10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-2921

____________________________

PANHANDLE EASTERN PIPE LINE COMPANY, LP

(Exact name of registrant as specified in its charter)

____________________________

Delaware	44-0382470
(state or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

5051 Westheimer Road

Houston, Texas 77056-5622

(Address of principle executive offices) (zip code)

(713) 989-7000

(Registrant’s telephone number, including area code)

____________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xNo ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes xNo ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨   Accelerated filer ¨   Non-accelerated filer x   Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).

Yes ¨   No x

Panhandle Eastern Pipe Line Company, LP meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.  Items 1, 2 and 7 have been reduced and Items 6, 10, 11, 12 and 13 have been omitted in accordance with Instruction I.

PANHANDLE EASTERN PIPE LINE COMPANY, LP

TABLE OF CONTENTS

		Page
PART I
ITEM 1.	BUSINESS	3
ITEM 1A.	RISK FACTORS	7
ITEM 1B.	UNRESOLVED STAFF COMMENTS	18
ITEM 2.	PROPERTIES	18
ITEM 3.	LEGAL PROCEEDINGS	18
ITEM 4.	MINE SAFETY DISCLOSURES	18
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	19
ITEM 6.	SELECTED FINANCIAL DATA	19
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	24
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	25
ITEM 9A.	CONTROLS AND PROCEDURES	25
ITEM 9B.	OTHER INFORMATION	25
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	26
ITEM 11.	EXECUTIVE COMPENSATION	26
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	26
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	26
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	26
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	27
	SIGNATURES	28

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Panhandle Eastern Pipe Line Company LP, and its subsidiaries (“Panhandle” or the “Company”) in periodic press releases and some oral statements of Panhandle officials during presentations about the Company, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” included in this annual report.

Definitions

The abbreviations, acronyms and industry terminology used in this annual report on Form 10-K are defined as follows:

/d	per day
ARO	Asset retirement obligation
Bbls	barrels
Bcf	billion cubic feet
Btu	British thermal units
Citrus	Citrus Corp.
CrossCountry Citrus	CrossCountry Citrus, LLC
CrossCountry Energy	CrossCountry Energy, LLC
EITR	Effective Income Tax Rate
EPA	United States Environmental Protection Agency
ETC	Energy Transfer Company, a wholly-owned subsidiary of ETP
ETE	Energy Transfer Equity, L.P.
ETP	Energy Transfer Partners, L.P.
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
HAPs	Hazardous air pollutants
Holdco	ETP Holdco Corporation
KDHE	Kansas Department of Health and Environment
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
LNG Holdings	Trunkline LNG Holdings, LLC
MGE	Missouri Gas Energy, Inc.

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MMBtu	Million British thermal units
NGL	Natural gas liquids
OPEB plans	Other postretirement employee benefit plans
Panhandle	PEPL and its subsidiaries
PCBs	Polychlorinated biphenyls
PEPL	Panhandle Eastern Pipe Line Company, LP
PEPL Holdings	PEPL Holdings, LLC
ppb	parts per billion
PRPs	Potentially responsible parties
SARs	Stock appreciation rights
Sea Robin	Sea Robin Pipeline Company, LLC
SEC	United States Securities and Exchange Commission
Southern Union	Southern Union Company
Southwest Gas	Pan Gas Storage, LLC (d.b.a. Southwest Gas)
Sunoco	Sunoco, Inc.
TBtu	Trillion British thermal units
Trunkline	Trunkline Gas Company, LLC
Trunkline LNG	Trunkline LNG Company, LLC

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PART I

ITEM 1.  BUSINESS

OUR BUSINESS

Introduction

Panhandle, a Delaware limited partnership, is an indirect wholly-owned subsidiary of Southern Union.  The Company 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;

• 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;

• Trunkline LNG, a direct wholly-owned subsidiary of LNG Holdings; and

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

On March 26, 2012, Southern Union, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among Southern Union, ETE and Merger Sub, Merger Sub was merged with and into Southern Union, with Southern Union continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, LLC, an indirect wholly-owned subsidiary of Southern Union (CrossCountry Energy), ETP, Citrus ETP Acquisition, LLC (ETP Merger Sub), Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of Southern Union (PEPL Holdings), and Southern Union consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and Southern Union, on the other hand.

Immediately prior to the Effective Time, Southern Union, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder and Southern Union assumed the obligations and rights of ETE thereunder.  Southern Union made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus Corp. (Citrus).  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) Southern Union contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, Southern Union entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which Southern Union agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to Southern Union) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

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On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity in exchange for a 60% equity interest in the new entity, Holdco, and (ii) 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 will control Holdco. This transaction did not result in a new basis of accounting for Southern Union.

See Note 3 to our consolidated financial statements for information related to Southern Union’s merger with ETE.

Asset Overview

The Company owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the PEPL, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  PEPL’s transmission system consists of four large diameter pipelines extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.  Trunkline’s transmission system consists of two large diameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and to Michigan.  Sea Robin’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico.  In connection with its natural gas pipeline transmission and storage systems, the Company has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.  Through Trunkline LNG, the Company owns and operates an LNG terminal in Lake Charles, Louisiana.

We are currently developing plans to convert certain existing pipeline assets from natural gas transportation to crude oil transportation.  These plans include the proposed abandonment of certain pipeline segments of Trunkline, which are currently operating in natural gas service, and the conversion of some or all of those segments of pipeline to crude oil transportation service.  Trunkline's application to abandon those segments of pipeline from natural gas service, filed July 26, 2012, is currently pending before the FERC.  As of February 13, 2013, ETP and Enbridge (U.S.), Inc. entered into an agreement under which they will jointly market a project to transport up to 420,000 Bbls/d of crude oil from Patoka, Illinois, to refinery markets in and around Memphis, Tennessee, Baton Rouge, Louisiana, and St. James, Louisiana, utilizing a combination of newly constructed pipeline and approximately 574 miles of pipeline to be abandoned by Trunkline.  Subject to receipt of sufficient customer commitments for long-term transportation capacity and regulatory approvals, this project is expected to be in service by 2015.

We are currently studying the commercial and engineering feasibility of constructing a liquefaction facility at Trunkline LNG's existing Lake Charles LNG, regasification terminal. The project is anticipated to utilize a portion of the existing LNG regasification infrastructure, including storage tanks and marine facilities, and is expected to have the capacity to export up to 15 million tons per annum of LNG.  We expect to complete certain studies, permits and approvals through 2014, and we do not anticipate making any significant capital expenditures related to this project prior to the completion of those items.

Panhandle earns most of its revenue by entering into firm transportation and storage contracts, providing capacity for customers to transport and store natural gas or LNG in its facilities.  The Company provides firm transportation services under contractual arrangements to local distribution company customers and their affiliates, natural gas marketers, producers, other pipelines, electric power generators and a variety of end-users.  The Company’s pipelines offer both firm and interruptible transportation to customers on a short-term and long-term basis.  Demand for natural gas transmission on the Company’s pipeline systems peaks during the winter months, with the highest throughput and a higher portion of annual total operating revenues occurring during the first and fourth calendar quarters.  Average reservation revenue rates realized by the Company are dependent on certain factors, including but not limited to rate regulation, customer demand for capacity, and capacity sold for a given period and, in some cases, utilization of capacity.  Commodity or utilization revenues, which are more variable in nature, are dependent upon a number of factors including weather, storage levels and pipeline capacity availability levels, and customer demand for firm and interruptible services, including parking services.  The majority of Panhandle’s revenues are related to firm capacity reservation charges, which reservation charges accounted for approximately 87% of total revenues in 2012.

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The following table provides a summary of pipeline transportation (including deliveries made throughout the Company’s pipeline network) in TBtu:

	Successor	Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012	Period from January 1, 2012 to March 25, 2012	Years Ended December 31,
			2011	2010
PEPL transportation	430	152	564	563
Trunkline transportation	533	177	743	664
Sea Robin transportation	91	20	113	172

The following table provides a summary of certain statistical information associated with the Company at the date indicated:

	December 31, 2012
Approximate Miles of Pipelines
PEPL	6,000
Trunkline	3,000
Sea Robin	1,000
Peak Day Delivery Capacity (Bcf/d)
PEPL	2.8
Trunkline	1.7
Sea Robin	1.9
Trunkline LNG Peak Send Out Capacity (Bcf/d)	2.1
Underground Storage Capacity-Owned (Bcf)	68.1
Underground Storage Capacity-Leased (Bcf)	33.3
Trunkline LNG Terminal Storage Capacity (Bcf)	9.0
Approximate Average Number of Transportation Customers	500
Weighted Average Remaining Life in Years of Firm Transportation Contracts (1)
PEPL	5.7
Trunkline	8.9
Sea Robin (2)	N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts (1)
PEPL	8.8
Trunkline	6.0

⁽¹⁾  Weighted by firm capacity volumes.

⁽²⁾  Sea Robin’s contracts are primarily interruptible, with only four firm contracts in place.

Regulation

The Company is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.

FERC has comprehensive jurisdiction over PEPL, Trunkline, Sea Robin, Trunkline LNG and Southwest Gas.  In accordance with the Natural Gas Act of 1938, FERC’s jurisdiction over natural gas companies encompasses, among other things, the acquisition, operation and disposition of assets and facilities, the services provided and rates charged.

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FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities.  PEPL, Trunkline, Sea Robin, Trunkline LNG and Southwest Gas hold certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce.

The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

For additional information regarding the Company’s regulation and rates, see “Item 1. Business – Environmental”, “Item 1A.  Risk Factors” and Note 4 to our consolidated financial statements.

Competition

The interstate pipeline and storage systems of the Company compete with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas.  The principal elements of competition among pipelines are rates, terms of service, flexibility and reliability of service.

Natural gas competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils.  The primary competitive factor is price.  Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulation, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the ongoing demand for natural gas in the areas served by the Company.  In order to meet these challenges, the Company will need to adapt its marketing strategies, the types of transportation and storage services provided and its pricing and rates to address competitive forces.  In addition, FERC may authorize the construction of new interstate pipelines that compete with the Company’s existing pipelines.

OTHER MATTERS

Environmental

The Company is subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters.  These laws 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 requirements 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 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.  For additional information concerning the impact of environmental regulation on the Company, see “Item 1A. Risk Factors” and Note 15 to our consolidated financial statements.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business.  This includes, but is not limited to, insurance for potential liability to third parties, worker’s compensation, automobile and property insurance.  The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses.  Except for windstorm property insurance more fully described below, insurance deductibles range from $100,000 to $10 million for the various policies utilized by the Company.  As the Company renews its policies, it is possible that some of the current insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.

Oil Insurance Limited (OIL), the Company’s member mutual property insurer, revised its windstorm insurance coverage effective January 1, 2010.  Based on the revised coverage,  the per occurrence windstorm claims for onshore and offshore assets are limited to $250 million per member subject to a fixed 60% payout, up to $150 million per member, and are subject to the $750 million aggregate limit for total payout to members per incident and a $10 million deductible. The revised windstorm coverage also limits annual individual member recovery to $300 million in the aggregate. The Company has also purchased additional excess insurance coverage for its onshore assets arising from windstorm damage, which provides up to an additional $100 million of property insurance coverage over and above existing coverage or in excess of the base OIL coverage.  In the event windstorm damage

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claims are made by the Company for its onshore assets and such damage claims are subject to a scaled or aggregate limit reduction by OIL, the Company may have additional uninsured exposure prior to application of the excess insurance coverage.

Employees

At January 31, 2013, the Company had 1,065 employees.  Of these employees, 218 were represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial, and Service Workers International AFL-CIO, CLC.  The current union contract expires on May 27, 2014.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports on our internet website located at http://www.sug.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

The risks and uncertainties described below are not the only ones faced by the Company.  Additional risks and uncertainties that the Company is unaware of, or that it currently deems immaterial, may become important factors that affect it.  If any of the following risks occurs, the Company’s business, financial condition, results of operations or cash flows could be materially and adversely affected.

Risks That Relate to the Company

The Company has substantial debt and may not be able to obtain funding or obtain funding on acceptable terms because of deterioration in the credit and capital markets.  This may hinder or prevent the Company from meeting its future capital needs.

The Company has a significant amount of debt outstanding.  As of December 31, 2012, consolidated debt on the consolidated balance sheets totaled $1.76 billion outstanding, compared to total capitalization (long- and short-term debt plus partners’ capital) of $5.80 billion.

Covenants exist in certain of the Company’s debt agreements that require the Company to maintain a fixed charge coverage ratio, a leverage ratio and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Any such acceleration or inability to borrow could cause a material adverse change in the Company’s financial condition.

The Company relies on access to both short- and long-term credit as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations.  Deterioration in the Company’s financial condition could hamper its ability to access the capital markets.

Global financial markets and economic conditions have been, and may continue to be, disrupted and volatile.  The current weak economic conditions have made, and may continue to make, obtaining funding more difficult.

Due to these factors, the Company cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms.  If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to grow its existing business, complete acquisitions, refinance its debt or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s revenues and results of operations.

Further, in order for the Company to receive equity contributions or loans from its parent, Southern Union, certain state regulatory approvals are required.  This may limit the Company’s overall access to sources of capital otherwise available.  Restrictions on the Company’s ability to access capital markets could affect its ability to execute its business plan or limit its ability to pursue improvements or acquisitions on which it may otherwise rely for future growth.

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Credit ratings downgrades could increase the Company’s financing costs and limit its ability to access the capital markets.

The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements.  However, if its current credit ratings were downgraded below investment grade, the Company could be negatively impacted as follows:

• Borrowing costs associated with existing debt obligations could increase in the event of a credit rating downgrade;

• The costs of refinancing debt that is maturing or any new debt issuances could increase due to a credit rating downgrade; and

• FERC may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

The Company’s credit rating can be impacted by the credit rating and activities of its parent company, Southern Union.  Thus, adverse impacts to Southern Union and its activities, which may include activities unrelated to the Company, may have adverse impacts on the Company’s credit rating and financing and operating costs.

The financial soundness of the Company’s customers could affect its business and operating results and the Company’s credit risk management may not be adequate to protect against customer risk.

As a result of macroeconomic challenges that have impacted the economy of the United States and other parts of the world, the Company’s customers may experience cash flow concerns.  As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to the Company.  The Company’s credit procedures and policies may not be adequate to fully eliminate customer credit risk.  In addition, in certain situations, the Company may assume certain additional credit risks for competitive reasons or otherwise.  Any inability of the Company’s customers to pay for services could adversely affect the Company’s financial condition, results of operations and cash flows.

The Company is controlled by Holdco.

The Company is an indirect wholly-owned subsidiary of ETP Holdco, which is owned and controlled by ETP.  ETP executives serve as the board of managers and as executive officers of the Company.  Accordingly, ETP Holdco controls and directs all of the Company’s business affairs, decides all matters submitted for member approval and may unilaterally effect changes to its management team.  In circumstances involving a conflict of interest between ETP Holdco, on the one hand, and the Company’s creditors, on the other hand, the Company can give no assurance that ETP Holdco would not exercise its power to control the Company in a manner that would benefit ETP Holdco to the detriment of the Company’s creditors.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of ETE and/or ETP. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our Unitholders' best interests. In addition, these overlapping executive officers and directors allocate their time among us and ETE and/or ETP. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

Our affiliates may compete with us.

Our affiliates and related parties are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

The Company is subject to operating risks.

The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas, including adverse weather conditions, explosions, pollution, release of toxic substances, fires and other hazards, each of which could result in damage to or destruction of its facilities or damage to persons and property. If any of these events were to occur, the Company could suffer substantial losses. Moreover, as a result, the Company has been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. While the Company maintains insurance against many of these risks to the extent and in amounts that it believes are reasonable, the Company’s insurance coverages have significant deductibles and self-insurance levels, limits on maximum recovery, and do not cover all risks.  There is also the risk that the coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in the Company’s decision to either terminate certain coverages, increase deductibles and self-insurance levels, or

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decrease maximum recoveries.  In addition, there is a risk that the insurers may default on their coverage obligations. As a result, the Company’s results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and the consequences of terrorism may adversely impact the Company’s results of operations.

The impact that terrorist attacks, such as the attacks of September 11, 2001, may have on the energy industry in general, and on the Company in particular, is not known at this time. Uncertainty surrounding military activity may affect the Company’s operations in unpredictable ways, including disruptions of fuel supplies and markets and the possibility that infrastructure facilities, including pipelines, LNG facilities, gathering facilities and processing plants, could be direct targets of, or indirect casualties of, an act of terror or a retaliatory strike. The Company may have to incur significant additional costs in the future to safeguard its physical assets.

The success of the pipeline business depends, in part, on factors beyond the Company’s control.

Third parties own most of the natural gas transported and stored through the pipeline systems operated by the Company.  As a result, the volume of natural gas transported and stored depends on the actions of those third parties and is beyond the Company’s control.  Further, other factors beyond the Company’s and those third parties’ control may unfavorably impact the Company’s ability to maintain or increase current transmission and storage rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity.  High utilization of contracted capacity by firm customers reduces capacity available for interruptible transportation and parking services.

The expansion of the Company’s pipeline systems by constructing new facilities subjects the Company to construction and other risks that may adversely affect the financial results of the pipeline businesses.

The Company may expand the capacity of its existing pipeline, storage and LNG facilities by constructing additional facilities.  Construction of these facilities is subject to various regulatory, development and operational risks, including:

• the Company’s ability to obtain necessary approvals and permits from FERC and other regulatory agencies on a timely basis and on terms that are acceptable to it;

• the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when the Company may be unable to access capital markets;

• the availability of skilled labor, equipment, and materials to complete expansion projects;

• adverse weather conditions;

• potential changes in federal, state and local statutes, regulations, and orders, including environmental requirements that delay or prevent a project from proceeding or increase the anticipated cost of the project;

• impediments on the Company’s ability to acquire rights-of-way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to it;

• the Company’s ability to construct projects within anticipated costs, including the risk that the Company may incur cost overruns, resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond its control, that the Company may not be able to recover from its customers;

• the lack of future growth in natural gas supply and/or demand; and

• the lack of transportation, storage and throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs.  There is also the risk that a downturn in the economy and its potential negative impact on natural gas demand may result in either slower development in the Company’s expansion projects or adjustments in the contractual commitments supporting such projects.  As a result, new facilities could be delayed or may not achieve the Company’s expected investment return, which may adversely affect the Company’s business, financial condition, results of operations and cash flows.

The inability to continue to access lands owned by third parties could adversely affect the Company’s ability to operate and/or expand its pipeline and gathering and processing businesses.

The ability the Company to operate in certain geographic areas will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion

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projects.  Even though the Company generally has the right of eminent domain, the Company cannot assure that it will be able to acquire all of the necessary new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current rights-of-way or that all of the rights-of-way will be obtainable in a timely fashion. The Company’s financial position could be adversely affected if the costs of new or extended rights-of-way materially increase or the Company is unable to obtain or extend the rights-of-way timely.

Federal, state and local jurisdictions may challenge the Company’s tax return positions.

The positions taken by the Company and Southern Union in their tax return filings require significant judgment, use of estimates, and the interpretation and application of complex tax laws.  Significant judgment is also required in assessing the timing and amounts of deductible and taxable items.  Despite management’s belief that the Company’s tax return positions are fully supportable, certain positions may be challenged successfully by federal, state and local jurisdictions.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business that may increase its costs of operations, expose it to environmental liabilities and require it to make material unbudgeted expenditures.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business (including air emissions), which are complex, change from time to time and have tended to become increasingly strict. These laws and regulations have necessitated, and in the future may necessitate, increased capital expenditures and operating costs. In addition, certain environmental laws may result in liability without regard to fault concerning contamination at a broad range of properties, including currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of, waste.

The Company is currently monitoring or remediating contamination at several of its facilities and at waste disposal sites pursuant to environmental laws and regulations and indemnification agreements.  The Company cannot predict with certainty the sites for which it may be responsible, the amount of resulting cleanup obligations that may be imposed on it or the amount and timing of future expenditures related to environmental remediation because of the difficulty of estimating cleanup costs and the uncertainty of payment by other PRPs.

Costs and obligations also can arise from claims for toxic torts and natural resource damages or from releases of hazardous materials on other properties as a result of ongoing operations or disposal of waste. Compliance with amended, new or more stringently enforced existing environmental requirements, or the future discovery of contamination, may require material unbudgeted expenditures. These costs or expenditures could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows, particularly if such costs or expenditures are not fully recoverable from insurance or through the rates charged to customers or if they exceed any amounts that have been reserved.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2012, our consolidated balance sheet reflected $1.79 billion of goodwill. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners' capital and balance sheet leverage as measured by debt to total capitalization.

The use of derivative financial instruments could result in material financial losses by us.

From time to time, we have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure

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to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, even though monitored by management, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

The adoption of the Dodd-Frank Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business, resulting in our operations becoming more volatile and our cash flows less predictable.

Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), a comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation was signed into law by President Obama on July 21, 2010 and requires the U.S. Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules andregulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC and the SEC as a result of their activities in the derivatives markets or otherwise become specifically qualified to enter into derivatives contracts. We will be required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.

Reporting and recordkeeping requirements also could significantly increase operating costs and expose us to penalties for non-compliance. Certain CFTC recordkeeping requirements became effective on October 14, 2010, and additional recordkeeping requirements will be phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements will be phased in through April 2013. These additional recordkeeping and reporting requirements may require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices and our ability to hedge.

The CFTC has also issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC's position limits rules were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. The CFTC has appealed that ruling and it is uncertain at this time whether, when, and to what extent the CFTC's position limits rules will become effective.

The new regulations may also require us to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation also requires that certain derivative instruments be centrally cleared and executed through an exchange or other approved trading platform. Mandatory exchange trading and clearing requirements could result in increased costs in the form of additional margin requirements imposed by clearing organizations. On December 13, 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although there may be an exception to the mandatory exchange trading and clearing requirement that applies to our trading activities, we must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on this exception. In addition, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In

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addition, the CFTC's rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

The Company’s business could be affected adversely by union disputes and strikes or work stoppages by its unionized employees.

As of January 31, 2013, approximately 218 of the Company’s 1,065 employees were represented by collective bargaining units under collective bargaining agreements.  Any future work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on the Company’s business, financial position, results of operations or cash flows.

The Company is subject to risks associated with climate change.

It has been advanced that emissions of “greenhouse gases” (GHGs) are linked to climate change. Climate change and the costs that may be associated with its impact and the regulation of GHGs have the potential to affect the Company’s business in many ways, including negatively impacting (i) the costs it incurs in providing its products and services, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its GHG emissions, pay any taxes related to GHG emissions, administer and manage a GHG emissions program, pay higher insurance premiums or accept greater risk of loss in areas affected by adverse weather and coastal regions in the event of rising sea levels, (ii) the demand for and consumption of its products and services (due to change in both costs and weather patterns), and (iii) the economic health of the regions in which it operates, all of which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

Recently proposed rules regulating air emissions from natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA issued final rules that would establish new air emission controls for natural gas production and processing operations. Specifically, the EPA's proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with natural gas production and processing activities. The EPA's proposal would require the reduction of VOC emissions from natural gas production facilities by mandating the use of "green completions" for hydraulic fracturing by January 2015, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. These rules will require us to modify certain of our operations, including the possible installation of new equipment. Compliance with such rules will be required within three years of their effective date, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that we transport, store or otherwise handle.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA has recently adopted rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and another which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. In November 2011, the EPA also adopted rules requiring companies with facilities that emit over 25,000 metric tons or more of carbon dioxide to report their greenhouse gas emissions to the EPA by September 30, 2012, a requirement with which we timely complied.

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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase may be reduced over time in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, natural gas, NGLs, crude oil and refined products. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our fuels is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

The Company is subject to risks resulting from the moratorium in 2010 on and the resulting increased costs of offshore deepwater drilling.

The United States Department of Interior (DOI) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the blowout and explosion on April 20, 2010 at the British Petroleum Plc deepwater well in the Gulf of Mexico.  The offshore drilling moratorium was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies.  The moratorium was lifted in October 2010. Additionally, the United States Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the United States Mineral Management Service) has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection.   Certain enhanced regulatory mandates have been enacted with additional regulatory mandates expected.  The new regulatory requirements will increase the cost of offshore drilling and production operations.  The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company.  Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States.   Business decisions to not drill in the areas serviced by the Company resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect  the Company’s business, financial condition, results of operations and cash flows.

The costs of providing postretirement health care benefits and related funding requirements are subject to changes in other postretirement fund values and fluctuating actuarial assumptions and may have a material adverse effect on the Company’s financial results.  In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for Company employees.

The Company provides postretirement healthcare benefits to certain of its employees.  The costs of providing postretirement health care benefits and related funding requirements are subject to changes in postretirement fund values and fluctuating actuarial assumptions that may have a material adverse effect on the Company’s future financial results.  In addition, the passage of the Health Care Reform Act of 2010 could significantly increase the cost of health care benefits for its employees.  While certain of the costs incurred in providing such postretirement healthcare benefits are recovered through the rates charged by the Company’s regulated businesses, the Company may not recover all of its costs and those rates are generally not immediately responsive to current market conditions or funding requirements.  Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

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The Company is subject to risks related to cybersecurity.

The Company is subject to cybersecurity risks and may incur increasing costs in connection with its efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks.

Substantial aspects of the Company’s business depend on the secure operation of its computer systems and websites. Security breaches could expose the Company to a risk of loss, misuse or interruption of sensitive and critical information and functions, including its own proprietary information and that of its customers, suppliers and employees and functions that affect the operation of the business. Such losses could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions, and liability. While the Company devotes substantial resources to maintaining adequate levels of cybersecurity, there can be no assurance that it will be able to prevent all of the rapidly evolving types of cyber attacks. Actual or anticipated attacks and risks may cause the Company to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

If the Company’s security measures are circumvented, proprietary information may be misappropriated, its operations may be disrupted, and its computers or those of its customers or other third parties may be damaged. Compromises of the Company’s security may result in an interruption of operations, violation of applicable privacy and other laws, significant legal and financial exposure, damage to its reputation, and a loss of confidence in its security measures.

The Company’s business is highly regulated.

The Company’s transportation and storage business is subject to regulation by federal, state and local regulatory authorities.  FERC, the U.S. Department of Transportation and various state and local regulatory agencies regulate the interstate pipeline business.  In particular, FERC has authority to regulate rates charged by the Company for the transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets.  In addition, the U.S. Coast Guard has oversight over certain issues including the importation of LNG.

The Company’s rates and operations are subject to extensive regulation by federal regulators as well as the actions of Congress and state legislatures and, in some respects, state regulators.  The Company cannot predict or control what effect future actions of regulatory agencies may have on its business or its access to the capital markets.  Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past several decades and there is no assurance that further substantial changes will not occur or that existing policies and rules will not be applied in a new or different manner.  Should new and more stringent regulatory requirements be imposed, the Company’s business could be unfavorably impacted and the Company could be subject to additional costs that could adversely affect its financial condition or results of operations if these costs are not ultimately recovered through rates.

The Company’s transportation and storage business is also influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, outside contractor services costs, asset retirement obligations for certain assets and other operating costs.  The profitability of regulated operations depends on the business’ ability to collect such increased costs as a part of the rates charged to its customers.  To the extent that such operating costs increase in an amount greater than that for which revenue is received, or for which rate recovery is allowed, this differential could impact operating results.  The lag between an increase in costs and the ability of the Company to file to obtain rate relief from FERC to recover those increased costs can have a direct negative impact on operating results.  As with any request for an increase in rates in a regulatory filing, once granted, the rate increase may not be adequate.  In addition, FERC may prevent the business from passing along certain costs in the form of higher rates. Competition may prevent the recovery of increased costs even if allowed in rates.

FERC may also exercise its Section 5 authority to initiate proceedings to review rates that it believes may not be just and reasonable.  FERC has recently exercised this authority with respect to several other pipeline companies, as it had in 2007 with respect to Southwest Gas.  If FERC were to initiate a Section 5 proceeding against the Company and find that the Company’s rates at that time were not just and reasonable due to a lower rate base, reduced or disallowed operating costs, or other factors, the applicable maximum rates the Company is allowed to charge customers could be reduced and the reduction could potentially have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.  In 2010, in response to an intervention and protest filed by BG LNG Services (BGLS) regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC’s resources on a Section 5 proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG’s revenues were in excess of its associated cost of service.  However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002, a Section 5 proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than

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revenues.  For additional related information, see Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations – Other Matters – Trunkline LNG Cost and Revenue Study.

A rate reduction is also a possible outcome with any Section 4 rate case proceeding for the regulated entities of the Company, including any rate case proceeding required to be filed as a result of a prior rate case settlement.  A regulated entity’s rate base, upon which a rate of return is allowed in the derivation of maximum rates, is primarily determined by a combination of accumulated capital investments, accumulated regulatory basis depreciation, and accumulated deferred income taxes.  Such rate base can decline due to capital investments being less than depreciation over a period of time, or due to accelerated tax depreciation in excess of regulatory basis depreciation.

The pipeline business of the Company is subject to competition.

The interstate pipeline and storage business of the Company competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas.  The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service.  Natural gas competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils.  The primary competitive factor is price.  Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by the Company.

Substantial risks are involved in operating a natural gas pipeline system.

Numerous operational risks are associated with the operation of a complex pipeline system.  These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency, the collision of equipment with pipeline facilities (such as may occur if a third party were to perform excavation or construction work near the facilities) and other catastrophic events beyond the Company’s control.  In particular, the Company’s pipeline system, especially those portions that are located offshore, may be subject to adverse weather conditions, including hurricanes, earthquakes, tornadoes, extreme temperatures and other natural phenomena, making it more difficult for the Company to realize the historic rates of return associated with these assets and operations.  A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage.  Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.

Fluctuations in energy commodity prices could adversely affect the business of the Company.

If natural gas prices in the supply basins connected to the pipeline systems of the Company are higher than prices in other natural gas producing regions able to serve the Company’s customers, the volume of natural gas transported by the Company may be negatively impacted.  Natural gas prices can also affect customer demand for the various services provided by the Company.

The pipeline business of the Company is dependent on a small number of customers for a significant percentage of its sales.

The Company’s top two customers accounted for 43% of its 2012 revenue.  The loss of any one or more of these customers could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.

The success of the Company depends on the continued development of additional natural gas reserves in the vicinity of its facilities and its ability to access additional reserves to offset the natural decline from existing sources connected to its system.

The amount of revenue generated by the Company ultimately depends upon its access to reserves of available natural gas.  As the reserves available through the supply basins connected to the Company’s system naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. If production from these natural gas reserves is substantially reduced and not replaced with other sources of natural gas, such as new wells or interconnections with other pipelines, and certain of the Company’s assets are consequently not utilized, the Company may have to accelerate the recognition and settlement of asset retirement obligations.  Investments by third parties in the development of new natural gas reserves or other sources of natural gas in proximity to the Company’s facilities depend on many factors beyond the Company’s control.  Revenue reductions or the acceleration of asset retirement obligations resulting from the decline of natural gas reserves and the lack of new sources of natural gas may have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

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The pipeline revenues of the Company are generated under contracts that must be renegotiated periodically.

The pipeline revenues of the Company are generated under natural gas transportation contracts that expire periodically and must be replaced.  Although the Company will actively pursue the renegotiation, extension and/or replacement of all of its contracts, it cannot assure that it will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.  If the Company is unable to renew, extend or replace these contracts, or if the Company renews them on less favorable terms, it may suffer a material reduction in revenues and earnings.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This reportcontains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.  Forward-looking statements are based on management’s beliefs and assumptions.  These forward-looking statements, which address the Company’s expected business and financial performance, among other matters, are identified by terms and phrases such as:  anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast and similar expressions.  Forward-looking statements involve risks and uncertainties that may or could cause actual results to be materially different from the results predicted.  Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

• changes in demand for natural gas or NGL and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas or NGL accessible to the Company’s system;

• the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or NGL as well as electricity, oil, coal and other bulk materials and chemicals;

• adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters;

• changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;

• the speed and degree to which additional competition, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues;

• the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries;

• the  ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations;

• unanticipated environmental liabilities;

• the uncertainty of estimates, including accruals and costs of environmental remediation;

• the impact of potential impairment charges;

• the ability to acquire new businesses and assets and to integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;

• the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects;

• the ability to complete expansion projects on time and on budget;

• the ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;

• the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;

• the performance of contractual obligations by customers, service providers and contractors;

• exposure to customer concentrations with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers;

• changes in the ratings of the Company’s debt securities;

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• the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets;

• the impact of unsold pipeline capacity being greater than expected;

• changes in interest rates and other general market and economic conditions, and in the Company’s ability to obtain additional financing on acceptable terms, whether in the capital markets or otherwise;

• declines in the market prices of equity and debt securities and resulting funding requirements for other postretirement benefit plans;

• acts of nature, sabotage, terrorism or other similar acts that cause damage to the  facilities or those of the Company’s  suppliers’ or customers’ facilities;

• market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness;

• the availability/cost of insurance coverage and the ability to collect under existing insurance policies;

• the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant;

• changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;

• the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of costs (including pipeline relocation costs), and permitting for new natural gas production accessible to the Company’s systems;

• market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts;

• actions taken to protect species under the Endangered Species Act and the effect of those actions on the Company’s operations;

• the impact of union disputes, employee strikes or work stoppages and other labor-related disruptions; and

• other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Company’s forward-looking statements.  Other factors could also have material adverse effects on the Company’s future results.  In light of these risks, uncertainties and assumptions, the events described in forward-looking statements might not occur or might occur to a different extent or at a different time than the Company has described.  The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See “Item 1. Business” for information concerning the general location and characteristics of the important physical properties and assets of the Company.

ITEM 3. LEGAL PROCEEDINGS

The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing.  The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in “Item 1. Business – Regulation”. Several of these companies have been named parties to various actions involving environmental issues.  Based on the Company’s current knowledge and subject to future legal and factual developments, the Company’s management believes that it is unlikely that these actions, individually or in the aggregate, will have a material adverse effect on its consolidated financial position, results of operations or cash flows.  For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other legal matters, reference is made to Note 4 and Note 15 to our consolidated financial statements. Also see “Item 1A. Risk Factors”.

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Southern Union Panhandle, LLC, an indirect wholly-owned subsidiary of Southern Union, serves as the general partner of PEPL and owns a 1% general partnership interest in PEPL.  PEPL Holdings, LLC, an indirect wholly-owned subsidiary of Southern Union, owns a 99% limited partnership interest in PEPL. See Note 1 to our consolidated financial statements.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in millions)

Introduction

The information in Item 7 has been prepared pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. Accordingly, this Item 7 includes only management’s narrative analysis of the results of operations and certain supplemental information.

Overview

The Company’s business purpose is to provide interstate transportation and storage of natural gas in a safe, efficient and dependable manner.  The Company operates approximately 10,000 miles of interstate pipelines that transport up to 6.4 Bcf/d of natural gas.  Demand for natural gas transmission services on the Company’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.  For additional information related to the Company’s line of business, locations of operations and services provided, see “Item 1. Business”.

The Company’s business is conducted through both short- and long-term contracts with customers.  Shorter-term contracts, both firm and interruptible, tend to have a greater impact on the volatility of revenues.  Short-term and long-term contracts are affected by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices and basis differentials.  Since the majority of the Company’s revenues are related to firm capacity reservation charges, which customers pay whether they utilize their contracted capacity or not, volumes transported do not have as significant an impact on revenues over the short-term.  However, longer-term demand for capacity may be affected by changes in the customers’ actual and anticipated utilization of their contracted capacity and other factors.  For additional information concerning the Company’s related risk factors and the weighted average remaining lives of firm transportation and storage contracts, see “Item 1A. Risk Factors” and “Item 1. Business”, respectively.

The Company’s regulated transportation and storage businesses can file (or be required to file) for changes in their rates, which are subject to approval by FERC.  Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition.  For information related to the status of current rate filings, see “Item 1. Business – Regulation”.

Results of Operations

The Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  The Company allocated the purchase price paid by ETE to its assets, liabilities and partners’ capital as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.

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The most significant impacts of the new basis of accounting during the successor periods were (i) higher depreciation expense due to the step-up of depreciable assets and assignment of purchase price to certain amortizable intangible assets and (ii) lower interest expense (though not cash payments) for the remaining life of the related long-term debt due to its revaluation and related debt premium amortization. Depreciation and amortization expense recognized in the successor periods subsequent to March 25, 2012 increased by approximately $8 million per quarter as a direct result of the application of the new basis of accounting. Interest expense recognized in the successor periods subsequent to March 25, 2012 decreased by approximately $8 million per quarter as a direct result of the application of the new basis of accounting.

The results of operations for successor and predecessor periods included herein reflect certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the results below. For information regarding expenses related to the merger, see Note 3 to our consolidated financial statements included in this Annual Report on Form 10-K. The Holdco Transaction did not result in a new basis of accounting for Southern Union or Panhandle.

The following table illustrates the results of operations of the Company for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
OPERATING REVENUES:
Transportation and storage of natural gas	$	417		$	140		$	574
LNG terminalling	166			51			220
Other	9			3			10
Total operating revenues (1)	592			194			804
OPERATING EXPENSES:
Operating, maintenance and general	173			53			221
Operating, maintenance and general - affiliate	61			14			58
Depreciation and amortization	125			30			128
Taxes, other than on income	28			9			35
Total operating expenses	387			106			442
OPERATING INCOME	205			88			362
OTHER INCOME (EXPENSE):
Interest expense	(43		)	(25		)	(108		)
Interest income - affiliates	2			2			9
Total other expenses, net	(41		)	(23		)	(99		)
INCOME BEFORE INCOME TAX EXPENSE	164			65			263
Income tax expense	76			25			95
NET INCOME	$	88		$	40		$	168
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	430			152			564
Trunkline	533			177			743
Sea Robin	91			20			113

⁽¹⁾  Reservation revenues comprised 87% of total operating revenues in the successor period. Reservation revenues comprised 88% and 89% of total operating revenues in the 2012 and 2011 predecessor periods, respectively.

⁽²⁾  Includes transportation deliveries made throughout the Company’s pipeline network.

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The following is a discussion of the significant items and variances impacting the Company’s net income during the periods presented above:

Operating Revenues. Operating revenues were lower in the successor period primarily due to the impact of customer contract buyouts of $14 million in 2011.

Operating Expenses. The successor period included merger-related expenses of approximately $48 million, offset by a curtailment gain on our OPEB plans of $11 million. The year ended December 31, 2011 reflected legal expenses that were lower than the legal expenses recorded during the predecessor and successor periods in 2012; this was due to settlement in 2011 of certain litigation with several contractors related to the Company’s East End project. The successor period also reflected higher depreciation compared to the predecessor period, due to the step-up in depreciable assets in connection with the merger, offset by lower corporate allocations due to merger-related synergies.

Interest Expense. Interest expense was lower in the successor period primarily due to amortization of the long-term debt fair value adjustment recorded in connection with the merger as well as the termination of interest rate swaps.

Income Taxes. Income taxes increased relative to income before income tax expense during the successor period primarily due to the impact of non-deductible merger-related expenses.

For information regarding expenses related to the merger, see Note 3 to our consolidated financial statements included in this Annual Report on Form 10-K.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of the Company has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the ETE Merger for the years ended December 31, 2012 and 2011, giving effect to the ETE Merger as if it had occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the ETE Merger had been consummated on January 1, 2011.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Pro Forma Adjustments				Pro Forma Year Ended December 31, 2012
OPERATING REVENUES	$	592		$	194		$	—			$	786
OPERATING EXPENSES:
Operating, maintenance and general	173			53			—				226
Operating, maintenance and general - affiliate	61			14			(37		)	(a)	38
Depreciation and amortization	125			30			8			(b)	163
Taxes, other than on income	28			9							37
Total operating expenses	387			106			(29		)		464
OPERATING INCOME	205			88			29				322
OTHER INCOME (EXPENSE):
Interest expense	(43		)	(25		)	8			(c)	(60		)
Interest income - affiliates	2			2			—				4
Total other expenses, net	(41		)	(23		)	8				(56		)
INCOME BEFORE INCOME TAX EXPENSE	164			65			37				266
Income tax expense	76			25			6			(d)	107
NET INCOME	88			40			31				159

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	Predecessor
	Year Ended December 31, 2011			Pro Forma Adjustments				Pro forma Year Ended December 31, 2011
OPERATING REVENUES	$	804		$	—			$	804
OPERATING EXPENSES:
Operating, maintenance and general	221			—				221
Operating, maintenance and general - affiliate	58			(2		)	(a)	56
Depreciation and amortization	128			36			(b)	164
Taxes, other than on income	35			—				35
Total operating expenses	442			34				476
OPERATING INCOME	362			(34		)		328
OTHER INCOME (EXPENSE):
Interest expense	(108		)	32			(c)	(76		)
Interest income - affiliates	9			—				9
Total other expenses, net	(99		)	32				(67		)
INCOME BEFORE INCOME TAX EXPENSE	263			(2		)		261
Income tax expense	95			(1		)		94
NET INCOME	$	168		$	(1	)		$	167

(a) To eliminate the merger-related costs incurred by the Company in connection with the ETE Merger, including change in control and severance costs. These costs are eliminated from the Company’s pro forma income statement because such costs would not have a continuing impact on the Company’s results of operations.

(b) To record incremental depreciation on the excess purchase price allocated to property, plant and equipment based on a weighted average useful life of 24 years.

(c) To adjust amortization included in interest expense to (i) reverse historical amortization of financing costs and fair value adjustments related to debt and (ii) record pro forma amortization related to the pro forma adjustment of the Company’s debt to fair value.

(d) To reflect income tax impacts from the pro forma adjustments to pre-tax income, including the elimination of the dividend received deduction recorded in the historical income tax provision for the predecessor periods in connection with the Company’s investment in Citrus.

Analysis of Supplemental Pro Forma Financial Information

Following is a discussion of the significant items impacting the pro forma results for the year ended December 31, 2012 compared to pro forma results for the year ended December 31, 2011.

• Pro forma operating revenues were lower in 2012 compared to 2011 primarily due to the impact of customer contract buyouts of $14 million in 2011.

• Pro forma operating, maintenance and general-affiliate were lower in 2012 compared to 2011 primarily due to decreased corporate allocations.

• Pro forma interest expense was lower in 2012 compared to 2011 primarily due to lower pro forma interest expense resulting from the retirement of a $465 million term loan.

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Other Matters

Regulation.  See Note 4 to our consolidated financial statements.

Environmental Matters.  The Company is subject to federal, state and local laws and regulations relating to the protection of the environment.  These evolving laws and regulations may require expenditures over a long period of time to control environmental impacts.  The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures.  These procedures are designed to achieve compliance with such laws and regulations.  For additional information concerning the impact of environmental regulation on the Company, see Note 15 to our consolidated financial statements.

Contractual Obligations.  The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2012:

	Contractual Obligations
	Total		2013		2014		2015		2016		2017		2018 and thereafter
Operating leases (1)	$	83	$	15	$	14	$	13	$	6	$	6	$	29
Total long-term debt (2) (3)	1,621		250		—		455		—		300		616
Interest payments on debt (4)	432		81		72		65		63		63		88
Firm capacity payments (5)	150		28		33		27		22		21		19
OPEB funding (6)	48		8		8		8		8		8		8
Total (7)	$	2,334	$	382	$	127	$	568	$	99	$	398	$	760

⁽¹⁾  Lease of various assets utilized for operations.

⁽²⁾  The Company is party to debt agreements containing certain covenants that, if not satisfied, would give rise to an event of default that would cause such debt to become immediately due and payable.  Such covenants require the Company to maintain a fixed charge coverage ratio, a leverage ratio and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense.  At December 31, 2012, the Company was in compliance with all of its covenants.  See Note 8 to our consolidated financial statements.

⁽³⁾  The long-term debt cash obligations exclude $136 million of unamortized fair value adjustments as of December 31, 2012.

⁽⁴⁾  Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2012.

⁽⁵⁾  Charges for third party storage capacity.

⁽⁶⁾  Panhandle is committed to the funding levels of $8 million per year until modified by future rate proceedings, the timing of which is uncertain.

⁽⁷⁾  Excludes non-current deferred tax liability of $853 million due to uncertainty of the timing of future cash flows for such liabilities.

Contingencies

SeeNote 15 to our consolidated financial statements.

Inflation

The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, and will continue to require higher capital replacement and construction costs.  The Company continually reviews the adequacy of its rates in relation to such increasing cost of providing services, the inherent regulatory lag in adjusting its tariff rates and the rates it is actually able to charge in its markets.

Regulatory

SeeNote 4 to our consolidated financial statements.

Trunkline LNG Cost and Revenue Study. On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders.  Such filing, which was as of March 31, 2009, reflected an annualized cost of service level for these expansions of $55 million, less than the associated actual revenues during the same period of $69 million.  BGLS filed a motion to intervene and protest on July 14, 2009.  By order dated July 26,

23

2010, FERC determined that since (i) Trunkline LNG has fixed negotiated rates with BGLS through 2015, which would be unaffected by any rate change that might be determined through hearing at this time, and (ii) current costs and revenues are not necessarily representative of Trunkline LNG’s costs and revenues at the termination of the negotiated rate period in 2015, there was no reason to expend FERC’s and the parties’ resources on a Natural Gas Act Section 5 proceeding at this time.  The order is final and not subject to rehearing.

LNG Export License.On July 22, 2011, the United States Department of Energy, Office of Fossil Energy issued an order authorizing Lake Charles Exports, LLC, an entity owned by subsidiaries of the Company and BG Group plc, to export domestically produced LNG by vessel from Trunkline LNG’s Lake Charles LNG terminal.  The authorization, for a 25-year term beginning on the earlier of the date of first export or 10 years from the issuance of the order, permits export of up to approximately 2 Bcf/d to countries that have or will enter into a free trade agreement (FTA) with the United States that requires national treatment for trade in natural gas.  Lake Charles Exports, LLC is permitted to use the authorization to export LNG on its own behalf or as an agent for BGLS. A proceeding for approval to export to non-FTA countries is ongoing. Another affiliate of the Company, Trunkline LNG Export, LLC. has also filed with the United States Department of Energy, Office of Fossil Energy for LNG export authorization to export up to approximately 2 Bcf/d to FTA and non-FTA countries. This authorization is non-additive to the LCE authorization request, but is requested by Trunkline LNG Export, LLC to provide greater flexibility and optionality in their potential marketing of LNG.  The companies are developing plans to install liquefaction facilities at the Lake Charles terminal to export LNG. Modifications to the Lake Charles terminal would be subject to approval by the FERC.  The Company and BG Group plc have not finalized the economic terms of their arrangement, but the Company expects that any such arrangement will take into account, among other things, the December 31, 2015 termination of certain contracted rates at the existing Trunkline LNG terminal, which otherwise revert to tariff rates in 2016, and the term of BGLS contracts related to the Trunkline LNG terminal, which otherwise all expire in 2030.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

The Company is subject to the risk of loss associated with movements in market interest rates.  The Company manages this risk through the use of fixed-rate debt, floating-rate debt and interest rate swaps.  Fixed-rate swaps are used to reduce the risk of increased interest costs during periods of rising interest rates.  Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. The Company considers the impact of interest rate swaps to manage the risk of interest expense. At December 31, 2012, the interest rate on 72% of the Company’s long-term debt was fixed with no outstanding interest rate swaps.

At December 31, 2012, a 100 basis point change in the annual interest rate on all outstanding floating-rate debt would correspondingly change the Company’s interest payments by approximately less than $1 million for each month during which such change continued.  If interest rates changed significantly, the Company may take actions to manage its exposure to the change.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2012 is not material to the Company.

See Note 11 and Note 8 to our consolidated financial statements.

Commodity Price Risk

The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines.  Specifically, the pipelines receive natural gas from customers for use in generating compression to move the customers’ natural gas.  Additionally the pipelines may have to settle system imbalances when customers’ actual receipts and deliveries do not match.  When the amount of natural gas utilized in operations by the pipelines differs from the amount provided by customers, the pipelines may use natural gas from inventory or may have to buy or sell natural gas to cover these or other operational needs, resulting in commodity price risk exposure to the Company.  In addition, there is other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company.  At December 31, 2012, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required here is included in the report as set forth in the Index to Consolidated Financial Statements on page F-1.

24

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2012.

Management’s Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Exchange Act Rule 13a-15(f) as a process designed by, or under the supervision of, the Company’s principal executive officer and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP, and includes those policies and procedures that:

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; and

• Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Exchange Act Rules 13a-15(c) and 15d-15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Company to conduct an annual evaluation of the Company’s internal control over financial reporting and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting is effective.  Pursuant to the rules of the SEC, Management’s attestation report regarding internal control over financial reporting was not subject to attestation by the Company’s independent registered public accountant.  As such, this Form 10-K does not contain an attestation report of the Company’s independent registered public accountant regarding internal control over financial reporting.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s evaluation of the effectiveness of the Company’s internal control over financial reporting was based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under that framework and applicable SEC rules, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2012.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 10, Directors, Executive Officers and Corporate Governance, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Item 11, Executive Compensation, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Item 13, Certain Relationships and Related Transactions, and Director Independence, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The Audit Committee of the Board of Directors of ETE appointed Grant Thornton LLP as our principal accountant to conduct the audit of our financial statements for the year ended December 31, 2012 on April 16, 2012.  PricewaterhouseCoopers LLC served as our independent registered public accountant for the year ended December 31, 2011.  The approval of Grant Thornton LLP occurred subsequent to the ETE merger but prior to the Holdco Transaction.

The following table sets forth fees billed by Grant Thornton LLP and PricewaterhouseCoopers LLC for the audits of our annual financial statements and other services rendered:

	Grant Thornton LLP		Pricewaterhouse-Coopers LLC
	2012		2011
Audit fees (1)	$	456,250	$	924,000
Total Fees	$	456,250	$	924,000

⁽¹⁾  Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.

Subsequent to the Holdco Transaction, the ETP Audit Committee is responsible for the oversight of our accounting, reporting and financial practices, pursuant to the charter of the ETP Audit Committee. The ETP Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The ETP Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The ETP Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the ETP Audit Committee.

26

The ETP Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

• the auditors’ internal quality-control procedures;

• any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

• the independence of the external auditors;

• the aggregate fees billed by our external auditors for each of the previous two years; and

• the rotation of the lead partner.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this Report:

(1) Financial Statements - see Index to Financial Statements appearing on page F-1.

(2) Financial Statement Schedules - None.

(3) Exhibits - see Index to Exhibits set forth on page E-1.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Panhandle Eastern Pipe Line Company, LP has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PANHANDLE EASTERN PIPE LINE COMPANY, LP
Date:  March 1, 2013	By: /s/   Martin Salinas, Jr. Martin Salinas, Jr. Chief Financial Officer (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Panhandle Pipe Line Company, LP, in the capacities and on the dates indicated:

	Signature	Title	Date
(i)	Principal executive officer: /s/ Kelcy L. Warren      Kelcy L. Warren	Chief Executive Officer	March 1, 2013
(ii)	Principal financial officer: /s/ Martin Salinas, Jr.      Martin Salinas, Jr.	Chief Financial Officer	March 1, 2013
(iii)	A majority of the Board of Directors of Southern Union Company, Sole Member of Southern Union Panhandle, LLC, General Partner of Panhandle Eastern Pipe Line Company, L.P
	Signature	Title	Date
	/s/ Marshall S. McCrea, III      Marshall S. McCrea, III	President, Chief Operating Officer and Director, Southern Union Company	March 1, 2013
	/s/ John W. McReynolds      John W. McReynolds	Director, Southern Union Company	March 1, 2013
	/s/ John D. Harkey, Jr.      John D. Harkey, Jr.	Director, Southern Union Company	March 1, 2013
	/s/ Kyle Kutch      Kyle Kutch	Director, Southern Union Company	March 1, 2013

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INDEX TO EXHIBITS

Exhibit No.	Description
3(a)	Certificate of Formation of Panhandle Eastern Pipe Line Company, LP.  (Filed as Exhibit 3.A to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)
3(b)	Limited Partnership Agreement of Panhandle Eastern Pipe Line Company, LP, dated as of June 29, 2004, between Southern Union Company and Southern Union Panhandle LLC.  (Filed as Exhibit 3.B to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)
4(a)	Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(a) to the Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference.)
4(b)	First Supplemental Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company. (Filed as Exhibit 4(b) to the Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference.)
4(c)	Second Supplemental Indenture dated as of March 27, 2000, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(e) to the Form S-4 (File No. 333-39850) filed on June 22, 2000, and incorporated herein by reference.)
4(d)	Third Supplemental Indenture dated as of August 18, 2003, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(d) to the Form 10-Q for the quarter ended September 30, 2003, and incorporated herein by reference.)
4(e)	Fourth Supplemental Indenture dated as of March 12, 2004, between Panhandle and J.P. Morgan Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee.  (Filed as Exhibit 4.E to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)
4(f)	Fifth Supplemental Indenture dated as of October 26, 2007, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on October 29, 2007 and incorporated herein by reference.)
4(g)	Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on June 11, 2008 and incorporated herein by reference.)
10(a)	Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and the Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent, dated as of February 23, 2012.
10(b)	Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between Panhandle and The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on May 28, 2009 and incorporated herein by reference).
10(c)	Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007 (Filed as Exhibit 10.1 to Panhandle’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)
10(d)	Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008 (Filed as Exhibit 10(b) to the Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

E -1

10(e)	Amended and Restated Promissory Note made by CrossCountry Citrus, LLC, as borrower, in favor of Trunkline LNG Holdings LLC, as holder, dated as of June 13, 2008 (Filed as Exhibit 10(d) to the Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
12.1	Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definitions Document
101.LAB	XBRL Taxonomy Label Linkbase Document
101.PRE	XBRL Taxonomy Presentation Linkbase Document

E -2

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:
Report of Independent Registered Public Accounting Firm	F -2
Report of Independent Registered Public Accounting Firm	F -3
Consolidated Balance Sheets	F -4
Consolidated Statements of Operations	F -7
Consolidated Statements of Comprehensive Income	F -8
Consolidated Statement of Partners' Capital	F -9
Consolidated Statements of Cash Flows	F -10
Notes to Consolidated Financial Statements	F -11

F -1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southern Union Company and Board of Managers of

Panhandle Eastern Pipe Line Company, LP

We have audited the accompanying consolidated balance sheet of Panhandle Eastern Pipe Line Company, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2012, and the related consolidated statements of operations, comprehensive income, partners' capital, and cash flows for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Panhandle Eastern Pipe Line Company, LP and subsidiariesas of December 31, 2012, and the results of their operations and their cash flows for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Houston, Texas

March 1, 2013

F -2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Southern Union Company and Board of Managers of

Panhandle Eastern Pipe Line Company, LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Panhandle Eastern Pipe Line Company, LP and its subsidiaries at December 31, 2011, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2012

F -3

FINANCIAL STATEMENTS

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 – ETE Merger and Holdco Transaction.

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.”

F -4

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	Successor			Predecessor
	December 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	—
Accounts receivable net of allowances of nil and $1, respectively	74			76
Accounts receivable from related companies	14			6
Natural gas imbalances receivable	10			53
Note receivable from related party	—			342
System natural gas and operating supplies	144			115
Other	20			21
Total current assets	262			613
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	4,076			4,046
Construction work in progress	45			42
	4,121			4,088
Accumulated depreciation and amortization	(57		)	(733		)
Net property, plant and equipment	4,064			3,355
GOODWILL	1,785			—
NOTE RECEIVABLE FROM RELATED PARTY	831			688
OTHER NON-CURRENT ASSETS	108			19
Total assets	$	7,050		$	4,675

The accompanying notes are an integral part of these consolidated financial statements.

F -5

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	Successor			Predecessor
	December 31, 2012			December 31, 2011
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Current portion of long-term debt	$	258		$	342
Accounts payable	12			13
Accounts payable to related companies	27			52
Natural gas imbalances — payable	130			145
Accrued taxes	13			18
Accrued interest	13			14
Capital accruals	13			11
Other	56			56
Total current liabilities	522			651
LONG-TERM DEBT, less current portion	1,499			1,624
DEFERRED INCOME TAXES	853			538
OTHER NON-CURRENT LIABILITIES	135			70
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Partners’ capital	4,050			1,809
Accumulated other comprehensive loss	(9		)	(16		)
Tax sharing note receivable — related party	—			(1		)
Total partners’ capital	4,041			1,792
Total liabilities and partners’ capital	$	7,050		$	4,675

The accompanying notes are an integral part of these consolidated financial statements.

F -6

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
OPERATING REVENUES:
Transportation and storage of natural gas	$	417		$	140		$	574		$	561
LNG terminalling	166			51			220			199
Other	9			3			10			9
Total operating revenues	592			194			804			769
OPERATING EXPENSES:
Operating, maintenance and general	173			53			221			216
Operating, maintenance and general - affiliate	61			14			58			55
Depreciation and amortization	125			30			128			123
Taxes, other than on income	28			9			35			36
Total operating expenses	387			106			442			430
OPERATING INCOME	205			88			362			339
OTHER INCOME (EXPENSE):
Interest expense	(43		)	(25		)	(108		)	(103		)
Interest income - affiliates	2			2			9			9
Total other expenses, net	(41		)	(23		)	(99		)	(94		)
INCOME BEFORE INCOME TAX EXPENSE	164			65			263			245
Income tax expense	76			25			95			97
NET INCOME	$	88		$	40		$	168		$	148

The accompanying notes are an integral part of these consolidated financial statements.

F -7

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Net income	$	88		$	40	$	168		$	148
Other comprehensive income (loss), net of tax:
Reclassification of unrealized loss on interest rate hedges into earnings	—			3		13			13
Change in fair value of interest rate hedges	—			—		(1		)	(8		)
Actuarial loss relating to postretirement benefits	(9		)	—		(10		)	(1		)
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—		(1		)	(1		)
	(9		)	3		1			3
Comprehensive income	$	79		$	43	$	169		$	151

The accompanying notes are an integral part of these consolidated financial statements.

F -8

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Dollars in millions)

	Partners’ Capital		Accumulated Other Comprehensive Loss			Tax Sharing Note Receivable-Related Party			Total
Predecessor
Balance, December 31, 2009	$	1,493	$	(20	)	$	(5	)	$	1,468
Tax sharing receivable - Southern Union	—		—			2			2
Net income	148		—			—			148
Other comprehensive income, net of tax	—		3			—			3
Balance, December 31, 2010	1,641		(17		)	(3		)	1,621
Tax sharing receivable - Southern Union	—		—			2			2
Net income	168		—			—			168
Other comprehensive income, net of tax	—		1			—			1
Balance, December 31, 2011	1,809		(16		)	(1		)	1,792
Tax sharing receivable - Southern Union	—		—			—			—
Net income	40		—			—			40
Other comprehensive income, net of tax	—		3			—			3
Balance, March 25, 2012	$	1,849	$	(13	)	$	(1	)	$	1,835
Successor
Balance, March 26, 2012	$	3,962	$	—		$	(1	)	$	3,961
Tax sharing receivable - Southern Union	—		—			1			1
Net income	88		—			—			88
Other comprehensive loss, net of tax	—		(9		)	—			(9		)
Balance, December 31, 2012	$	4,050	$	(9	)	$	—		$	4,041

The accompanying notes are an integral part of these consolidated financial statements.

F -9

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	88		$	40		$	168		$	148
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	125			30			128			123
Deferred income taxes	86			19			76			52
Amortization of costs charged to interest	(24		)	—			—			—
Net gain on curtailment of OPEB benefits	(11		)	—			—			—
Changes in operating assets and liabilities, net of Merger impact	(77		)	23			(28		)	(21		)
Net cash flows provided by operating activities	187			112			344			302
CASH FLOWS FROM INVESTING ACTIVITIES:
Net (increase) decrease in note receivable - related parties	(55		)	255			(207		)	(128		)
Net (decrease) increase in income taxes payable - related parties	(43		)	5			(10		)	21
Additions to property, plant and equipment	(90		)	(28		)	(111		)	(161		)
Plant retirements and other	—			—			—			7
Net cash flows (used in) provided by investing activities	(188		)	232			(328		)	(261		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			455			—			—
Repayment of debt	—			(797		)	(18		)	(41		)
Issuance costs of debt	—			(2		)	—			—
Other	1			—			2			—
Net cash flows provided by (used in) financing activities	1			(344		)	(16		)	(41		)
INCREASE IN CASH AND CASH EQUIVALENTS	—			—			—			—
CASH AND CASH EQUIVALENTS, beginning of period	—			—			—			—
CASH AND CASH EQUIVALENTS, end of period	$	—		$	—		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F -10

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

1. 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 ETE;

• 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;

• Trunkline LNG, a direct wholly-owned subsidiary of LNG Holdings; and

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

The Company’s assets 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.  The Company also owns and operates 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 Southern Union, serves as the general partner of PEPL and owns a 1% general partnership interest in PEPL.  PEPL Holdings, LLC, an indirect wholly-owned subsidiary of Southern Union, owns a 99% limited partnership interest in PEPL.

See Note 3 for information related to Southern Union’s merger with ETE and the completion of the Holdco Transaction.

2. 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. In 1999, the Company discontinued application of regulatory-based accounting policies for its units which had been applying such accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. The accounting required by the regulatory-based authoritative guidance differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, 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.”

F -11

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, 2012, 2011 and 2010 were each less than 1 million, respectively.

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	75	$	17	$	106	$	102
Cash paid for income taxes	32		—		35		22

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 at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current
Natural gas (1)	$	124	$	96
Materials and supplies	20		19
Total current	144		115
Non-Current
Natural gas (1)	—		3
	$	144	$	118

⁽¹⁾  Natural gas volumes held for operations at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 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

F -12

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 13.

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 as of November 30 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.  No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Related Party Transactions. Related party expenses primarily include payments for services provided by Southern Union.  Other income is primarily related to interest income on a note receivable from a related party.  See Note 5 for additional information on related party transactions.

A portion of the Company’s revenues for the transportation of natural gas includes revenues from MGE, a division of Southern Union that is a natural gas utility having a service territory covering Kansas City, Missouri and parts of western Missouri.

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/

F -13

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 utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  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 for the periods presented.

	Years Ended December 31,
	2011		2010
Beginning balance	$	1	$	1
Additions: charged to cost and expenses	—		—
Deductions: write-off of uncollectible accounts	—		—
Other	—		—
Ending balance	$	1	$	1

Amounts related to the allowance for doubtful accounts were not material as of and during the year ended December 31, 2012.

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	31	%	30	%	30	%	29	%
ProLiance	12		13		13		13
Other top 10 customers	20		24		21		23
Remaining customers	37		33		36		35
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 the year in which the change occurs through Accumulated other comprehensive income in Partners’ capital. See Note 9 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

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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 11 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 14.

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 12 and Note 9 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 6 for additional related information.

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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 will enter 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. 

3. ETE MERGER AND HOLDCO TRANSACTION:

Description of Merger

On March 26, 2012, Southern Union, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among Southern Union, ETE and Merger Sub, Merger Sub was merged with and into Southern Union, with Southern Union continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, LLC, an indirect wholly-owned subsidiary of Southern Union (CrossCountry Energy), ETP, Citrus ETP Acquisition, L.L.C. (ETP Merger Sub), Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of Southern Union (PEPL Holdings), and Southern Union consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and Southern Union, on the other hand.

Immediately prior to the Effective Time, Southern Union, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder to, and Southern Union assumed the obligations and rights of ETE thereunder.  Southern Union made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus Corp. (Citrus).  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) Southern Union contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, Southern Union entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant

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to which Southern Union agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to Southern Union) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

Expenses Related to the Merger

Merger-related expenses of $48 million include charges related to employment agreements with certain executives that provide 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.  See Note 9 for more information on the curtailment.

Allocation of Consideration Transferred

The 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 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.

Holdco Transaction

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity in exchange for a 60% equity interest in the new entity, Holdco, and (ii) 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 will control Holdco. This transaction did not result in a new basis of accounting for Southern Union or Panhandle.

4. REGULATORY MATTERS:

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.

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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 is subject to FERC approval. Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission’s requests for additional information on this application.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

5. RELATED PARTY TRANSACTIONS:

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

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Notes receivable from related party — Southern Union and subsidiaries:
Current	$	—	$	342
Non-current	831		688
	$	831	$	1,030
Accounts receivable from related companies (1)	$	14	$	6
Accounts payable to related companies:
Southern Union — income taxes (2)	$	—	$	33
Southern Union — other (3)	26		19
Other (4)	1		—
	$	27	$	52

(1) Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus, MGE and other affiliates. The December 31, 2011 balance also included interest income associated with a note receivable from an affiliate, which was repaid on March 26, 2012.

(2) Accounts payable from related companies reflected above related to income taxes payable to Southern Union per the tax sharing agreement to provide for taxes to be remitted upon the filing of the tax return.

(3) Accounts payable from related companies reflected above primarily related to payroll funding including merger-related expenses, provided by Southern Union.  The December 31, 2011 amount was net of insurance proceeds of $2 million owed by Southern Union to the Company.

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

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The following tables provide a summary of related party transactions for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Transportation and storage of natural gas (1)	$	7	$	1	$	3	$	3
Operation and maintenance and general-affiliate:
Management and royalty fees	5		5		20		19
Corporate services - Southern Union	47		9		32		31
Other expenses (2)	9		—		6		5
Other income, net:
Interest income — Southern Union and subsidiaries	2		2		9		9

⁽¹⁾  Represents transportation and storage revenues with ETC, a subsidiary of ETP (in the successor period) and MGE, a Southern Union division.

⁽²⁾  Represents primarily insurance costs and corporate charges for merger-related employee expenses from ETE 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.

6. 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.

As of December 31, 2012, 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 $1 million and were reflected as non-current assets on our balance sheet.

As of December 31, 2012, the Company had no legally restricted funds for the purpose of settling AROs.

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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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Beginning balance	$	41		$	41	$	57		$	58
Incurred	1			—		1			29
Revisions	3			—		—			(11		)
Settled	(5		)	—		(17		)	(20		)
Accretion expense	2			—		—			1
Ending balance	$	42		$	41	$	41		$	57

In 2010, additional AROs of $29 million were established primarily for the Company’s offshore assets. During 2010, the Company largely completed its assessment and repairs of the property damaged by Hurricane Ike in 2008, which resulted in accelerated abandonments of such property, and determined that the estimated third party abandonment costs for all of its offshore property needed to be increased.  Also in 2010, the Company recorded an $11 million downward revision to its prior ARO liability estimates, primarily for the costs of abandoning certain other specific offshore properties as a result of favorable weather conditions, changes in equipment used, and some changes in scope of the respective projects, which were primarily related to abandonments required as a result of permanent damage from Hurricane Ike.  The ARO liability associated with Hurricane Ike was further reduced by settlements of $20 million.  Such revisions and settlements were primarily associated with AROs of $8 million and $34 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike.   During 2011, the Company recorded settlements of approximately $17 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike.  See Note 15 for additional related information related to 2008 Hurricane Damage.

7. COMPREHENSIVE INCOME:

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

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$	—		$	2	$	9		$	9
Change in fair value of interest rate hedges	—			—		(1		)	(5		)
Actuarial loss relating to postretirement benefits	(6		)	—		(6		)	—
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—		(1		)	(1		)
	$	(6	)	$	2	$	1		$	3

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The table below presents the components in accumulated other comprehensive loss as of the dates indicated:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Other postretirement plan - net actuarial loss and prior service costs, net	$	(9	)	$	(13	)
Interest rate hedges, net	—			(3		)
Total accumulated other comprehensive loss, net of tax	$	(9	)	$	(16	)

8. DEBT OBLIGATIONS:

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

	Successor			Predecessor
	December 31, 2012			December 31, 2011
6.05% Senior Notes due 2013	$	250		$	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 Loans due 2012	—			797
Term Loan due 2015	455			—
Net premiums on long-term debt	—			3
Unamortized fair value adjustments	136			—
Total debt outstanding	1,757			1,966
Current portion of long-term debt	(258		)	(342		)
Total long-term debt	$	1,499		$	1,624

The Company has $250 million principal amount of senior notes which mature within the next twelve months. The Company currently expects to refinance all or a portion of the debt upon maturity or, alternatively, to retire all or a portion of the debt with proceeds from repayment of the note receivable from Southern Union, which funds are available to the Company on a demand basis.

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, 2012 and 2011 was $1.81 billion and $2.13 billion, respectively. As of December 31, 2012 and 2011, the aggregate carrying amount of our consolidated debt obligations was $1.76 billion and $1.97 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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. Under LNG Holding's $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5 times. The annualized interest rate for the LNG Holdings term loan was 1.84% at December 31, 2012.

Other.  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, 2012, the Company is in compliance with these covenants.

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As of December 31, 2012, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2013	$	250
2014	—
2015	455
2016	—
2017	300
Thereafter	616
Total	$	1,621

9. BENEFITS:

Postretirement Benefit Plans

The 2012 postretirement benefits expense reflects 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.  The health care plans provided for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles and coinsurance on the amount the Company paid annually to provide future retiree health care coverage under certain of these plans.

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, 2012			March 25, 2012		December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of period	$	93		$	88	$	69
Service cost	—			1		3
Interest cost	1			1		4
Amendments	16			—		—
Actuarial loss and other	4			3		13
Benefits paid, net	(1		)	—		(1		)
Curtailments	(75		)	—		—
Benefit obligation at end of period	$	38		$	93	$	88
Change in plan assets:
Fair value of plan assets at beginning of period	$	82		$	75	$	68
Return on plan assets and other	3			5		—
Employer contributions	6			2		8
Benefits paid, net	(1		)	—		(1		)
Fair value of plan assets at end of period	$	90		$	82	$	75
Amount (overfunded) underfunded at end of period (1)	$	(52	)	$	11	$	13
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(1	)	$	—	$	23
Prior service cost	16			—		1
	$	15		$	—	$	24

⁽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.

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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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Service cost	$	—		$	1		$	2		$	3
Interest cost	1			1			4			4
Expected return on plan assets	(3		)	(1		)	(3		)	(3		)
Prior service credit amortization	—			(1		)	(2		)	(2		)
Curtailment recognition (1)	(11		)	—			—			—
Net periodic benefit cost	$	(13	)	$	—		$	1		$	2

⁽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 credit for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2013 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.51%, 4.24% and 4.26% in the successor and predecessor periods in 2012 and at December 31, 2011, respectively.

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Discount rate	3.64	%	4.26	%	5.54	%	6.00	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%	5.00	%

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.

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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, 2012		March 25, 2012		December 31, 2011
Health care cost trend rate assumed for next year	8.50	%	8.00	%	8.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.50	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2020		2019		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	$	4	$	(3	)

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:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Cash and cash equivalents	$	2	$	2
Mutual fund (1)	88		73
Total	$	90	$	75

⁽¹⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds.  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.  As of December 31, 2011, the fund was primarily comprised of approximately 19% large-cap U.S. equities, 2% small-cap U.S. equities, 10% international equities, 55% fixed income securities, 8% cash and 6% 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 contribute approximately $8 million to its other postretirement plans in 2013 and approximately $8 million annually thereafter until modified by rate case proceedings.

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Benefit Payments.  The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D Subsidy Receipts		Net
2013	$	3	$	—	$	3
2014	3		—		3
2015	3		—		3
2016	3		—		3
2017	3		—		3
2018 – 2022	12		2		10

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Defined Contribution Plan

The Company sponsors a defined contribution savings plan (Savings Plan) that is available to 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 are 100% vested after five years of continuous service.  Company contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $3 million, $1 million, $5 million and $5 million, respectively.

In addition, the Company makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation with the amount generally varying based on age and years of service.  Company contributions are 100% vested after five years of continuous service.  Company contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $2 million, $1 million, $6 million and $5 million, respectively.

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10.TAXES ON INCOME:

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

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Current expense (benefit):
Federal	$	(8	)	$	5		$	24		$	34
State	(2		)	1			(5		)	11
Total	(10		)	6			19			45
Deferred expense:
Federal	$	72		$	17		$	67		$	51
State	14			2			9			1
Total	86			19			76			52
Total income tax expense	$	76		$	25		$	95		$	97
Effective tax rate	46		%	38		%	36		%	40		%

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Computed statutory income tax expense at 35%	$	57	$	23	$	92	$	86
Changes in income taxes resulting from:
Non-deductible executive compensation	11		—		—		—
State income taxes, net of federal income tax benefit	8		2		3		8
Other	—		—		—		3
Income tax expense	$	76	$	25	$	95	$	97

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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:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Deferred income tax assets:
Other postretirement benefits	$	52		$	13
Derivative financial instruments (interest rates)	13			4
Other	18			20
Total deferred income tax assets	83			37
Deferred income tax liabilities:
Property, plant and equipment	(925		)	(559		)
Other	(2		)	(7		)
Total deferred income tax liabilities	(927		)	(566		)
Net deferred income tax liability	(844		)	(529		)
Less current income tax assets	9			9
Accumulated deferred income taxes	$	(853	)	$	(538	)

As of December 31, 2012, the Company has $1 million ($1 million, net of federal tax) of unrecognized tax benefits, none of which would impact the Company’s EITR 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.

11. 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.  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, 2012, 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

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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 asset derivative instruments at December 31, 2012 and December 31, 2011.  The following table summarizes the fair value amounts of the Company’s liability derivative instruments and their location reported in the consolidated balance sheets at the dates indicated:

		Fair Value (1)
		Successor		Predecessor
	Balance Sheet Location	December 31, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts	Other current liabilities	$	—	$	4

⁽¹⁾  See Note 7 for additional fair value information.

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Cash Flow Hedges:
Change in fair value – increase in accumulated other comprehensive income	$	—	$	—	$	1	$	13
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	—		4		22		22

12. FAIR VALUE MEASUREMENT:

The Company did not have any plan assets or liabilities that are measured at fair value on a recurring basis at December 31, 2012. The Company did not have any Level 3 instruments measured at fair value using significant unobservable inputs at December 31, 2012 or December 31, 2011 and there were no transfers between hierarchy levels.

The Company previously had outstanding Level 2 interest rate swap derivatives, which were valued using pricing models based on an income approach that discounted future cash flows to a present value amount. As of December 31, 2011, a liability of $4 million was included in the balance sheet for the fair value of interest rate swap derivative instruments.

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.

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13. PROPERTY, PLANT AND EQUIPMENT:

The following table provides a summary of property, plant and equipment at the dates indicated:

		Successor			Predecessor
	Lives in Years	December 31, 2012			December 31, 2011
Transmission	5 – 46	$	2,580		$	2,321
Gathering	26	114			108
Underground storage	5 – 46	306			322
General plant - LNG	5 – 40	966			1,119
General plant - other	3 – 40	110			176
Plant in service		4,076			4,046
Construction work in progress		45			42
Total property, plant and equipment		4,121			4,088
Accumulated depreciation and amortization		(57		)	(733		)
Net property, plant and equipment		$	4,064		$	3,355

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 years ended December 31, 2011 and 2010 was $7 million and $7 million, respectively.

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 years ended December 31, 2011 and 2010 was $2 million and $2 million, respectively.

14. STOCK-BASED COMPENSATION

Stock Award Plans.  The Third Amended 2003 Plan adopted by the stockholders of Southern Union Company allows 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 include 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 is 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.  To the extent that volatility of Southern Union Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing stock-based compensation expense in future periods.  Additionally, the expected dividend yield is considered for each grant on the date of grant.  The Company’s uses the simplified method in determining the expected term of stock options and SARs granted, which results in the use of the average midpoint between vesting of the awards and their contractual term for such estimate.  The Company utilizes the simplified method primarily because Southern Union has experienced several acquisitions and divestitures during the contractual period for the current awards outstanding, resulting in a change in the employee mix and an acceleration of certain stock option and SAR exercise activity.  Additionally, Southern Union has 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 is not believed to be indicative of future behavior.  In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term.  This change could impact the fair value of stock options and SARs granted in the future.  The risk-free rate is 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 amounts have been presented in the following sections.

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The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards for periods in which awards were granted.

	Year ended December 31, 2010
Expected volatility	32.79% to 32.82%
Expected dividend yield	2.47%
Risk-free interest rate	2.28% to 2.40%
Expected life	6 years

Stock Options.  The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable for the periods presented.

	Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2009	263,059		$	20.42
Exercised	(59,156	)	20.92
Outstanding December 31, 2010	203,903		$	20.27
Exercised	(38,596	)	17.56
Outstanding December 31, 2011	165,307		$	20.90
Exercisable December 31, 2010	203,903		$	20.27
Exercisable December 31, 2011	165,307		20.90

SARS.  The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable for the periods presented.

	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2009	556,803		$	19.08
Granted	138,181		24.54
Exercised	(49,366	)	12.55
Forfeited	(28,815	)	19.35
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, 2010	308,799		$	20.90
Exercisable December 31, 2011	423,815		19.61

The SARs that have been awarded vest in equal installments on the first three anniversaries of the grant date. Each SAR entitles 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.

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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 years ended December 31, 2011 and 2010.  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 provides for grants of restricted stock equity units, which are settled in shares of Southern Union Company common stock, and restricted stock liability units, which are settled in cash.  The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expire equally over a period of three years.  Restrictions on restricted stock liability units expire at the end of the applicable period, which is also the requisite service period.

There were no restricted stock equity awards granted during the years ended December 31, 2011 and 2010.

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, 2009	206,120		$	18.53
Granted	70,110		24.57
Released	(101,420	)	19.27
Forfeited	(8,940	)	18.49
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 and $2 million for the years ended December 31, 2011 and 2010, respectively.

The Company settled the restricted stock liability units released in 2011 and 2010 with cash payments of $4 million and $2 million, respectively.

15. COMMITMENTS AND CONTINGENCIES:

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.

Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including the Company, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  The Company believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by FERC.  As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that the Company complied with the terms of its tariffs).  In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case.  The Company believes it has no liability associated with this proceeding.

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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, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $6 million and $1 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.

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.

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current	$	1	$	3
Non-current	5		4
Total environmental liabilities	$	6	$	7

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Other Commitments and Contingencies

Controlled Group Pension Liabilities.  Southern Union (including certain of its divisions) sponsors a number of defined benefit pension plans for employees.  Under applicable pension and tax laws, upon being acquired by Southern Union, the Company became a member of Southern Union’s “controlled group” with respect to those plans and, along with Southern Union and any other members of that group, is jointly and severally liable for any failure by Southern Union (along with any other persons that may be or become a sponsor of any such plan) to fund any of these pension plans or to pay any unfunded liabilities that these plans may have if they are ever terminated.  In addition, if any of the obligations of any of these pension plans is not paid when due, a lien in favor of that plan or the Pension Benefit Guaranty Corporation may be created against the assets of each member of Southern Union’s controlled group, including the Company and each of its subsidiaries.  Based on the latest actuarial information available, the aggregate amount of the projected benefit obligations of these pension plans was approximately $243 million and the estimated fair value of all of the assets of these plans was approximately $155 million.

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.

See Note 4 for other potential regulatory matters applicable to the Company.

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.  The Company is reviewing the new standards to determine the impact on its operations.

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 is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

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 is currently reviewing 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.

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The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursing any emissions reductions from the Company’s operations unless there are changes in the future regarding the status of the Kansas City area.

16. QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	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
				June 30, 2012	September 30, 2012	December 31, 2012
Operating revenues	194	13		185	189	205	592
Operating income	88	(26	)	65	77	89	205
Net income	40	(19	)	30	37	40	88
		Predecessor
		Quarters Ended
		March 31, 2011		June 30, 2011	September 30, 2011	December 31, 2011	Total
Operating revenues		202		190	193	219	804
Operating income		91		88	82	101	362
Net income		46		40	35	47	168

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EX-12.1

Exhibit 12.1

Panhandle Eastern Pipe Line Company, LP

Computation of Ratio of Earnings to Fixed Charges

(in millions, except for ratio amounts)

(Unaudited)

The following table sets forth the consolidated ratio of earnings to fixed charges on an historical basis for the periods from March 26, 2012 to December 31, 2012 and January 1, 2012 to March 25, 2012 and the years ended December 31, 2011, 2010, 2009, and 2008. For the purpose of calculating such ratios, “earnings” consist of pre-tax income from continuing operations before income or loss from equity investees, adjusted to reflect distributed income from equity investments, and fixed charges, less capitalized interest. “Fixed charges” consist of interest costs, amortization of debt discount, premiums and issuance costs and an estimate of interest implicit in rentals. No adjustment has been made to earnings for the amortization of capital interest for the periods presented as such amount is immaterial. Interest on FIN 48 liabilities is excluded from the computation of fixed charges as it is recorded by the Company in income tax expense versus interest expense.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010			2009			2008
Fixed Charges:
Interest expense, net	$	67		$	25	$	106		$	102		$	83		$	90
Net amortization of debt discount, premium and issuance expense	(24		)	—		2			1			1			(1		)
Capitalized interest	1			—		1			7			26			19
Interest charges included in rental expense	3			1		4			4			4			3
Total fixed charges	$	47		$	26	$	113		$	114		$	114		$	111
Earnings:
Consolidated pre-tax income from continuing operations	$	164		$	65	$	263		$	245		$	243		$	247
Distributed income of equity investees	—			—		1			—			—			—
Capitalized interest	(1		)	—		(1		)	(7		)	(26		)	(19		)
Total fixed charges (from above)	47			26		113			114			114			111
Earnings Available for Fixed Charges	$	210		$	91	$	376		$	352		$	331		$	339
Ratio of earnings to fixed charges	4.5			3.5		3.3			3.1			2.9			3.1

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Kelcy L. Warren, certify that:

(1) I have reviewed this Report on Form 10-K of Panhandle Eastern Pipe Line Company, LP;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2013

/s/ KELCY L. WARREN

Kelcy L. Warren

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Martin Salinas, Jr., certify that:

(1) I have reviewed this Report on Form 10-K of Panhandle Eastern Pipe Line Company, LP;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2013

/s/ MARTIN SALINAS, JR.

Martin Salinas, Jr.

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “Company”) for the year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ KELCY L. WARREN

Kelcy L. Warren

Chief Executive Officer

March 1, 2013

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “Company”) for the year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Martin Salinas, Jr., Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ MARTIN SALINAS, JR.

Martin Salinas, Jr.

Chief Financial Officer

March 1, 2013

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Inventory (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor MMbtu		Dec. 31, 2011 Predecessor MMbtu
Natural Gas Volumes	34,891,000		29,718,000
Natural Gas Inventory	$ 124	[1]	$ 96	[1]
Inventory, Raw Materials and Supplies	20		19
System natural gas and operating supplies	144		115
Inventory, Gas in Storage Underground, Noncurrent	0	[1]	3	[1]
Energy Related Inventory	$ 144		$ 118

[1] Natural gas volumes held for operations at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 MMBtu, respectively.

XML

Debt Obligations - Narrative (Details) (USD $)	Dec. 31, 2012	Feb. 29, 2012	Dec. 31, 2011	Dec. 31, 2012 Term Loan Due August 2013	Mar. 25, 2012 Term Loan Due June 2012	Dec. 31, 2012 Term Loan Due March 2012	Feb. 29, 2012 Term Loan Due March 2012	Dec. 31, 2012 Revolver 2012
Debt Instrument
Long term debt, face amount		$ 455,000,000		$ 250,000,000	$ 465,000,000		$ 455,000,000
Debt Instrument, Fair Value Disclosure	1,810,000,000		2,130,000,000
Long term debt, amount outstanding	$ 1,760,000,000		$ 1,970,000,000		$ 342,000,000
Debt Covenant, Cross Default Feature, Minimum Amount						5
Debt, Weighted Average Interest Rate								1.84%

XML

Related Party Balances (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Southern Union	Dec. 31, 2012 Successor		Dec. 31, 2012 Successor Southern Union	Dec. 31, 2012 Successor Other accounts payable		Dec. 31, 2012 Successor Other accounts payable Southern Union		Dec. 31, 2012 Successor Income Taxes Southern Union		Dec. 31, 2011 Predecessor		Dec. 31, 2011 Predecessor Southern Union	Dec. 31, 2011 Predecessor Other accounts payable		Dec. 31, 2011 Predecessor Other accounts payable Southern Union		Dec. 31, 2011 Predecessor Income Taxes Southern Union
Related Party Transaction
Note receivable - related party, current		$ 0		$ 0							$ 342		$ 342
Notes receivable - related party, noncurrent		831		831							688		688
Notes Receivable - related party		831									1,030
Accounts receivable — related parties (1)		14	[1]								6	[1]
Accounts payable — related parties:		27			1	[2]	26	[3]	0	[4]	52			0	[2]	19	[3]	33	[4]
Insurance Proceeds - related party	$ 2

[1] Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus, MGE and other affiliates. The December 31, 2011 balance also included interest income associated with a note receivable from an affiliate, which was repaid on March 26, 2012.

[2] Accounts payable from related companies reflected above primarily related to various administrative and operating costs paid by other affiliate companies on behalf of the Company.

[3] Accounts payable from related companies reflected above primarily related to payroll funding including merger-related expenses, provided by Southern Union. The December 31, 2011 amount was net of insurance proceeds of $2 million owed by Southern Union to the Company.

[4] Accounts payable from related companies reflected above related to income taxes payable to Southern Union per the tax sharing agreement to provide for taxes to be remitted upon the filing of the tax return.

XML

TAXES ON INCOME Taxes on Income - Narrative (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 1
Unrecognized tax benfits for state filing positions, net of federal tax	$ 1

XML

Debt Obligations - Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument
Total debt outstanding	$ 1,760	$ 1,970
6.05% Senior Notes due 2013
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	6.05%
6.20% Senior Notes due 2017
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	6.20%
8.125% Senior Notes due 2019
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	8.125%
7.00% Senior Notes due 2029
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	7.00%
7.00% Senior Notes due 2018
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Successor
Debt Instrument
Net premiums on long-term debt	0
Unamortized fair value adjustments	136
Total debt outstanding	1,757
Current portion of long-term debt	(258)
Total long-term debt	1,499
Successor | 6.05% Senior Notes due 2013
Debt Instrument
Senior Notes	250
Successor | 6.20% Senior Notes due 2017
Debt Instrument
Senior Notes	300
Successor | 8.125% Senior Notes due 2019
Debt Instrument
Senior Notes	150
Successor | 7.00% Senior Notes due 2029
Debt Instrument
Senior Notes	66
Successor | 7.00% Senior Notes due 2018
Debt Instrument
Senior Notes	400
Successor | Term Loans due 2012
Debt Instrument
Term Loans	0
Successor | Term Loan due 2015
Debt Instrument
Term Loans	455
Predecessor
Debt Instrument
Net premiums on long-term debt		3
Unamortized fair value adjustments		0
Total debt outstanding		1,966
Current portion of long-term debt		(342)
Total long-term debt		1,624
Predecessor | 6.05% Senior Notes due 2013
Debt Instrument
Senior Notes		250
Predecessor | 6.20% Senior Notes due 2017
Debt Instrument
Senior Notes		300
Predecessor | 8.125% Senior Notes due 2019
Debt Instrument
Senior Notes		150
Predecessor | 7.00% Senior Notes due 2029
Debt Instrument
Senior Notes		66
Predecessor | 7.00% Senior Notes due 2018
Debt Instrument
Senior Notes		400
Predecessor | Term Loans due 2012
Debt Instrument
Term Loans		797
Predecessor | Term Loan due 2015
Debt Instrument
Term Loans		$ 0

XML

SHARE-BASED COMPENSATION Share-Based Compensation - Narrative (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	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	2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Total Share-based Liabilities Paid		$ 4	$ 2

XML

Related Party (Narrative) (Details)	Mar. 25, 2012
Related Party Transactions Phantoms [Abstract]
Debt Instrument, Basis Spread on Variable Rate	1.125%

XML

Derivative Instrument and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The Company had no asset derivative instruments at December 31, 2012 and December 31, 2011.  The following table summarizes the fair value amounts of the Company’s liability derivative instruments and their location reported in the consolidated balance sheets at the dates indicated:

		Fair Value (1)
		Successor		Predecessor
	Balance Sheet Location	December 31, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts	Other current liabilities	$	—	$	4

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Cash Flow Hedges:
Change in fair value – increase in accumulated other comprehensive income	$	—	$	—	$	1	$	13
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	—		4		22		22

XML

SHARE-BASED COMPENSATION Stock-Based Compensation - SARs (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding	616,803	556,803
Sars Outstanding Weighted Average Exercise Price	$ 20.71	$ 19.08
Granted		138,181
SARS Granted Weighted Average Exercise Price		$ 24.54
Exercised	(27,389)	(49,366)
Sars Exercised Weighted Average Exercise Price	$ 15.87	$ 12.55
Forfeitures	(30,512)	(28,815)
Sars Forfeited Weighted Average Exercise Price	$ 27.41	$ 19.35
Outstanding	558,902	616,803
Sars Outstanding Weighted Average Exercise Price	$ 20.58	$ 20.71
SARs Exercisable	423,815	308,799
SARs Exercisable Weighted Average Exercise Price	$ 19.61	$ 20.90

XML

Derivative Instrument and Hedging Activities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Derivative [Line Items]
Change in fair value – increase in accumulated other comprehensive income	$ 0	$ 0	$ 1	$ 13
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	$ 0	$ 4	$ 22	$ 22

XML

BENEFITS Benefits - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended					12 Months Ended				12 Months Ended			9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Supplemental Employee Retirement Plans, Defined Benefit	Dec. 31, 2012 Savings Plan	Dec. 31, 2012 Pension Plans, Defined Benefit	Dec. 31, 2011 Pension Plans, Defined Benefit	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2012 Successor Other Postretirement Benefit Plans, Defined Benefit	Mar. 25, 2012 Predecessor Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2011 Predecessor Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2012 Equity Securities Pension Plans, Defined Benefit	Dec. 31, 2012 Fixed Income Securities Pension Plans, Defined Benefit	Dec. 31, 2012 Supplemental Employee Retirement Plans, Defined Benefit Missouri Gas Energy	Dec. 31, 2012 Supplemental Employee Retirement Plans, Defined Benefit Successor	Mar. 25, 2012 Supplemental Employee Retirement Plans, Defined Benefit Predecessor	Dec. 31, 2011 Supplemental Employee Retirement Plans, Defined Benefit Predecessor	Dec. 31, 2010 Supplemental Employee Retirement Plans, Defined Benefit Predecessor	Dec. 31, 2012 Savings Plan Successor	Mar. 25, 2012 Savings Plan Predecessor	Dec. 31, 2011 Savings Plan Predecessor	Dec. 31, 2010 Savings Plan Predecessor	Dec. 31, 2012 Pension Plans, Defined Benefit Successor	Mar. 25, 2012 Pension Plans, Defined Benefit Predecessor	Dec. 31, 2011 Pension Plans, Defined Benefit Predecessor
Defined Benefit Plan Disclosure
Defined Contribution Plan Employers Matching Contribution Percentage to Participants Percentage Conribution	100.00%
Large Cap US Equitiies					19.00%	17.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum										25.00%	65.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum										35.00%	75.00%
Pretax curtailment gain	$ 70
Noncurrent refund liability	59
Curtailment recognition (1)	11																				(75)	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax						1
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate							3.51%	4.24%	4.26%
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum				10.00%
Small Cap US Equities					2.00%	3.00%
International Equities					10.00%	10.00%
Fixed Income Securities					55.00%	53.00%
Cash Fund Investments					8.00%	10.00%
Other Investments - Plan Asset Allocation					6.00%	7.00%
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year				8		8
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Company Contributions Vested		100.00%	100.00%
Company Contributions Years			five									five
Defined Contribution Plan, Cost Recognized													$ 2	$ 1	$ 6	$ 5	$ 3	$ 1	$ 5	$ 5

XML

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Capitalized Computer Software, Net	$ 34
Capitalized Computer Software, Accumulated Amortization	51
Capitalized Computer Software, Amortization	7	7
Contributions in Aid of Construction	49
Finite-Lived Intangible Assets, Accumulated Amortization	5
Depreciation, Depletion and Amortization	$ 2	$ 2

XML

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 0 months

XML

PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2012
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

XML

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

XML

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

12 Months Ended

Dec. 31, 2012

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
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	75	$	17	$	106	$	102
Cash paid for income taxes	32		—		35		22

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

The following table presents the balance in the allowance for doubtful accounts and activity for the periods presented.

	Years Ended December 31,
	2011		2010
Beginning balance	$	1	$	1
Additions: charged to cost and expenses	—		—
Deductions: write-off of uncollectible accounts	—		—
Other	—		—
Ending balance	$	1	$	1

Schedule of Inventory, Current [Table Text Block]

The following table presents the components of inventory at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current
Natural gas (1)	$	124	$	96
Materials and supplies	20		19
Total current	144		115
Non-Current
Natural gas (1)	—		3
	$	144	$	118

⁽¹⁾  Natural gas volumes held for operations at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 MMBtu, respectively.

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

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	31	%	30	%	30	%	29	%
ProLiance	12		13		13		13
Other top 10 customers	20		24		21		23
Remaining customers	37		33		36		35
Total percentage	100	%	100	%	100	%	100	%

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Assets (Details) (Other ARO Assets, USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Other ARO Assets
ARO Underlying Asset	$ 1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Restricted Cash and Cash Equivalents Items
Interest Paid, Net	$ 75	$ 17	$ 106	$ 102
Income Taxes Paid, Net	$ 32	$ 0	$ 35	$ 22

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PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - PPE Type (Details) (USD $) In Millions, unless otherwise specified																	12 Months Ended
	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Transmission	Dec. 31, 2012 Successor Gathering	Dec. 31, 2012 Successor Underground storage	Dec. 31, 2012 Successor General plant - LNG	Dec. 31, 2012 Successor General plant - other	Dec. 31, 2012 Successor Plant in service	Dec. 31, 2012 Successor Construction work in progress	Dec. 31, 2011 Predecessor	Dec. 31, 2011 Predecessor Transmission	Dec. 31, 2011 Predecessor Gathering	Dec. 31, 2011 Predecessor Underground storage	Dec. 31, 2011 Predecessor General plant - LNG	Dec. 31, 2011 Predecessor General plant - other	Dec. 31, 2011 Predecessor Plant in service	Dec. 31, 2011 Predecessor Construction work in progress	Dec. 31, 2012 Minimum Transmission	Dec. 31, 2012 Minimum Underground storage	Dec. 31, 2012 Minimum General plant - LNG	Dec. 31, 2012 Minimum General plant - other	Dec. 31, 2012 Maximum Transmission	Dec. 31, 2012 Maximum Gathering	Dec. 31, 2012 Maximum Underground storage	Dec. 31, 2012 Maximum General plant - LNG	Dec. 31, 2012 Maximum General plant - other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment		$ 2,580	$ 114	$ 306	$ 966	$ 110	$ 4,076			$ 2,321	$ 108	$ 322	$ 1,119	$ 176	$ 4,046
Property, Plant and Equipment, Estimated Useful Lives																	P5Y0M	P5Y0M	P5Y0M	P3Y0M	P46Y0M	P26Y0M	P46Y0M	P40Y0M	P40Y0M
Construction work in progress	45							45	42							42
Total property, plant and equipment	4,121								4,088
Accumulated depreciation and amortization	(57)								(733)
Net property, plant and equipment	$ (4,064)								$ (3,355)

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QUARTERLY OPERATIONS Quarterly Operations (Tables)

12 Months Ended

Dec. 31, 2012

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:

	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
				June 30, 2012	September 30, 2012	December 31, 2012
Operating revenues	194	13		185	189	205	592
Operating income	88	(26	)	65	77	89	205
Net income	40	(19	)	30	37	40	88
		Predecessor
		Quarters Ended
		March 31, 2011		June 30, 2011	September 30, 2011	December 31, 2011	Total
Operating revenues		202		190	193	219	804
Operating income		91		88	82	101	362
Net income		46		40	35	47	168

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Comprehensive Income (Loss) - Tax amounts in other comprehensive income (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$ 0	$ 2	$ 9	$ 9
Change in fair value of interest rate hedges	0	0	(1)	(5)
Actuarial loss relating to postretirement benefits	(6)	0	(6)	0
Reclassification of prior service credit relating to other postretirement benefits into earnings	0	0	(1)	(1)
Income tax benefit included in other comprehensive income	$ (6)	$ 2	$ 1	$ 3

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TAXES ON INCOME Taxes on Income - Unrecognized Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Schedule of Unrecognized Tax Benefits Rollforward
Unrecognized Tax Benefits	$ 1
Unrecognized tax benfits for state filing positions, net of federal tax	1
Unrecognized Tax Benefits	$ 1

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BENEFITS Benefits - Assumed Health Care Cost Trend Rates Used (Details)	3 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2011
Postemployment Benefits [Abstract]
Health care cost trend rate assumed for next year	8.00%	8.50%	8.50%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75%	4.50%	4.75%
Year that the rate reaches the ultimate trend rate	2019	2020	2019

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended					3 Months Ended	12 Months Ended		3 Months Ended		12 Months Ended				3 Months Ended		12 Months Ended
	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Southern Union		Dec. 31, 2012 Successor Affiliated Entity		Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor	Mar. 25, 2012 Predecessor Southern Union		Dec. 31, 2011 Predecessor Southern Union		Dec. 31, 2010 Predecessor Southern Union		Mar. 25, 2012 Predecessor Affiliated Entity		Dec. 31, 2011 Predecessor Affiliated Entity		Dec. 31, 2010 Predecessor Affiliated Entity
Operation and maintenance:
Transportation and storage of natural gas		$ 7	[1]						$ 1	[1]	$ 3	[1]	$ 3	[1]
Management and royalty fees				5											5		20		19
Cost of Services				47											9		32		31
Other expenses (2)				9	[2]										0	[2]	6	[2]	5	[2]
Other income, net:
Interest income	$ 2	$ 2				$ 2	$ 9	$ 9	$ 2		$ 9		$ 9

[1] Represents transportation and storage revenues with ETC, a subsidiary of ETP (in the successor period) and MGE, a Southern Union division.

[2] Represents primarily insurance costs and corporate charges for merger-related employee expenses from ETE offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

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. In 1999, the Company discontinued application of regulatory-based accounting policies for its units which had been applying such accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. The accounting required by the regulatory-based authoritative guidance differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, 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, 2012, 2011 and 2010 were each less than 1 million, respectively.

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	75	$	17	$	106	$	102
Cash paid for income taxes	32		—		35		22

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 at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current
Natural gas (1)	$	124	$	96
Materials and supplies	20		19
Total current	144		115
Non-Current
Natural gas (1)	—		3
	$	144	$	118

⁽¹⁾  Natural gas volumes held for operations at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 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 13.

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 as of November 30 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.  No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Related Party Transactions. Related party expenses primarily include payments for services provided by Southern Union.  Other income is primarily related to interest income on a note receivable from a related party.  See Note 5 for additional information on related party transactions.

A portion of the Company’s revenues for the transportation of natural gas includes revenues from MGE, a division of Southern Union that is a natural gas utility having a service territory covering Kansas City, Missouri and parts of western Missouri.

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 utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  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 for the periods presented.

	Years Ended December 31,
	2011		2010
Beginning balance	$	1	$	1
Additions: charged to cost and expenses	—		—
Deductions: write-off of uncollectible accounts	—		—
Other	—		—
Ending balance	$	1	$	1

Amounts related to the allowance for doubtful accounts were not material as of and during the year ended December 31, 2012.

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	31	%	30	%	30	%	29	%
ProLiance	12		13		13		13
Other top 10 customers	20		24		21		23
Remaining customers	37		33		36		35
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 the year in which the change occurs through Accumulated other comprehensive income in Partners’ capital. See Note 9 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 11 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 14.

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 12 and Note 9 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 6 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 will enter 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.

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BENEFITS Benefits - 1% Change in Assumed Health Care Cost Trend Rates Used (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Postemployment Benefits [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	$ 4
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	$ (3)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Politicies - Period End Cash Balances (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Mar. 25, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor	Dec. 31, 2009 Predecessor
Cash and Cash Equivalents
Cash and cash equivalents	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0

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Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2012

Statement of Other 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 for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$	—		$	2	$	9		$	9
Change in fair value of interest rate hedges	—			—		(1		)	(5		)
Actuarial loss relating to postretirement benefits	(6		)	—		(6		)	—
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—		(1		)	(1		)
	$	(6	)	$	2	$	1		$	3

Schedule of Accumulated Other Comprehensive Income (Loss)

The table below presents the components in accumulated other comprehensive loss as of the dates indicated:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Other postretirement plan - net actuarial loss and prior service costs, net	$	(9	)	$	(13	)
Interest rate hedges, net	—			(3		)
Total accumulated other comprehensive loss, net of tax	$	(9	)	$	(16	)

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Beginning balance	$	41		$	41	$	57		$	58
Incurred	1			—		1			29
Revisions	3			—		—			(11		)
Settled	(5		)	—		(17		)	(20		)
Accretion expense	2			—		—			1
Ending balance	$	42		$	41	$	41		$	57

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DEBT OBLIGATIONS Debt Obligations - Future Maturities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Debt Instrument
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 250
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	455
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	300
Long-term Debt, Maturities, Repayments of Principal after Year Five	616
Long Term Debt Maturities Repayments Of Principal Total	$ 1,621

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ETE Merger and Holdco Transaction (Narrative) (Details) (USD $)	9 Months Ended	12 Months Ended	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Mar. 31, 2012 Citrus	Dec. 31, 2012 Citrus	Mar. 25, 2012 Citrus	Oct. 05, 2012 ETE Holdco	Oct. 05, 2012 ETP Holdco
Percentage owned by equity investment				50.00%
Total merger amount					$ 2,000,000,000
Merger amount, in cash					1,900,000,000
Merger amount, in common units			105,000,000
Maximum contribution equity interest merger			1,450,000,000
Merger related expenses	48,000,000
Net gain due to curtailment of postretirement employee benefit plans	$ 11,000,000
Intangible asset, estimated useful life		17 years 6 months
Ownership of Parent						60.00%	40.00%

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Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Schedule Of Debt Instruments

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

	Successor			Predecessor
	December 31, 2012			December 31, 2011
6.05% Senior Notes due 2013	$	250		$	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 Loans due 2012	—			797
Term Loan due 2015	455			—
Net premiums on long-term debt	—			3
Unamortized fair value adjustments	136			—
Total debt outstanding	1,757			1,966
Current portion of long-term debt	(258		)	(342		)
Total long-term debt	$	1,499		$	1,624

Schedule of Maturities of Long-term Debt

As of December 31, 2012, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2013	$	250
2014	—
2015	455
2016	—
2017	300
Thereafter	616
Total	$	1,621

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Benefits (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012			March 25, 2012		December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of period	$	93		$	88	$	69
Service cost	—			1		3
Interest cost	1			1		4
Amendments	16			—		—
Actuarial loss and other	4			3		13
Benefits paid, net	(1		)	—		(1		)
Curtailments	(75		)	—		—
Benefit obligation at end of period	$	38		$	93	$	88
Change in plan assets:
Fair value of plan assets at beginning of period	$	82		$	75	$	68
Return on plan assets and other	3			5		—
Employer contributions	6			2		8
Benefits paid, net	(1		)	—		(1		)
Fair value of plan assets at end of period	$	90		$	82	$	75
Amount (overfunded) underfunded at end of period (1)	$	(52	)	$	11	$	13
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(1	)	$	—	$	23
Prior service cost	16			—		1
	$	15		$	—	$	24

⁽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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Service cost	$	—		$	1		$	2		$	3
Interest cost	1			1			4			4
Expected return on plan assets	(3		)	(1		)	(3		)	(3		)
Prior service credit amortization	—			(1		)	(2		)	(2		)
Curtailment recognition (1)	(11		)	—			—			—
Net periodic benefit cost	$	(13	)	$	—		$	1		$	2

⁽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.

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
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Discount rate	3.64	%	4.26	%	5.54	%	6.00	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%	5.00	%

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, 2012		March 25, 2012		December 31, 2011
Health care cost trend rate assumed for next year	8.50	%	8.00	%	8.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.50	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2020		2019		2019

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

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	$	4	$	(3	)

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:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Cash and cash equivalents	$	2	$	2
Mutual fund (1)	88		73
Total	$	90	$	75

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments.  The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D Subsidy Receipts		Net
2013	$	3	$	—	$	3
2014	3		—		3
2015	3		—		3
2016	3		—		3
2017	3		—		3
2018 – 2022	12		2		10

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Description of the Business

12 Months Ended

Dec. 31, 2012

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 ETE;

• 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;

• Trunkline LNG, a direct wholly-owned subsidiary of LNG Holdings; and

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

The Company’s assets 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.  The Company also owns and operates 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 Southern Union, serves as the general partner of PEPL and owns a 1% general partnership interest in PEPL.  PEPL Holdings, LLC, an indirect wholly-owned subsidiary of Southern Union, owns a 99% limited partnership interest in PEPL.

See Note 3 for information related to Southern Union’s merger with ETE and the completion of the Holdco Transaction.

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Taxes on Income (Tables)

12 Months Ended

Dec. 31, 2012

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 for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Current expense (benefit):
Federal	$	(8	)	$	5		$	24		$	34
State	(2		)	1			(5		)	11
Total	(10		)	6			19			45
Deferred expense:
Federal	$	72		$	17		$	67		$	51
State	14			2			9			1
Total	86			19			76			52
Total income tax expense	$	76		$	25		$	95		$	97
Effective tax rate	46		%	38		%	36		%	40		%

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:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Deferred income tax assets:
Other postretirement benefits	$	52		$	13
Derivative financial instruments (interest rates)	13			4
Other	18			20
Total deferred income tax assets	83			37
Deferred income tax liabilities:
Property, plant and equipment	(925		)	(559		)
Other	(2		)	(7		)
Total deferred income tax liabilities	(927		)	(566		)
Net deferred income tax liability	(844		)	(529		)
Less current income tax assets	9			9
Accumulated deferred income taxes	$	(853	)	$	(538	)

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

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Computed statutory income tax expense at 35%	$	57	$	23	$	92	$	86
Changes in income taxes resulting from:
Non-deductible executive compensation	11		—		—		—
State income taxes, net of federal income tax benefit	8		2		3		8
Other	—		—		—		3
Income tax expense	$	76	$	25	$	95	$	97

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Commitment and Contingenices (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]
Estimated litigation liability	$ 6		$ 1
Aggregate amount of projected benefit obligations of pension plans		243
Estimated fair value of all assets of pension plans	$ 90	$ 155	$ 75

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Allowance for Doubtful Accounts (Details) (USD $) In Millions, unless otherwise specified		12 Months Ended
	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Beginning balance	$ 0	$ 1	$ 1
Additions: charged (credited) to expense		0	0
Deductions: write-off of uncollectible accounts		0	0
Other		0	0
Ending balance	$ 0	$ 1	$ 1

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Comprehensive Income (Loss) - Components of AOCI (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor
Comprehensive Income Loss [Line Items]
Other postretirement plan - net actuarial loss and prior service costs, net	$ (9)	$ (13)
Interest rate hedges, net	0	(3)
Total accumulated other comprehensive loss, net of tax	$ (9)	$ (16)

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Derivative Instruments and Hedging Assets / Liabilities (Details) (Other current liabilities, USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor
Derivatives, Fair Value [Line Items]
Interest rate contracts	$ 0	$ 4

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor
CURRENT ASSETS:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable net of allowances of nil and $1, respectively	74	76
Accounts receivable from related companies	14	6
Natural gas imbalances receivable	10	53
Note receivable from related party	0	342
System natural gas and operating supplies	144	115
Other	20	21
Total current assets	262	613
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	4,076	4,046
Construction work in progress	45	42
Total property, plant and equipment	4,121	4,088
Accumulated depreciation and amortization	(57)	(733)
Net property, plant and equipment	4,064	3,355
GOODWILL	1,785	0
NOTE RECEIVABLE FROM RELATED PARTY	831	688
OTHER NON-CURRENT ASSETS	108	19
Total assets	7,050	4,675
CURRENT LIABILITIES:
Current portion of long-term debt	258	342
Accounts payable	12	13
Accounts payable to related companies	27	52
Natural gas imbalances — payable	130	145
Accrued taxes	13	18
Accrued interest	13	14
Capital accruals	13	11
Other	56	56
Total current liabilities	522	651
LONG-TERM DEBT, less current portion	1,499	1,624
DEFERRED INCOME TAXES	853	538
OTHER NON-CURRENT LIABILITIES	135	70
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Partners’ capital	4,050	1,809
Accumulated other comprehensive loss	(9)	(16)
Tax sharing note receivable — related party	0	(1)
Total partners’ capital	4,041	1,792
Total liabilities and partners’ capital	$ 7,050	$ 4,675

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ETE Merger and Holdco Transaction (Details) (USD $) In Millions, unless otherwise specified	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)		55	[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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 88	$ 40	$ 168	$ 148
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	125	30	128	123
Deferred income taxes	86	19	76	52
Amortization of costs charged to interest	(24)	0	0	0
Net gain on curtailment of OPEB benefits	(11)	0	0	0
Changes in operating assets and liabilities, net of Merger impact	(77)	23	(28)	(21)
Net cash flows provided by operating activities	187	112	344	302
CASH FLOWS FROM INVESTING ACTIVITIES:
Net (increase) decrease in note receivable - related parties	(55)	255	(207)	(128)
Net (decrease) increase in income taxes payable - related parties	(43)	5	(10)	21
Additions to property, plant and equipment	(90)	(28)	(111)	(161)
Plant retirements and other	0	0	0	7
Net cash flows (used in) provided by investing activities	(188)	232	(328)	(261)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	0	455	0	0
Repayment of debt	0	(797)	(18)	(41)
Issuance costs of debt	0	(2)	0	0
Other	1	0	2	0
Net cash flows provided by (used in) financing activities	1	(344)	(16)	(41)
INCREASE IN CASH AND CASH EQUIVALENTS	0	0	0	0
CASH AND CASH EQUIVALENTS, beginning of period	0	0	0	0
CASH AND CASH EQUIVALENTS, end of period	$ 0	$ 0	$ 0	$ 0

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Benefits - Components of Net Periodic Benefit Cost (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	9 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Successor		Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Defined Benefit Plan Disclosure
Service cost		$ 0		$ 1	$ 2	$ 3
Interest cost		1		1	4	4
Expected return on plan assets		(3)		(1)	(3)	(3)
Prior service credit amortization		0		(1)	(2)	(2)
Curtailment recognition (1)	11	(11)	[1]	0	0	0
Net periodic benefit cost		(13)		0	1	2
Pretax curtailment gain	70
Noncurrent refund liability	$ 59

[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.

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SHARE-BASED COMPENSATION Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

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

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards for periods in which awards were granted.

	Year ended December 31, 2010
Expected volatility	32.79% to 32.82%
Expected dividend yield	2.47%
Risk-free interest rate	2.28% to 2.40%
Expected life	6 years

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 for the periods presented.

	Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2009	263,059		$	20.42
Exercised	(59,156	)	20.92
Outstanding December 31, 2010	203,903		$	20.27
Exercised	(38,596	)	17.56
Outstanding December 31, 2011	165,307		$	20.90
Exercisable December 31, 2010	203,903		$	20.27
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 for the periods presented.

	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2009	556,803		$	19.08
Granted	138,181		24.54
Exercised	(49,366	)	12.55
Forfeited	(28,815	)	19.35
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, 2010	308,799		$	20.90
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, 2009	206,120		$	18.53
Granted	70,110		24.57
Released	(101,420	)	19.27
Forfeited	(8,940	)	18.49
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

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Taxes on Income - Current and Deferred (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Income Tax Disclosure
Federal	$ (8)	$ 5	$ 24	$ 34
State	(2)	1	(5)	11
Current Income Tax Expense (Benefit)	(10)	6	19	45
Federal	72	17	67	51
State	14	2	9	1
Deferred income taxes	86	19	76	52
Total income tax expense	$ 76	$ 25	$ 95	$ 97
Effective tax rate	46.4396%	38.00%	36.00%	40.00%

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Commitments and Contingencies Disclosure

COMMITMENTS AND CONTINGENCIES:

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.

Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including the Company, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  The Company believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by FERC.  As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that the Company complied with the terms of its tariffs).  In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case.  The Company believes it has no liability associated with this proceeding.

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, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $6 million and $1 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.

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.

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current	$	1	$	3
Non-current	5		4
Total environmental liabilities	$	6	$	7

Other Commitments and Contingencies

Controlled Group Pension Liabilities.  Southern Union (including certain of its divisions) sponsors a number of defined benefit pension plans for employees.  Under applicable pension and tax laws, upon being acquired by Southern Union, the Company became a member of Southern Union’s “controlled group” with respect to those plans and, along with Southern Union and any other members of that group, is jointly and severally liable for any failure by Southern Union (along with any other persons that may be or become a sponsor of any such plan) to fund any of these pension plans or to pay any unfunded liabilities that these plans may have if they are ever terminated.  In addition, if any of the obligations of any of these pension plans is not paid when due, a lien in favor of that plan or the Pension Benefit Guaranty Corporation may be created against the assets of each member of Southern Union’s controlled group, including the Company and each of its subsidiaries.  Based on the latest actuarial information available, the aggregate amount of the projected benefit obligations of these pension plans was approximately $243 million and the estimated fair value of all of the assets of these plans was approximately $155 million.

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.

See Note 4 for other potential regulatory matters applicable to the Company.

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.  The Company is reviewing the new standards to determine the impact on its operations.

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 is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

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 is currently reviewing 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.

The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursing any emissions reductions from the Company’s operations unless there are changes in the future regarding the status of the Kansas City area.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Environmental Liabilities Table

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.

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current	$	1	$	3
Non-current	5		4
Total environmental liabilities	$	6	$	7

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

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.

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. In 1999, the Company discontinued application of regulatory-based accounting policies for its units which had been applying such accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. The accounting required by the regulatory-based authoritative guidance differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, 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.

Consolidation, Policy [Policy Text Block]

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 [Policy Text Block]

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, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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, 2012, 2011 and 2010 were each less than 1 million, respectively.

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Supplemental Cash Flow Information:
Cash paid for interest, net of interest capitalized	$	75	$	17	$	106	$	102
Cash paid for income taxes	32		—		35		22

Inventory, Policy [Policy Text Block]

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 at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current
Natural gas (1)	$	124	$	96
Materials and supplies	20		19
Total current	144		115
Non-Current
Natural gas (1)	—		3
	$	144	$	118

⁽¹⁾  Natural gas volumes held for operations at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 MMBtu, respectively.

Natural Gas Exchanges [Policy Text Block]

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 [Policy Text Block]

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, Policy [Policy Text Block]

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 13.

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

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 and Intangible Assets, Policy [Policy Text Block]

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 as of November 30 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.  No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Related Party Transactions Disclosure [Policy Text Block]

Related Party Transactions. Related party expenses primarily include payments for services provided by Southern Union.  Other income is primarily related to interest income on a note receivable from a related party.  See Note 5 for additional information on related party transactions.

A portion of the Company’s revenues for the transportation of natural gas includes revenues from MGE, a division of Southern Union that is a natural gas utility having a service territory covering Kansas City, Missouri and parts of western Missouri.

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 Cost, Expense Policy [Policy Text Block]

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.

Revenue Recognition, Policy [Policy Text Block]

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.

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

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 utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  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 for the periods presented.

	Years Ended December 31,
	2011		2010
Beginning balance	$	1	$	1
Additions: charged to cost and expenses	—		—
Deductions: write-off of uncollectible accounts	—		—
Other	—		—
Ending balance	$	1	$	1

Amounts related to the allowance for doubtful accounts were not material as of and during the year ended December 31, 2012.

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	31	%	30	%	30	%	29	%
ProLiance	12		13		13		13
Other top 10 customers	20		24		21		23
Remaining customers	37		33		36		35
Total percentage	100	%	100	%	100	%	100	%

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

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 the year in which the change occurs through Accumulated other comprehensive income in Partners’ capital. See Note 9 for additional related information.

Derivatives, Policy [Policy Text Block]

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 11 for information related to derivative instruments and hedging activities.

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

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 12 and Note 9 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]

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 6 for additional related information.

Income Tax, Policy [Policy Text Block]

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 will enter 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.

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

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 14.

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TAXES ON INCOME Income Taxes - Effective Rate Reconciliation (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Schedule of Effective Income Tax Rate Reconciliation
Computed statutory income tax expense at 35%	$ 57	$ 23	$ 92	$ 86
Income Tax Reconciliation, Nondeductible Expense, Other	11	0	0	0
State income taxes, net of federal income tax benefit	8	2	3	8
Income Tax Reconciliation, Other Adjustments	0	0	0	3
Total income tax expense	$ 76	$ 25	$ 95	$ 97

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CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (USD $) In Millions	Predecessor	Predecessor Partners’ Capital	Predecessor Accumulated Other Comprehensive Loss	Predecessor Tax Sharing Note Receivable-Related Party	Successor	Successor Partners’ Capital	Successor Accumulated Other Comprehensive Loss	Successor Tax Sharing Note Receivable-Related Party
Balance at Dec. 31, 2009	$ 1,468	$ 1,493	$ (20)	$ (5)
Tax sharing receivable - Southern Union	2	0	0	2
Net income	148	148	0	0
Other comprehensive income, net of tax	3	0	3	0
Balance at Dec. 31, 2010	1,621	1,641	(17)	(3)
Net income	46
Balance at Mar. 31, 2011
Balance at Dec. 31, 2010	1,621	1,641	(17)	(3)
Tax sharing receivable - Southern Union	2	0	0	2
Net income	168	168	0	0
Other comprehensive income, net of tax	1	0	1	0
Balance at Dec. 31, 2011	1,792	1,809	(16)	(1)
Balance at Sep. 30, 2011
Net income	47
Balance at Dec. 31, 2011	1,792	1,809	(16)	(1)
Tax sharing receivable - Southern Union	0	0	0	0
Net income	40	40	0	0
Other comprehensive income, net of tax	3	0	3	0
Balance at Mar. 25, 2012	1,835	1,849	(13)	(1)	3,961	3,962	0	(1)
Tax sharing receivable - Southern Union					1	0	0	1
Net income					88	88	0	0
Other comprehensive income, net of tax					(9)	0	(9)	0
Balance at Dec. 31, 2012					4,041	4,050	(9)	0
Balance at Sep. 30, 2012
Net income					40
Balance at Dec. 31, 2012					$ 4,041

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PARENTHETICAL DISCLOSURE OF CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor	Dec. 31, 2009 Predecessor
Allowance for doubtful accounts	$ 0	$ 1	$ 1	$ 1

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Taxes on Income

12 Months Ended

Dec. 31, 2012

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 for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Current expense (benefit):
Federal	$	(8	)	$	5		$	24		$	34
State	(2		)	1			(5		)	11
Total	(10		)	6			19			45
Deferred expense:
Federal	$	72		$	17		$	67		$	51
State	14			2			9			1
Total	86			19			76			52
Total income tax expense	$	76		$	25		$	95		$	97
Effective tax rate	46		%	38		%	36		%	40		%

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Computed statutory income tax expense at 35%	$	57	$	23	$	92	$	86
Changes in income taxes resulting from:
Non-deductible executive compensation	11		—		—		—
State income taxes, net of federal income tax benefit	8		2		3		8
Other	—		—		—		3
Income tax expense	$	76	$	25	$	95	$	97

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:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Deferred income tax assets:
Other postretirement benefits	$	52		$	13
Derivative financial instruments (interest rates)	13			4
Other	18			20
Total deferred income tax assets	83			37
Deferred income tax liabilities:
Property, plant and equipment	(925		)	(559		)
Other	(2		)	(7		)
Total deferred income tax liabilities	(927		)	(566		)
Net deferred income tax liability	(844		)	(529		)
Less current income tax assets	9			9
Accumulated deferred income taxes	$	(853	)	$	(538	)

As of December 31, 2012, the Company has $1 million ($1 million, net of federal tax) of unrecognized tax benefits, none of which would impact the Company’s EITR 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.

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Document And Entity Information (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Document Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
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	0

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2012

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.  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, 2012, 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 asset derivative instruments at December 31, 2012 and December 31, 2011.  The following table summarizes the fair value amounts of the Company’s liability derivative instruments and their location reported in the consolidated balance sheets at the dates indicated:

		Fair Value (1)
		Successor		Predecessor
	Balance Sheet Location	December 31, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts	Other current liabilities	$	—	$	4

⁽¹⁾  See Note 7 for additional fair value information.

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 for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Cash Flow Hedges:
Change in fair value – increase in accumulated other comprehensive income	$	—	$	—	$	1	$	13
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense	—		4		22		22

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SHARE-BASED COMPENSATION Stock-Based Compensation - Stock Options (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding	203,903	263,059
Weighted Average Exercise Price	$ 20.27	$ 20.42
Exercised	(38,596)	(59,156)
Outstanding	165,307	203,903
Weighted Average Exercise Price	$ 20.90	$ 20.27
Exercisable	165,307	203,903
Weighted Average Exercise Price Exercisable	$ 20.90	$ 20.27
ShareBasedCompensationArrangementByShareBasedPayment Award Excercises in Period Weighted Average Excercise Price	$ 17.56	$ 20.92

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
OPERATING REVENUES:
Transportation and storage of natural gas	$ 417	$ 140	$ 574	$ 561
LNG terminalling	166	51	220	199
Other	9	3	10	9
Total operating revenues	592	194	804	769
OPERATING EXPENSES:
Operating, maintenance and general	173	53	221	216
Operating, maintenance and general - affiliate	61	14	58	55
Depreciation and amortization	125	30	128	123
Taxes, other than on income	28	9	35	36
Total operating expenses	387	106	442	430
OPERATING INCOME	205	88	362	339
OTHER INCOME (EXPENSE):
Interest expense	(43)	(25)	(108)	(103)
Interest income - affiliates	2	2	9	9
Total other expenses, net	(41)	(23)	(99)	(94)
INCOME BEFORE INCOME TAX EXPENSE	164	65	263	245
Income tax expense	76	25	95	97
NET INCOME	$ 88	$ 40	$ 168	$ 148

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS:

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

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Notes receivable from related party — Southern Union and subsidiaries:
Current	$	—	$	342
Non-current	831		688
	$	831	$	1,030
Accounts receivable from related companies (1)	$	14	$	6
Accounts payable to related companies:
Southern Union — income taxes (2)	$	—	$	33
Southern Union — other (3)	26		19
Other (4)	1		—
	$	27	$	52

(1) Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus, MGE and other affiliates. The December 31, 2011 balance also included interest income associated with a note receivable from an affiliate, which was repaid on March 26, 2012.

(2) Accounts payable from related companies reflected above related to income taxes payable to Southern Union per the tax sharing agreement to provide for taxes to be remitted upon the filing of the tax return.

(3) Accounts payable from related companies reflected above primarily related to payroll funding including merger-related expenses, provided by Southern Union.  The December 31, 2011 amount was net of insurance proceeds of $2 million owed by Southern Union to the Company.

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

The following tables provide a summary of related party transactions for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Transportation and storage of natural gas (1)	$	7	$	1	$	3	$	3
Operation and maintenance and general-affiliate:
Management and royalty fees	5		5		20		19
Corporate services - Southern Union	47		9		32		31
Other expenses (2)	9		—		6		5
Other income, net:
Interest income — Southern Union and subsidiaries	2		2		9		9

⁽¹⁾  Represents transportation and storage revenues with ETC, a subsidiary of ETP (in the successor period) and MGE, a Southern Union division.

⁽²⁾  Represents primarily insurance costs and corporate charges for merger-related employee expenses from ETE 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.

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Regulatory Matters

12 Months Ended

Dec. 31, 2012

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

Regulatory Matters

REGULATORY MATTERS:

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 is subject to FERC approval. Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission’s requests for additional information on this application.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

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QUARTERLY OPERATIONS

12 Months Ended

Dec. 31, 2012

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:

	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
				June 30, 2012	September 30, 2012	December 31, 2012
Operating revenues	194	13		185	189	205	592
Operating income	88	(26	)	65	77	89	205
Net income	40	(19	)	30	37	40	88
		Predecessor
		Quarters Ended
		March 31, 2011		June 30, 2011	September 30, 2011	December 31, 2011	Total
Operating revenues		202		190	193	219	804
Operating income		91		88	82	101	362
Net income		46		40	35	47	168

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Fair Value Measurement

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

FAIR VALUE MEASUREMENT:

The Company did not have any plan assets or liabilities that are measured at fair value on a recurring basis at December 31, 2012. The Company did not have any Level 3 instruments measured at fair value using significant unobservable inputs at December 31, 2012 or December 31, 2011 and there were no transfers between hierarchy levels.

The Company previously had outstanding Level 2 interest rate swap derivatives, which were valued using pricing models based on an income approach that discounted future cash flows to a present value amount. As of December 31, 2011, a liability of $4 million was included in the balance sheet for the fair value of interest rate swap derivative instruments.

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.

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Commitments and Contingencies - Accrued Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor
Loss Contingencies [Line Items]
Current	$ 1	$ 3
Non-current	5	4
Total environmental liabilities	$ 6	$ 7

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Debt Obligations

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

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

	Successor			Predecessor
	December 31, 2012			December 31, 2011
6.05% Senior Notes due 2013	$	250		$	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 Loans due 2012	—			797
Term Loan due 2015	455			—
Net premiums on long-term debt	—			3
Unamortized fair value adjustments	136			—
Total debt outstanding	1,757			1,966
Current portion of long-term debt	(258		)	(342		)
Total long-term debt	$	1,499		$	1,624

The Company has $250 million principal amount of senior notes which mature within the next twelve months. The Company currently expects to refinance all or a portion of the debt upon maturity or, alternatively, to retire all or a portion of the debt with proceeds from repayment of the note receivable from Southern Union, which funds are available to the Company on a demand basis.

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, 2012 and 2011 was $1.81 billion and $2.13 billion, respectively. As of December 31, 2012 and 2011, the aggregate carrying amount of our consolidated debt obligations was $1.76 billion and $1.97 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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. Under LNG Holding's $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5 times. The annualized interest rate for the LNG Holdings term loan was 1.84% at December 31, 2012.

Other.  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, 2012, the Company is in compliance with these covenants.

As of December 31, 2012, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2013	$	250
2014	—
2015	455
2016	—
2017	300
Thereafter	616
Total	$	1,621

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BENEFITS Benefits - Weighted-average Assumptions (Details)	3 Months Ended	12 Months Ended
	Mar. 25, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Postemployment Benefits [Abstract]
Discount rate	4.26%	3.64%	5.54%	6.00%
Tax exempt accounts	7.00%	7.00%	7.00%	7.00%
Taxable accounts	4.50%	4.50%	4.50%	5.00%

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2012

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.

As of December 31, 2012, 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 $1 million and were reflected as non-current assets on our balance sheet.

As of December 31, 2012, the Company had no 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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Beginning balance	$	41		$	41	$	57		$	58
Incurred	1			—		1			29
Revisions	3			—		—			(11		)
Settled	(5		)	—		(17		)	(20		)
Accretion expense	2			—		—			1
Ending balance	$	42		$	41	$	41		$	57

In 2010, additional AROs of $29 million were established primarily for the Company’s offshore assets. During 2010, the Company largely completed its assessment and repairs of the property damaged by Hurricane Ike in 2008, which resulted in accelerated abandonments of such property, and determined that the estimated third party abandonment costs for all of its offshore property needed to be increased.  Also in 2010, the Company recorded an $11 million downward revision to its prior ARO liability estimates, primarily for the costs of abandoning certain other specific offshore properties as a result of favorable weather conditions, changes in equipment used, and some changes in scope of the respective projects, which were primarily related to abandonments required as a result of permanent damage from Hurricane Ike.  The ARO liability associated with Hurricane Ike was further reduced by settlements of $20 million.  Such revisions and settlements were primarily associated with AROs of $8 million and $34 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike.   During 2011, the Company recorded settlements of approximately $17 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike.  See Note 15 for additional related information related to 2008 Hurricane Damage.

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Comprehensive Income

12 Months Ended

Dec. 31, 2012

Statement of Other Comprehensive Income [Abstract]

Comprehensive Income

COMPREHENSIVE INCOME:

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

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Income taxes included in other comprehensive income:
Reclassification of unrealized loss on interest rate hedges into earnings	$	—		$	2	$	9		$	9
Change in fair value of interest rate hedges	—			—		(1		)	(5		)
Actuarial loss relating to postretirement benefits	(6		)	—		(6		)	—
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—		(1		)	(1		)
	$	(6	)	$	2	$	1		$	3

The table below presents the components in accumulated other comprehensive loss as of the dates indicated:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Other postretirement plan - net actuarial loss and prior service costs, net	$	(9	)	$	(13	)
Interest rate hedges, net	—			(3		)
Total accumulated other comprehensive loss, net of tax	$	(9	)	$	(16	)

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Benefits

12 Months Ended

Dec. 31, 2012

Postemployment Benefits [Abstract]

Benefits

BENEFITS:

Postretirement Benefit Plans

The 2012 postretirement benefits expense reflects 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.  The health care plans provided for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles and coinsurance on the amount the Company paid annually to provide future retiree health care coverage under certain of these plans.

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, 2012			March 25, 2012		December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of period	$	93		$	88	$	69
Service cost	—			1		3
Interest cost	1			1		4
Amendments	16			—		—
Actuarial loss and other	4			3		13
Benefits paid, net	(1		)	—		(1		)
Curtailments	(75		)	—		—
Benefit obligation at end of period	$	38		$	93	$	88
Change in plan assets:
Fair value of plan assets at beginning of period	$	82		$	75	$	68
Return on plan assets and other	3			5		—
Employer contributions	6			2		8
Benefits paid, net	(1		)	—		(1		)
Fair value of plan assets at end of period	$	90		$	82	$	75
Amount (overfunded) underfunded at end of period (1)	$	(52	)	$	11	$	13
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(1	)	$	—	$	23
Prior service cost	16			—		1
	$	15		$	—	$	24

⁽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
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Service cost	$	—		$	1		$	2		$	3
Interest cost	1			1			4			4
Expected return on plan assets	(3		)	(1		)	(3		)	(3		)
Prior service credit amortization	—			(1		)	(2		)	(2		)
Curtailment recognition (1)	(11		)	—			—			—
Net periodic benefit cost	$	(13	)	$	—		$	1		$	2

⁽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 credit for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2013 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.51%, 4.24% and 4.26% in the successor and predecessor periods in 2012 and at December 31, 2011, respectively.

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Discount rate	3.64	%	4.26	%	5.54	%	6.00	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%	5.00	%

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, 2012		March 25, 2012		December 31, 2011
Health care cost trend rate assumed for next year	8.50	%	8.00	%	8.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.50	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2020		2019		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	$	4	$	(3	)

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:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Cash and cash equivalents	$	2	$	2
Mutual fund (1)	88		73
Total	$	90	$	75

⁽¹⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds.  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.  As of December 31, 2011, the fund was primarily comprised of approximately 19% large-cap U.S. equities, 2% small-cap U.S. equities, 10% international equities, 55% fixed income securities, 8% cash and 6% 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 contribute approximately $8 million to its other postretirement plans in 2013 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:

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D Subsidy Receipts		Net
2013	$	3	$	—	$	3
2014	3		—		3
2015	3		—		3
2016	3		—		3
2017	3		—		3
2018 – 2022	12		2		10

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Defined Contribution Plan

The Company sponsors a defined contribution savings plan (Savings Plan) that is available to 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 are 100% vested after five years of continuous service.  Company contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $3 million, $1 million, $5 million and $5 million, respectively.

In addition, the Company makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation with the amount generally varying based on age and years of service.  Company contributions are 100% vested after five years of continuous service.  Company contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $2 million, $1 million, $6 million and $5 million, respectively.

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BENEFITS Benefits - Estimate of Expected Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 3
Prescription Drug Subsidy Receipts, Year One	0
Defined Benefit Plan, Expected Future Benefit Payments in Year One, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	3
Prescription Drug Subsidy Receipts, Year Two	0
Defined Benefit Plan, Expected Future Benefit Payments in Year Two, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	3
Prescription Drug Subsidy Receipts, Year Three	0
Defined Benefit Plan, Expected Future Benefit Payments in Year Three, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	3
Prescription Drug Subsidy Receipts, Year Four	0
Defined Benefit Plan, Expected Future Benefit Payments in Year Four, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3
Prescription Drug Subsidy Receipts, Year Five	0
Defined Benefit Plan, Expected Future Benefit Payments in Year Five, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	12
Prescription Drug Subsidy Receipts, Five Fiscal Years Thereafter	2
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter, net	12
Other Postretirement Benefit Plans, Defined Benefit Net of Medical Subsidiary Receipts [Member]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	3
Defined Benefit Plan, Expected Future Benefit Payments in Year One, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Two, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Three, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Four, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Five, net	3
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	10
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter, net	$ 10

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QUARTERLY OPERATIONS Quarterly Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended					12 Months Ended		0 Months Ended	3 Months Ended			9 Months Ended
	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Sep. 30, 2011 Predecessor	Jun. 30, 2011 Predecessor	Mar. 31, 2011 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor	Mar. 31, 2013 Successor	Dec. 31, 2012 Successor	Sep. 30, 2012 Successor	Jun. 30, 2012 Successor	Dec. 31, 2012 Successor
Operating revenues	$ 194	$ 219	$ 193	$ 190	$ 202	$ 804	$ 769	$ 13	$ 205	$ 189	$ 185	$ 592
Operating income	88	101	82	88	91	362	339	(26)	89	77	65	205
Net income	$ 40	$ 47	$ 35	$ 40	$ 46	$ 168	$ 148	$ (19)	$ 40	$ 37	$ 30	$ 88

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TAXES ON INCOME Taxes on Income - Actual versus Statutory (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Computed statutory income tax expense at 35%	$ 57	$ 23	$ 92	$ 86
Income Tax Reconciliation, Nondeductible Expense, Other	11	0	0	0
State income taxes, net of federal income tax benefit	8	2	3	8
Permanent differences and other	0	0	0	3
Total income tax expense	$ 76	$ 25	$ 95	$ 97

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BENEFITS Benefits - Fair Value of Assets by Category (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2011
Defined Benefit Plan, Fair Value of Plan Assets	$ 90	$ 155	$ 75
Cash and Cash Equivalents
Defined Benefit Plan, Fair Value of Plan Assets	2		2
Mutual Fund
Defined Benefit Plan, Fair Value of Plan Assets	$ 88		$ 73

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

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

The following table provides a summary of property, plant and equipment at the dates indicated:

		Successor			Predecessor
	Lives in Years	December 31, 2012			December 31, 2011
Transmission	5 – 46	$	2,580		$	2,321
Gathering	26	114			108
Underground storage	5 – 46	306			322
General plant - LNG	5 – 40	966			1,119
General plant - other	3 – 40	110			176
Plant in service		4,076			4,046
Construction work in progress		45			42
Total property, plant and equipment		4,121			4,088
Accumulated depreciation and amortization		(57		)	(733		)
Net property, plant and equipment		$	4,064		$	3,355

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Schedule of Changes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Beginning balance					$ 41	$ 41	$ 57	$ 58
Incurred			8	34	1	0	1	29
Revisions					3	0	0	(11)
Settled	17	20			(5)	0	(17)	(20)
Accretion expense					2	0	0	1
Ending balance					$ 42	$ 41	$ 41	$ 57

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SHARE-BASED COMPENSATION Share-Based Compensation

12 Months Ended

Dec. 31, 2012

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 allows 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 include 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 is 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.  To the extent that volatility of Southern Union Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing stock-based compensation expense in future periods.  Additionally, the expected dividend yield is considered for each grant on the date of grant.  The Company’s uses the simplified method in determining the expected term of stock options and SARs granted, which results in the use of the average midpoint between vesting of the awards and their contractual term for such estimate.  The Company utilizes the simplified method primarily because Southern Union has experienced several acquisitions and divestitures during the contractual period for the current awards outstanding, resulting in a change in the employee mix and an acceleration of certain stock option and SAR exercise activity.  Additionally, Southern Union has 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 is not believed to be indicative of future behavior.  In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term.  This change could impact the fair value of stock options and SARs granted in the future.  The risk-free rate is 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 amounts have been presented in the following sections.

The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards for periods in which awards were granted.

	Year ended December 31, 2010
Expected volatility	32.79% to 32.82%
Expected dividend yield	2.47%
Risk-free interest rate	2.28% to 2.40%
Expected life	6 years

Stock Options.  The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable for the periods presented.

	Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2009	263,059		$	20.42
Exercised	(59,156	)	20.92
Outstanding December 31, 2010	203,903		$	20.27
Exercised	(38,596	)	17.56
Outstanding December 31, 2011	165,307		$	20.90
Exercisable December 31, 2010	203,903		$	20.27
Exercisable December 31, 2011	165,307		20.90

SARS.  The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable for the periods presented.

	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2009	556,803		$	19.08
Granted	138,181		24.54
Exercised	(49,366	)	12.55
Forfeited	(28,815	)	19.35
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, 2010	308,799		$	20.90
Exercisable December 31, 2011	423,815		19.61

The SARs that have been awarded vest in equal installments on the first three anniversaries of the grant date. Each SAR entitles 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 years ended December 31, 2011 and 2010.  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 provides for grants of restricted stock equity units, which are settled in shares of Southern Union Company common stock, and restricted stock liability units, which are settled in cash.  The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expire equally over a period of three years.  Restrictions on restricted stock liability units expire at the end of the applicable period, which is also the requisite service period.

There were no restricted stock equity awards granted during the years ended December 31, 2011 and 2010.

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, 2009	206,120		$	18.53
Granted	70,110		24.57
Released	(101,420	)	19.27
Forfeited	(8,940	)	18.49
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 and $2 million for the years ended December 31, 2011 and 2010, respectively.

The Company settled the restricted stock liability units released in 2011 and 2010 with cash payments of $4 million and $2 million, respectively.

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ETE Merger and Holdco Transaction (Tables)

12 Months Ended

Dec. 31, 2012

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 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.

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended					12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2012 Other ARO Assets	Dec. 31, 2010 Offshore
ARO Underlying Asset					$ 1
Asset Retirement Obligation, Liabilities Incurred			8	34		29
Asset Retirement Obligation, Revision of Estimate						11
Asset Retirement Obligation, Liabilities Settled	$ 17	$ 20

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Top Customers (Details)	9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended		9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor	Dec. 31, 2012 BG LNG Services Successor	Mar. 25, 2012 BG LNG Services Predecessor	Dec. 31, 2011 BG LNG Services Predecessor	Dec. 31, 2010 BG LNG Services Predecessor	Dec. 31, 2012 ProLiance Successor	Mar. 25, 2012 ProLiance Predecessor	Dec. 31, 2011 ProLiance Predecessor	Dec. 31, 2010 ProLiance Predecessor	Dec. 31, 2012 Other Top 10 Customers Successor	Mar. 25, 2012 Other Top 10 Customers Predecessor	Dec. 31, 2011 Other Top 10 Customers Predecessor	Dec. 31, 2010 Other Top 10 Customers Predecessor	Dec. 31, 2012 Remaining Customers Successor	Mar. 25, 2012 Remaining Customers Predecessor	Dec. 31, 2011 Remaining Customers Predecessor	Dec. 31, 2010 Remaining Customers Predecessor
Entity-Wide Revenue, Major Customer, Percentage	100.00%	100.00%	100.00%	100.00%	31.00%	30.00%	30.00%	29.00%	12.00%	13.00%	13.00%	13.00%	20.00%	24.00%	21.00%	23.00%	37.00%	33.00%	36.00%	35.00%

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Mar. 25, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2010 Predecessor
Statement of Income and Comprehensive Income [Line Items]
Net income	$ 88	$ 40	$ 168	$ 148
Other comprehensive income (loss), net of tax:
Reclassification of unrealized loss on interest rate hedges into earnings	0	3	13	13
Change in fair value of interest rate hedges	0	0	(1)	(8)
Actuarial loss relating to postretirement benefits	(9)	0	(10)	(1)
Reclassification of prior service credit relating to other postretirement benefits into earnings	0	0	(1)	(1)
Total other comprehensive income, net of tax	(9)	3	1	3
Comprehensive income	$ 79	$ 43	$ 169	$ 151

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ETE Merger and Holdco Transaction

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

ETE Merger and ETP Merger

ETE MERGER AND HOLDCO TRANSACTION:

Description of Merger

On March 26, 2012, Southern Union, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among Southern Union, ETE and Merger Sub, Merger Sub was merged with and into Southern Union, with Southern Union continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, LLC, an indirect wholly-owned subsidiary of Southern Union (CrossCountry Energy), ETP, Citrus ETP Acquisition, L.L.C. (ETP Merger Sub), Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of Southern Union (PEPL Holdings), and Southern Union consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and Southern Union, on the other hand.

Immediately prior to the Effective Time, Southern Union, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder to, and Southern Union assumed the obligations and rights of ETE thereunder.  Southern Union made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus Corp. (Citrus).  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) Southern Union contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, Southern Union entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which Southern Union agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to Southern Union) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

Expenses Related to the Merger

Merger-related expenses of $48 million include charges related to employment agreements with certain executives that provide 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.  See Note 9 for more information on the curtailment.

Allocation of Consideration Transferred

The 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 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.

Holdco Transaction

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity in exchange for a 60% equity interest in the new entity, Holdco, and (ii) 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 will control Holdco. This transaction did not result in a new basis of accounting for Southern Union or Panhandle.

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BENEFITS Benefits - Obligations and Funded Status (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		9 Months Ended		3 Months Ended		12 Months Ended
	Dec. 31, 2012	Mar. 25, 2012	Dec. 31, 2012 Pension Plans, Defined Benefit Successor		Mar. 25, 2012 Pension Plans, Defined Benefit Predecessor		Dec. 31, 2011 Pension Plans, Defined Benefit Predecessor
Benefit obligation at beginning of period		$ 243	$ 93		$ 88		$ 69
Service cost			0		1		3
Interest cost			1		1		4
Amendments			16		0		0
Actuarial loss and other			4		3		13
Benefits paid, net			(1)		0		(1)
Curtailments	11		(75)		0		0
Benefit obligation at end of period		243	38		93		88
Fair value of plan assets at beginning of period	75	155	82		75		68
Return on plan assets and other			3		5		0
Employer contributions			6		2		8
Fair value of plan assets at end of period	90	155	90		82		75
Amount (overfunded) underfunded at end of period (1)			(52)	[1]	11	[1]	13	[1]
Net actuarial loss			(1)		0		23
Prior service cost			16		0		1
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:			$ 15		$ 0		$ 24

[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.

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SHARE-BASED COMPENSATION Stock-Based Compensation - Restricted Liability Units (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock Units Oustanding	165,870	206,120
Restricted Stock Units Outstanding Weighted Average Grant Date Fair Value	$ 20.68	$ 18.53
Restricted Stock Units Granted	51,611	70,110
Restricted Stock Units Granted Weighted Average Grant Date Fair Value	$ 42.08	$ 24.57
Restricted Stock Units Released	(87,509)	(101,420)
Restricted Stock Units Released Weighted Average Grant Date Fair Value	$ 18.47	$ 19.27
Restricted Stock Units Forfeited	(4,918)	(8,940)
Restricted Stock Units Forfeited Weighted Average Grant Date Fair Value	$ 18.97	$ 18.49
Restricted Stock Units Oustanding	125,054	165,870
Restricted Stock Units Outstanding Weighted Average Grant Date Fair Value	$ 31.15	$ 20.68

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TAXES ON INCOME Taxes on Income - Deferred Tax Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor
Other postretirement benefits	$ 52	$ 13
Derivative financial instruments (interest rates)	13	4
Other	18	20
Total deferred income tax assets	83	37
Property, plant and equipment	(925)	(559)
Other	(2)	(7)
Total deferred income tax liabilities	(927)	(566)
Net deferred income tax liability	(844)	(529)
Less current income tax assets	9	9
Accumulated deferred income taxes	$ (853)	$ (538)

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions [table text block]

The following tables provide a summary of related party transactions for the periods presented:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Transportation and storage of natural gas (1)	$	7	$	1	$	3	$	3
Operation and maintenance and general-affiliate:
Management and royalty fees	5		5		20		19
Corporate services - Southern Union	47		9		32		31
Other expenses (2)	9		—		6		5
Other income, net:
Interest income — Southern Union and subsidiaries	2		2		9		9

⁽¹⁾  Represents transportation and storage revenues with ETC, a subsidiary of ETP (in the successor period) and MGE, a Southern Union division.

⁽²⁾  Represents primarily insurance costs and corporate charges for merger-related employee expenses from ETE offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

Related Party Balances For Period Presented [Table Text Block]

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

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Notes receivable from related party — Southern Union and subsidiaries:
Current	$	—	$	342
Non-current	831		688
	$	831	$	1,030
Accounts receivable from related companies (1)	$	14	$	6
Accounts payable to related companies:
Southern Union — income taxes (2)	$	—	$	33
Southern Union — other (3)	26		19
Other (4)	1		—
	$	27	$	52

(1) Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP, Citrus, MGE and other affiliates. The December 31, 2011 balance also included interest income associated with a note receivable from an affiliate, which was repaid on March 26, 2012.

(2) Accounts payable from related companies reflected above related to income taxes payable to Southern Union per the tax sharing agreement to provide for taxes to be remitted upon the filing of the tax return.

(3) Accounts payable from related companies reflected above primarily related to payroll funding including merger-related expenses, provided by Southern Union.  The December 31, 2011 amount was net of insurance proceeds of $2 million owed by Southern Union to the Company.

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

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FAIR VALUE MEASUREMENT Narrative (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Fair Value Disclosures [Abstract]
Interest Rate Derivative Liabilities, at Fair Value	$ 4

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Description of the Business (Details)	12 Months Ended
	Dec. 31, 2012
General partnership
Description of the Business
General partnership interest	1.00%
Limited partnership
Description of the Business
Limited partnership interest	99.00%

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2012

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 at the dates indicated:

		Successor			Predecessor
	Lives in Years	December 31, 2012			December 31, 2011
Transmission	5 – 46	$	2,580		$	2,321
Gathering	26	114			108
Underground storage	5 – 46	306			322
General plant - LNG	5 – 40	966			1,119
General plant - other	3 – 40	110			176
Plant in service		4,076			4,046
Construction work in progress		45			42
Total property, plant and equipment		4,121			4,088
Accumulated depreciation and amortization		(57		)	(733		)
Net property, plant and equipment		$	4,064		$	3,355

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 years ended December 31, 2011 and 2010 was $7 million and $7 million, respectively.

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 years ended December 31, 2011 and 2010 was $2 million and $2 million, respectively.