)	40		(19		)	30		37		40			88

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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

Basis of Presentation. The Company’s consolidated financial statements have been prepared in accordance with GAAP.

Consolidation, Policy [Policy Text Block]

Business Combination Accounting [Policy Text Block]

Use of Estimates, Policy [Policy Text Block]

Cash and Cash Equivalents, Policy [Policy Text Block]

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	84	$	75	$	17	$	106
Cash paid for income taxes	—		32		—		35

Inventory, Policy [Policy Text Block]

The following table presents the components of inventory:



	December 31,
	2013		2012
Natural gas ⁽¹⁾	$	184	$	124
Materials and supplies	19		20
	$	203	$	144


⁽¹⁾	Natural gas volumes held for operations at December 31, 2013 and 2012 were 42,843,000 MMBtu and 34,891,000 MMBtu, respectively.

Natural Gas Exchanges [Policy Text Block]

Fuel Tracker [Policy Text Block]

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

Property, Plant and Equipment.

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

For additional information, see Note 12.

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

Goodwill and Intangible Assets, 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]

The following table presents the balance in the allowance for doubtful accounts and activity:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Beginning balance	$	1	$	1	$	1	$	1
Additions: charged to cost and expenses	—		—		—		—
Deductions: write-off of uncollectible accounts	—		—		—		—
Other	—		—		—		—
Ending balance	$	1	$	1	$	1	$	1

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
BG Energy Holdings LTD	30	%	31	%	30	%	30	%
ETC ProLiance (Related Party)	13		12		13		13
Other top 10 customers	24		20		24		21
Remaining customers	33		37		33		36
Total percentage	100	%	100	%	100	%	100	%

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;

•

See Note 8 and Note 11 for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.

Asset Retirement Obligations, Policy [Policy Text Block]

See Note 5 for additional related information.

Income Tax, Policy [Policy Text Block]

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

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

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

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

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	84	$	75	$	17	$	106
Cash paid for income taxes	—		32		—		35

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

The following table presents the balance in the allowance for doubtful accounts and activity:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Beginning balance	$	1	$	1	$	1	$	1
Additions: charged to cost and expenses	—		—		—		—
Deductions: write-off of uncollectible accounts	—		—		—		—
Other	—		—		—		—
Ending balance	$	1	$	1	$	1	$	1

Schedule of Inventory, Current [Table Text Block]

The following table presents the components of inventory:



	December 31,
	2013		2012
Natural gas ⁽¹⁾	$	184	$	124
Materials and supplies	19		20
	$	203	$	144


⁽¹⁾	Natural gas volumes held for operations at December 31, 2013 and 2012 were 42,843,000 MMBtu and 34,891,000 MMBtu, respectively.

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

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
BG Energy Holdings LTD	30	%	31	%	30	%	30	%
ETC ProLiance (Related Party)	13		12		13		13
Other top 10 customers	24		20		24		21
Remaining customers	33		37		33		36
Total percentage	100	%	100	%	100	%	100	%

ETE Merger and Other Transactions (Tables)

12 Months Ended

Dec. 31, 2013

ETE Merger and Holdco Transaction [Abstract]

Business acquisition

The table below represents the amounts allocated to Panhandle’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values. Certain amounts included in the purchase price allocation, as of December 31, 2012, may have been changed from amounts previously reflected based on management’s review of the valuation. The goodwill resulting from the ETE Merger was primarily due to expected commercial and operational synergies and is not deductible for tax purposes.



Cash and cash equivalents	$	—
Other current assets	229
Property and equipment	4,093
Goodwill	1,785
Identified intangibles ⁽¹⁾	55
Other non-current assets	783
Long-term debt, including current portion	(1,780		)
Deferred income taxes	(773		)
Other liabilities	(431		)
Total fair value of partners’ capital	$	3,961


⁽¹⁾	Identified intangibles will be amortized over a life of approximately 17.5 years and are included in Other non-current assets in the consolidated balance sheets.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

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



	Successor			Predecessor
	Year Ended December 31, 2013	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Transportation and storage of natural gas ⁽¹⁾	31	7		$	1	$	3
Operating, maintenance and general	59	61	⁽²⁾	14		58
Interest income — affiliates	2	2		2		9


⁽¹⁾	Represents transportation and storage revenues with ETC and Sunoco, subsidiaries of ETP (in the successor periods) and MGE, a division of Southern Union that was sold in the third quarter of 2013.


⁽²⁾	Primarily represents corporate charges for employee expenses related to the ETE Merger offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

The following table provides a summary of the related party balances included in the consolidated balance sheets:



	December 31,
	2013		2012
Non-current notes receivable from related party — Southern Union	$	532	$	831

Accounts receivable from related companies ⁽¹⁾	$	4	$	14

Cash advances from affiliate	$	120	$	—

Accounts payable to related companies:
Southern Union — other ⁽²⁾	$	—	$	26
Other ⁽³⁾	14		1
	$	14	$	27


⁽¹⁾	Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus and other affiliates.


⁽²⁾	Accounts payable from related companies reflected above primarily related to payroll funding, including merger-related expenses, provided by Southern Union.


⁽³⁾	Accounts payable from related companies reflected above primarily related to various administrative and operating costs paid by ETP and other affiliate companies on behalf of the Company.

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Beginning balance	$	42		$	41		$	41	$	57
Incurred	—			1			—		1
Revisions	11			3			—		—
Settled	(1		)	(5		)	—		(17		)
Accretion expense	3			2			—		—
Ending balance	$	55		$	42		$	41	$	41

Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2013

Statement of Comprehensive Income [Abstract]

Schedule Of Comprehensive Income Loss Tax

The tables below set forth the tax amounts included in the respective components of other comprehensive income:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$	—		$	—		$	2	$	9
Change in fair value of interest rate hedges	—			—			—		(1		)
Actuarial loss relating to postretirement benefits	(2		)	(6		)	—		(6		)
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—			—		(1		)
	$	(2	)	$	(6	)	$	2	$	1

Schedule of Accumulated Other Comprehensive Income (Loss)

The table below presents the components in accumulated other comprehensive income (loss):



	December 31,
	2013		2012
Other postretirement plan - net actuarial gain (loss) and prior service costs, net	$	3	$	(9	)
Total accumulated other comprehensive income (loss), net of tax	$	3	$	(9	)

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule Of Debt Instruments

The following table sets forth the debt obligations of the Company at the dates indicated:



	December 31,
	2013		2012
6.05% Senior Notes due 2013	$	—	$	250
6.20% Senior Notes due 2017	300		300
8.125% Senior Notes due 2019	150		150
7.00% Senior Notes due 2029	66		66
7.00% Senior Notes due 2018	400		400
Term Loan due 2015	—		455
Unamortized fair value adjustments	107		136
Total debt outstanding	1,023		1,757
Current portion of long-term debt	—		(258		)
Total long-term debt	$	1,023	$	1,499

Schedule of Maturities of Long-term Debt

As of December 31, 2013, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2014	$	—
2015	—
2016	—
2017	300
2018	400
Thereafter	216
Total	$	916

- 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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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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-Name Accounting Standards Codification
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-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 10
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-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-Section 50
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Benefits (Tables)

12 Months Ended

Dec. 31, 2013

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.



	Successor						Predecessor
	December 31, 2013			December 31, 2012			March 25, 2012
Change in benefit obligation:
Benefit obligation at beginning of period	$	38		$	93		$	88
Service cost	—			—			1
Interest cost	1			1			1
Amendments	—			16			—
Actuarial loss and other	(16		)	4			3
Benefits paid, net	(2		)	(1		)	—
Curtailments	—			(75		)	—
Benefit obligation at end of period	$	21		$	38		$	93
Change in plan assets:
Fair value of plan assets at beginning of period	$	90		$	82		$	75
Return on plan assets and other	7			3			5
Employer contributions	8			6			2
Benefits paid, net	(2		)	(1		)	—
Fair value of plan assets at end of period	$	103		$	90		$	82

Amount (overfunded) underfunded at end of period ⁽¹⁾	$	(82	)	$	(52	)	$	11

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(20	)	$	(1	)	$	—
Prior service cost	16			16			—
	$	(4	)	$	15		$	—


⁽¹⁾	Underfunded balance is recognized as a non-current liability in the consolidated balance sheets. Overfunded balance is recognized 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:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Service cost	$	—		$	—		$	1		$	2
Interest cost	1			1			1			4
Expected return on plan assets	(5		)	(3		)	(1		)	(3		)
Prior service credit amortization	1			—			(1		)	(2		)
Actuarial loss amortization	(1		)	—			—			—
Curtailment recognition⁽¹⁾	—			(11		)	—			—
Net periodic benefit cost	$	(4	)	$	(13	)	$	—		$	1

⁽¹⁾

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:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Discount rate	3.70	%	3.64	%	4.26	%	5.54	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	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:



	Successor				Predecessor
	December 31, 2013		December 31, 2012		March 25, 2012
Health care cost trend rate assumed for next year	8.00	%	8.50	%	8.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.90	%	4.50	%	4.75	%
Year that the rate reaches the ultimate trend rate	2021		2020		2019

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,
	2013		2012
Cash and cash equivalents	$	2	$	2
Mutual fund ⁽¹⁾	101		88
Total	$	103	$	90

⁽¹⁾

Schedule of Expected Benefit Payments [Table Text Block]



Years	Expected Benefit Payments
2014	$	2
2015	2
2016	2
2017	2
2018	1
2019 – 2023	6

Taxes on Income (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

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

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



	Successor					Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Current expense (benefit):
Federal	$	58	$	(8	)	$	5	$	24
State	9		(2		)	1		(5		)
Total	67		(10		)	6		19
Deferred expense:
Federal	$	44	$	72		$	17	$	67
State	7		14			2		9
Total	51		86			19		76
Total income tax expense	$	118	$	76		$	25	$	95

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:



	Successor					Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Computed statutory income tax expense at 35%	$	(133	)	$	57	$	23	$	92
Changes in income taxes resulting from:
Non-deductible executive compensation	—			11		—		—
State income taxes, net of federal income tax benefit	10			8		2		3
Non-deductible goodwill impairment	241			—		—		—
Income tax expense	$	118		$	76	$	25	$	95

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,
	2013			2012
Deferred income tax assets:
Other postretirement benefits	$	5		$	13
Debt amortization	43			52
Other	19			18
Total deferred income tax assets	67			83

Deferred income tax liabilities:
Property, plant and equipment	(967		)	(925		)
Other	(2		)	(2		)
Total deferred income tax liabilities	(969		)	(927		)
Net deferred income tax liability	(902		)	(844		)
Less current income tax assets	9			9
Accumulated deferred income taxes	$	(911	)	$	(853	)

Derivative Instrument and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives Effect On Income Table

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



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Cash Flow Hedges:
Change in fair value – increase in accumulated other comprehensive income	$	—	$	—	$	—	$	1
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	—		—		4		22

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

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

The following table provides a summary of property, plant and equipment:



		December 31,
	Lives in Years	2013			2012
Transmission	5 – 46	$	2,649		$	2,580
Gathering	26	96			114
Underground storage	5 – 46	318			306
General plant - LNG	5 – 40	967			966
General plant - other	3 – 40	108			110
Plant in service		4,138			4,076
Construction work in progress		69			45
Total property, plant and equipment		4,207			4,121
Accumulated depreciation and amortization		(211		)	(57		)
Net property, plant and equipment		$	3,996		$	4,064

SHARE-BASED COMPENSATION Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

Stock Options. The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable:



	Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2010	203,903		$	20.27
Exercised	(38,596	)	17.56
Outstanding December 31, 2011	165,307		$	20.90

Exercisable December 31, 2011	165,307		20.90

SarsExercisePriceRange [Table Text Block]

SARS. The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable:



	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2010	616,803		$	20.71
Exercised	(27,389	)	15.87
Forfeited	(30,512	)	27.41
Outstanding December 31, 2011	558,902		$	20.58

Exercisable December 31, 2011	423,815		19.61

Schedule Of Share Based Compensation Restricted Stock Liability Units Award Activity [Table Text Block]

The following table provides information on restricted stock liability awards granted, released and forfeited for the periods presented.



	Number of Restricted Stock Liability Units Outstanding		Weighted-Average Grant Date Fair Value
Restricted shares at December 31, 2010	165,870		$	20.68
Granted	51,611		42.08
Released	(87,509	)	18.47
Forfeited	(4,918	)	18.97
Restricted shares at December 31, 2011	125,054		$	31.15

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies [Abstract]

Environmental Liabilities Table



	December 31,
	2013		2012
Current	$	1	$	1
Non-current	3		5
Total environmental liabilities	$	4	$	6

QUARTERLY OPERATIONS Quarterly Operations (Tables)

12 Months Ended

Dec. 31, 2013

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:



			Successor
			Quarters Ended
			March 31, 2013			June 30, 2013		September 30, 2013		December 31, 2013			Total
Operating revenues			$	199		$	232	$	180	$	190		$	801
Operating income (loss)			81			126		71		(611		)	(333		)
Net income (loss)			42			69		37		(647		)	(499		)

	Predecessor		Successor
	Period from January 1, 2012 to March 25, 2012		Period from March 26, 2012 to March 31, 2012			Quarters Ended							Total Period from March 26, 2012 to December 31, 2012
	Period from January 1, 2012 to March 25, 2012		Period from March 26, 2012 to March 31, 2012			June 30, 2012		September 30, 2012		December 31, 2012			Total Period from March 26, 2012 to December 31, 2012
Operating revenues	$	194	$	13		$	185	$	189	$	205		$	592
Operating income (loss)	88		(26		)	65		77		89			205
Net income (loss)	40		(19		)	30		37		40			88

Description of the Business (Details)	12 Months Ended
Description of the Business (Details)	Dec. 31, 2013
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 - Inventory (Details)
$ in Millions

Dec. 31, 2013

USD ($)

MMbtu

Dec. 31, 2012

USD ($)

MMbtu

System natural gas and operating supplies

$ 203

$ 144

Successor

Natural Gas Volumes | MMbtu

42,843,000

34,891,000

Natural Gas Inventory

^[1]

$ 184

$ 124

Inventory, Raw Materials and Supplies

Energy Related Inventory

$ 203

$ 144

[1]	(1) Natural gas volumes held for operations at December 31, 2013 and 2012 were 42,843,000 MMBtu and 34,891,000 MMBtu, respectively.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Allowance for Doubtful Accounts (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Beginning balance		$ 1	$ 1
Additions: charged (credited) to expense		0	0
Deductions: write-off of uncollectible accounts		0	0
Other		0	0
Ending balance	$ 1	1	$ 1
Predecessor
Beginning balance	1	$ 1		$ 1
Additions: charged (credited) to expense	0			0
Deductions: write-off of uncollectible accounts	0			0
Other	0			0
Ending balance	$ 1			$ 1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Top Customers (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Entity-Wide Revenue, Major Customer, Percentage		100.00%	100.00%
Predecessor
Entity-Wide Revenue, Major Customer, Percentage	100.00%			100.00%
BG LNG Services \| Successor
Entity-Wide Revenue, Major Customer, Percentage		31.00%	30.00%
BG LNG Services \| Predecessor
Entity-Wide Revenue, Major Customer, Percentage	30.00%			30.00%
ProLiance \| Successor
Entity-Wide Revenue, Major Customer, Percentage		12.00%	13.00%
ProLiance \| Predecessor
Entity-Wide Revenue, Major Customer, Percentage	13.00%			13.00%
Other Top 10 Customers \| Successor
Entity-Wide Revenue, Major Customer, Percentage		20.00%	24.00%
Other Top 10 Customers \| Predecessor
Entity-Wide Revenue, Major Customer, Percentage	24.00%			21.00%
Remaining Customers \| Successor
Entity-Wide Revenue, Major Customer, Percentage		37.00%	33.00%
Remaining Customers \| Predecessor
Entity-Wide Revenue, Major Customer, Percentage	33.00%			36.00%

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2010
Restricted Cash and Cash Equivalents Items
Cash and cash equivalents			$ 1
Successor
Restricted Cash and Cash Equivalents Items
Cash and cash equivalents	$ 0	$ 0	0
Goodwill, Impairment Loss		0	689
Interest Paid, Net		75	84
Income Taxes Paid, Net		$ 32	$ 0
Predecessor
Restricted Cash and Cash Equivalents Items
Cash and cash equivalents	0			$ 0	$ 0
Goodwill, Impairment Loss	0			0
Interest Paid, Net	17			106
Income Taxes Paid, Net	$ 0			$ 35

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Politicies - Period End Cash Balances (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash and Cash Equivalents
Cash and cash equivalents	$ 1
Successor
Cash and Cash Equivalents
Cash and cash equivalents	$ 0	$ 0	$ 0
Predecessor
Cash and Cash Equivalents
Cash and cash equivalents			$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of significant accounting policies - goodwill (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
GOODWILL	$ 1,785	$ 1,096
Trunkline LNG [Member]
GOODWILL	873	184
Successor
Goodwill, Impairment Loss	$ 0	$ 689

Mergers and Other Transactions (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	4 Months Ended	9 Months Ended	12 Months Ended
	Feb. 28, 2014	Mar. 25, 2012	Apr. 30, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Feb. 19, 2014	Jun. 24, 2013
Merger related expenses				$ 48
Net gain due to curtailment of postretirement employee benefit plans				$ 11
Intangible asset, estimated useful life						17 years 6 months
Business Combination, Cost of Acquired Entity, Purchase Price		$ 3,961
ETE Merger [Member]
Business Acquisition Units Acquired		56,982,160
Business Combination, Consideration Transferred		$ 3,010
Citrus Merger [Member]
Percentage owned by equity investment					50.00%
Merger amount, in cash		$ 1,900
Business Acquisition Units Acquired		2,300,000
Business Combination, Cost of Acquired Entity, Purchase Price		$ 2,000
ETE [Member] \| Holdco Transaction [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			60.00%
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
ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					2,200,000
Notes Payable, Related Parties, Noncurrent							$ 1,090
ETP [Member] \| Holdco Transaction [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			40.00%		100.00%
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
Trunkline LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed	18,700,000

Mergers and Other Transactions (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Mar. 25, 2012

ETE Merger and Holdco Transacation [Abstract]

Cash and cash equivalents

$ 0

Other current assets

229

Property and equipment

4,093

Goodwill

1,785

Identified intangibles (1)

^[1]

Other non-current assets

783

Long-term debt, including current portion

(1,780)

Deferred income taxes

(773)

Other liabilities

(431)

Total fair value of partners’ capital

$ 3,961

Intangible asset, estimated useful life

17 years 6 months

[1]	Identified intangibles will be amortized over a life of approximately 17.5 years and are included in Other non-current assets in the consolidated balance sheets.

Related Party Transactions (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 25, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Successor

Other income, net:

Interest income

$ 2

Successor | Southern Union

Operation and maintenance:

Transportation and storage of natural gas

^[1]

Other income, net:

Interest income

Successor | Affiliated Entity

Operation and maintenance:

Operating, maintenance and general

$ 61

^[2]

$ 59

Predecessor

Other income, net:

Interest income

$ 2

$ 9

Predecessor | Southern Union

Operation and maintenance:

Transportation and storage of natural gas

^[1]

Other income, net:

Interest income

Predecessor | Affiliated Entity

Operation and maintenance:

Operating, maintenance and general

$ 14

$ 58

[1]	(1) Represents transportation and storage revenues with ETC and Sunoco, subsidiaries of ETP (in the successor periods) and MGE, a division of Southern Union that was sold in the third quarter of 2013.
[2]	(2) Primarily represents corporate charges for employee expenses related to the ETE Merger offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

Related Party Balances (Details) - USD ($)
$ in Millions

Dec. 31, 2013

Dec. 31, 2012

Related Party Transaction

Notes receivable - related party, noncurrent

$ 532

$ 831

Accounts receivable — related parties (1)

^[1]

Cash Flow From Advances To Payments From Affiliates

^[1]

120

Accounts payable — related parties:

Southern Union

Related Party Transaction

Notes receivable - related party, noncurrent

532

831

Other accounts payable

Related Party Transaction

Accounts payable — related parties:

^[2]

Other accounts payable | Southern Union

Related Party Transaction

Accounts payable — related parties:

^[3]

$ 0

$ 26

[1]	1) Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus and other affiliates.
[2]	(3) Accounts payable from related companies reflected above primarily related to various administrative and operating costs paid by ETP and other affiliate companies on behalf of the Company.
[3]	(2) Accounts payable from related companies reflected above primarily related to payroll funding, including merger-related expenses, provided by Southern Union.

- Definition

For an unclassified balance sheet, amount of receivables arising from transactions with related parties.

+ References + Details

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Other ARO Assets
ARO Underlying Asset			$ 13	$ 1
Predecessor
Asset Retirement Obligation, Liabilities Incurred	$ 0	$ 1
Asset Retirement Obligation, Revision of Estimate	0	0
Asset Retirement Obligation, Liabilities Settled	$ 0	$ (17)

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Other ARO Assets
ARO Underlying Asset	$ 13	$ 1

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Schedule of Changes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Beginning balance		$ 41	$ 42
Incurred		1	0
Revisions		3	11
Settled		(5)	(1)
Accretion expense		2	3
Ending balance	$ 41	42	$ 55
Predecessor
Beginning balance	41	$ 41		$ 57
Incurred	0			1
Revisions	0			0
Settled	0			(17)
Accretion expense	0			0
Ending balance	$ 41			$ 41

Comprehensive Income (Loss) - Tax amounts in other comprehensive income (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings		$ 0	$ 0
Change in fair value of interest rate hedges		0	0
Actuarial loss relating to postretirement benefits		(6)	(2)
Reclassification of prior service credit relating to other postretirement benefits into earnings		0	0
Income tax benefit included in other comprehensive income		$ (6)	$ (2)
Predecessor
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$ 2			$ 9
Change in fair value of interest rate hedges	0			(1)
Actuarial loss relating to postretirement benefits	0			(6)
Reclassification of prior service credit relating to other postretirement benefits into earnings	0			(1)
Income tax benefit included in other comprehensive income	$ 2			$ 1

Comprehensive Income (Loss) - Components of AOCI (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Comprehensive Income Loss [Line Items]
Other postretirement plan - net actuarial gain (loss) and prior service costs, net	$ 3	$ (9)
Total accumulated other comprehensive income (loss), net of tax	$ 3	$ (9)

- 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 - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2013	Jun. 24, 2013	Dec. 31, 2012	Mar. 25, 2012	Feb. 29, 2012
Debt Instrument
Long term debt, face amount					$ 455
Debt Instrument, Fair Value Disclosure	$ 1,060		$ 1,810
Long term debt, amount outstanding	1,023		$ 1,757
Term Loan Due August 2013
Debt Instrument
Long term debt, face amount	250
Term Loan Due June 2012
Debt Instrument
Long term debt, face amount				$ 465
Long term debt, amount outstanding				$ 342
Term Loan Due March 2012
Debt Instrument
Long term debt, face amount					$ 455
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument
Senior Notes	83
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
ETP [Member]
Debt Instrument
Senior Notes	$ 1,470

Debt Obligations - Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument
Unamortized fair value adjustments	$ 107	$ 136
Total debt outstanding	1,023	1,757
Current portion of long-term debt	0	(258)
Total long-term debt	$ 1,023	1,499
6.05% Senior Notes due 2013
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Senior Notes	$ 0	250
6.20% Senior Notes due 2017
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Senior Notes	$ 300	300
8.125% Senior Notes due 2019
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Senior Notes	$ 150	150
7.00% Senior Notes due 2029
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Senior Notes	$ 66	66
7.00% Senior Notes due 2018
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Senior Notes	$ 400	400
Term Loan due 2015
Debt Instrument
Term Loans	$ 0	$ 455

DEBT OBLIGATIONS Debt Obligations - Future Maturities (Details) $ in Millions	Dec. 31, 2013 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	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	300
Long-term Debt, Maturities, Repayments of Principal in Year Five	400
Long-term Debt, Maturities, Repayments of Principal after Year Five	216
Long Term Debt Maturities Repayments Of Principal Total	$ 916

BENEFITS Benefits - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure
Defined Contribution Plan Employers Matching Contribution Percentage to Participants Percentage Conribution				100.00%
Pretax curtailment gain				$ 70
Noncurrent refund liability				59
Curtailment recognition (1)				$ 11
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year			$ 8
Defined Contribution Plan, Employer Matching Contribution, Percent				5.00%
Supplemental Employee Retirement Plans, Defined Benefit \| Successor
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized		$ 2	2
Supplemental Employee Retirement Plans, Defined Benefit \| Predecessor
Defined Benefit Plan Disclosure
Defined Contribution Plan, Employer Matching Contribution, Percent				3.00%
Defined Contribution Plan, Cost Recognized	$ 1				$ 6
Savings Plan \| Successor
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized		3	3
Savings Plan \| Predecessor
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized	1				$ 5
Other Postretirement Benefit Plans, Defined Benefit \| Successor
Defined Benefit Plan Disclosure
Curtailment recognition (1)		$ (75)	$ 0
Other Postretirement Benefit Plans, Defined Benefit \| Predecessor
Defined Benefit Plan Disclosure
Curtailment recognition (1)	$ 0

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

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 25, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Curtailments

$ 11

Fair value of plan assets at beginning of period

$ 90

Fair value of plan assets at end of period

$ 90

103

Other Postretirement Benefit Plans, Defined Benefit | Successor

Benefit obligation at beginning of period

Service cost

Interest cost

Amendments

Actuarial loss and other

(16)

Benefits paid, net

(1)

(2)

Curtailments

(75)

Benefit obligation at end of period

$ 93

Fair value of plan assets at beginning of period

Return on plan assets and other

Employer contributions

Fair value of plan assets at end of period

103

Amount (overfunded) underfunded at end of period (1)

^[1]

(52)

(82)

(52)

Net actuarial loss

(1)

(20)

(1)

Prior service cost

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

$ (4)

Other Postretirement Benefit Plans, Defined Benefit | Predecessor

Benefit obligation at beginning of period

Service cost

Interest cost

Amendments

Actuarial loss and other

Benefits paid, net

Curtailments

Benefit obligation at end of period

Fair value of plan assets at beginning of period

$ 82

$ 75

Return on plan assets and other

Employer contributions

Fair value of plan assets at end of period

Amount (overfunded) underfunded at end of period (1)

^[1]

Net actuarial loss

Prior service cost

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

$ 0

[1]	Underfunded balance is recognized as a non-current liability in the consolidated balance sheets. Overfunded balance is recognized as a non-current asset in the consolidated balance sheets.

Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 25, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Defined Benefit Plan Disclosure

Curtailment recognition (1)

$ 11

Pretax curtailment gain

Noncurrent refund liability

$ 59

Successor

Defined Benefit Plan Disclosure

Service cost

$ 0

Interest cost

Expected return on plan assets

(3)

(5)

Prior service credit amortization

Actuarial loss amortization

(1)

Curtailment recognition (1)

(11)

^[1]

Net periodic benefit cost

$ (13)

$ (4)

Predecessor

Defined Benefit Plan Disclosure

Service cost

$ 1

$ 2

Interest cost

Expected return on plan assets

(1)

(3)

Prior service credit amortization

(1)

(2)

Actuarial loss amortization

Curtailment recognition (1)

Net periodic benefit cost

$ 0

$ 1

[1]

BENEFITS Benefits - Weighted-average Assumptions (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Postemployment Benefits [Abstract]
Discount rate	4.26%	3.64%	3.70%	5.54%
Tax exempt accounts	7.00%	7.00%	7.00%	7.00%
Taxable accounts	4.50%	4.50%	4.50%	4.50%

BENEFITS Benefits - Assumed Health Care Cost Trend Rates Used (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013
Postemployment Benefits [Abstract]
Health care cost trend rate assumed for next year	8.00%	8.50%	8.00%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75%	4.50%	4.90%
Year that the rate reaches the ultimate trend rate	2019	2020	2021

BENEFITS Benefits - 1% Change in Assumed Health Care Cost Trend Rates Used (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($)
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, 2013	Dec. 31, 2012
Defined Benefit Plan, Fair Value of Plan Assets	$ 103	$ 90
Cash and Cash Equivalents
Defined Benefit Plan, Fair Value of Plan Assets	2	2
Mutual Fund
Defined Benefit Plan, Fair Value of Plan Assets	$ 101	$ 88
Other Postretirement Benefit Plans, Defined Benefit
Large Cap US Equitiies	19.00%	17.00%
Small Cap US Equities	5.00%	3.00%
International Equities	8.00%	10.00%
Fixed Income Securities	55.00%	53.00%
Cash Fund Investments	7.00%	10.00%
Other Investments - Plan Asset Allocation	6.00%	7.00%

BENEFITS Benefits - Estimate of Expected Benefit Payments (Details) - Other Postretirement Benefit Plans, Defined Benefit $ in Millions	Dec. 31, 2013 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	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three, net	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four, net	2
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

Taxes on Income - Current and Deferred (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Income Tax Disclosure
Federal		$ (8)	$ 58
State		(2)	9
Current Income Tax Expense (Benefit)		(10)	67
Federal		72	44
State		14	7
Deferred income taxes		86	51
Total income tax expense		$ 76	$ 118
Predecessor
Income Tax Disclosure
Federal	$ 5			$ 24
State	1			(5)
Current Income Tax Expense (Benefit)	6			19
Federal	17			67
State	2			9
Deferred income taxes	19			76
Total income tax expense	$ 25			$ 95

TAXES ON INCOME Taxes on Income - Actual versus Statutory (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Computed statutory income tax expense at 35%		$ 57	$ (133)
Income Tax Reconciliation, Nondeductible Expense, Other		11	0
State income taxes, net of federal income tax benefit		8	10
Permanent differences and other		0	241
Total income tax expense		$ 76	$ 118
Predecessor
Computed statutory income tax expense at 35%	$ 23			$ 92
Income Tax Reconciliation, Nondeductible Expense, Other	0			0
State income taxes, net of federal income tax benefit	2			3
Permanent differences and other	0			0
Total income tax expense	$ 25			$ 95

TAXES ON INCOME Income Taxes - Effective Rate Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Computed statutory income tax expense at 35%		$ 57	$ (133)
Income Tax Reconciliation, Nondeductible Expense, Other		11	0
State income taxes, net of federal income tax benefit		8	10
Income Tax Reconciliation, Other Adjustments		0	241
Total income tax expense		$ 76	$ 118
Predecessor
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Computed statutory income tax expense at 35%	$ 23			$ 92
Income Tax Reconciliation, Nondeductible Expense, Other	0			0
State income taxes, net of federal income tax benefit	2			3
Income Tax Reconciliation, Other Adjustments	0			0
Total income tax expense	$ 25			$ 95

TAXES ON INCOME Taxes on Income - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Other postretirement benefits	$ 5	$ 13
Debt amortization	43	52
Other	19	18
Total deferred income tax assets	67	83
Property, plant and equipment	(967)	(925)
Other	(2)	(2)
Total deferred income tax liabilities	(969)	(927)
Net deferred income tax liability	(902)	(844)
Less current income tax assets	9	9
Accumulated deferred income taxes	$ (911)	$ (853)

TAXES ON INCOME Taxes on Income - Narrative (Details) $ in Millions	Dec. 31, 2013 USD ($)
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 1
Unrecognized tax benfits for state filing positions, net of federal tax	$ 1

Derivative Insturments and Hedging (Narrative) (Details) $ in Millions	Feb. 29, 2012 USD ($)
Derivative [Line Items]
Interest rate swaps, notional amount	$ 455
Long term debt, face amount	$ 455

Derivative Instrument and Hedging Activities (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Successor
Derivative [Line Items]
Change in fair value – increase in accumulated other comprehensive income		$ 0	$ 0
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense		$ 0	$ 0
Predecessor
Derivative [Line Items]
Change in fair value – increase in accumulated other comprehensive income	$ 0			$ 1
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	$ 4			$ 22

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - PPE Type (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Construction work in progress	$ 69	$ 45
Total property, plant and equipment	4,207	4,121
Accumulated depreciation and amortization	(211)	(57)
Net property, plant and equipment	(3,996)	(4,064)
Transmission
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	2,649	2,580
Gathering
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	96	114
Underground storage
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	318	306
General plant - LNG
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	967	966
General plant - other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	108	110
Plant in service
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	4,138	4,076
Construction work in progress
Property, Plant and Equipment [Line Items]
Construction work in progress	$ 69	$ 45
Minimum \| Transmission
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Minimum \| Underground storage
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Minimum \| General plant - LNG
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Minimum \| General plant - other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P3Y0M
Maximum \| Transmission
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Maximum \| Gathering
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P26Y0M
Maximum \| Underground storage
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Maximum \| General plant - LNG
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M
Maximum \| General plant - other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Capitalized Computer Software, Net	$ 34
Capitalized Computer Software, Accumulated Amortization	51
Capitalized Computer Software, Amortization	7
Contributions in Aid of Construction	49
Finite-Lived Intangible Assets, Accumulated Amortization	5
Depreciation, Depletion and Amortization	$ 2

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Transmission \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Transmission \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Gathering \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P26Y0M
Underground storage \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Underground storage \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
General plant - LNG \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
General plant - LNG \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M
General plant and other \| Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P3Y0M
General plant and other \| Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M

SHARE-BASED COMPENSATION Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares Per Employee	500,000
Exercise price for a stock option, minimum	100.00%
Options and SARS Fair Value of Vested		$ 4
Compensation expense for affiliate equity awards.			$ 1	$ 1
Aggregate intrinsic value of total options and SARs outstanding		16
Aggregate intrinsic value of total options and SARs exercisable		13
Aggregate intrinsic value of total options and SARs exercised		1
Restricted Stock and RSU Fair Value Released		4
Restricted Stock or Unit Expense		4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Total Share-based Liabilities Paid		$ 1

SHARE-BASED COMPENSATION Stock-Based Compensation - Stock Options (Details)	12 Months Ended
	Dec. 31, 2011 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding \| shares	203,903
Weighted Average Exercise Price \| $ / shares	$ 20.27
Exercised \| shares	(38,596)
Outstanding \| shares	165,307
Weighted Average Exercise Price \| $ / shares	$ 20.90
Exercisable \| shares	165,307
Weighted Average Exercise Price Exercisable \| $ / shares	$ 20.90
ShareBasedCompensationArrangementByShareBasedPayment Award Excercises in Period Weighted Average Excercise Price \| $ / shares	$ 17.56

SHARE-BASED COMPENSATION Stock-Based Compensation - SARs (Details)	12 Months Ended
	Dec. 31, 2011 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding \| shares	616,803
Sars Outstanding Weighted Average Exercise Price \| $ / shares	$ 20.71
Exercised \| shares	(27,389)
Sars Exercised Weighted Average Exercise Price \| $ / shares	$ 15.87
Forfeitures \| shares	(30,512)
Sars Forfeited Weighted Average Exercise Price \| $ / shares	$ 27.41
Outstanding \| shares	558,902
Sars Outstanding Weighted Average Exercise Price \| $ / shares	$ 20.58
SARs Exercisable \| shares	423,815
SARs Exercisable Weighted Average Exercise Price \| $ / shares	$ 19.61

SHARE-BASED COMPENSATION Stock-Based Compensation - Stock Options Valuation Assumptions (Details)	12 Months Ended
	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Volatility Rate, Minimum	32.79%
Expected Volatility Rate, Maximum	32.82%
Expected Dividend Yield, Minimum	2.47%
Expected Dividend Yield, Maximum	2.47%
Risk Free Interest Rate, Minimum	2.28%
Risk Free Interest Rate, Maximum	2.40%
Expected Life, Maximum	6 years

SHARE-BASED COMPENSATION Stock-Based Compensation - Restricted Liability Units (Details)	12 Months Ended
	Dec. 31, 2011 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock Units Oustanding \| shares	165,870
Restricted Stock Units Outstanding Weighted Average Grant Date Fair Value \| $ / shares	$ 20.68
Restricted Stock Units Granted \| shares	51,611
Restricted Stock Units Granted Weighted Average Grant Date Fair Value \| $ / shares	$ 42.08
Restricted Stock Units Released \| shares	(87,509)
Restricted Stock Units Released Weighted Average Grant Date Fair Value \| $ / shares	$ 18.47
Restricted Stock Units Forfeited \| shares	(4,918)
Restricted Stock Units Forfeited Weighted Average Grant Date Fair Value \| $ / shares	$ 18.97
Restricted Stock Units Oustanding \| shares	125,054
Restricted Stock Units Outstanding Weighted Average Grant Date Fair Value \| $ / shares	$ 31.15

Commitment and Contingenices (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Estimated litigation liability	$ 6	$ 6
Estimated fair value of all assets of pension plans	103	$ 90
Regency 4.50% Senior Notes Due 2023 [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Current Carrying Value	$ 600
Debt Instrument, Interest Rate, Stated Percentage	4.50%

Commitments and Contingencies - Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Current	$ 1	$ 1
Non-current	3	5
Total environmental liabilities	$ 4	$ 6

QUARTERLY OPERATIONS Quarterly Operations (Details) - USD ($) $ in Millions		3 Months Ended								9 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2011
Predecessor
Operating revenues									$ 194			$ 804
Operating income (loss)									88			362
Net income									$ 40			$ 168
Successor
Operating revenues	$ 13	$ 190	$ 180	$ 232	$ 199	$ 205	$ 189	$ 185		$ 592	$ 801
Operating income (loss)	(26)	(611)	71	126	81	89	77	65		205	(333)
Net income	$ (19)	$ (647)	$ 37	$ 69	$ 42	$ 40	$ 37	$ 30		$ 88	$ (499)

- Definition

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

+ References

+ Details

Label	Element	Value
Supplemental Employee Retirement Plan, Defined Benefit [Member]
Company Contributions Vested	pepl_CompanyContributionsVested	100.00%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	us-gaap_OtherComprehensiveIncomeDefinedBenefitPlanNetPriorServiceCostCreditArisingDuringPeriodBeforeTax	$ 1,000,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	us-gaap_DefinedBenefitPlansEstimatedFutureEmployerContributionsInNextFiscalYear	$ 8,000,000
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Successor [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	us-gaap_DefinedBenefitPlanAssumptionsUsedCalculatingBenefitObligationDiscountRate	4.26%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	us-gaap_DefinedBenefitPlanAssumptionsUsedCalculatingBenefitObligationDiscountRate	3.51%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Predecessor [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	us-gaap_DefinedBenefitPlanAssumptionsUsedCalculatingBenefitObligationDiscountRate	4.24%
Supplemental Employee Retirement Plan, Defined Benefit [Member] \| Missouri Gas Energy [Member]
Company Contributions Years	pepl_CompanyContributionsYears	five
Cash and Cash Equivalents [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	10.00%
Equity Securities [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	35.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	25.00%
Fixed Income Securities [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum	75.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum	65.00%