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PEPL_2013_10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2013



¨	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.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 x No ¨

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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

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		Page
PART I
ITEM 1.	BUSINESS	1
ITEM 1A.	RISK FACTORS	4
ITEM 1B.	UNRESOLVED STAFF COMMENTS	16
ITEM 2.	PROPERTIES	16
ITEM 3.	LEGAL PROCEEDINGS	16
ITEM 4.	MINE SAFETY DISCLOSURES	16
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	17
ITEM 6.	SELECTED FINANCIAL DATA	17
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	22
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	22
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	22
ITEM 9A.	CONTROLS AND PROCEDURES	22
ITEM 9B.	OTHER INFORMATION	23
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	23
ITEM 11.	EXECUTIVE COMPENSATION	23
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	23
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	23
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	23
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	24
	SIGNATURES	25

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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

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

Holdco		ETP Holdco Corporation, the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union and Sunoco

LIBOR		London Interbank Offered Rate

LNG		Liquefied Natural Gas

LNG Holdings		Trunkline LNG Holdings, LLC

MGE		Missouri Gas Energy

MMBtu		Million British thermal units

NGL		Natural gas liquids

OPEB plans		Other postretirement employee benefit plans

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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

Regency		Regency Energy Partners LP, a subsidiary of ETE

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

iii

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PART I

ITEM 1. BUSINESS

OUR BUSINESS

Introduction

Panhandle, a Delaware limited partnership, is an indirect wholly-owned subsidiary of ETP. References to “we,” “us,” “our”, the “Company” and “Panhandle” shall mean Panhandle Eastern Pipe Line Company, LP and its subsidiaries. The Company is primarily engaged in the transportation and storage of natural gas and is subject to the rules and regulations of the FERC. Panhandle directly or indirectly owns all of the equity interests in Trunkline, Sea Robin and Southwest Gas, among other subsidiaries.

Until March 26, 2012, the Company had previously been an indirect wholly-owned subsidiary of Southern Union, which was a publicly traded corporation. Several recent transactions have impacted the ownership and/or control of the Company.

On March 26, 2012, ETE, the entity that owns the general partners of ETP and Regency, consummated a merger with Southern Union, whereby Southern Union became a wholly-owned subsidiary of ETE. In a related transaction on March 26, 2012, Southern Union contributed its interest in the Company and Southern Union Panhandle LLC (the Company’s general partner) to PEPL Holdings.

On October 5, 2012, immediately following ETP’s acquisition of Sunoco, ETE and ETP completed the Holdco Transaction, whereby, (i) ETE contributed its interest in Southern Union into Holdco in exchange for a 60% equity interest in 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 controlled Holdco subsequent to this transaction.

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco. As a result of this transaction, ETP now owns 100% of Holdco.


•	2.2 million ETP common units;


•	31.4 million Regency common units and 6.3 million Regency Class F Units;


•	Approximately $176 million of Southern Union third party long-term debt and $1.09 billion of notes payable to ETP; and


•	Guarantee of $600 million of Regency senior notes.

See Note 3 to our consolidated financial statements for information related to these transactions.

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 120 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 owned and operated an LNG terminal in Lake Charles, Louisiana.

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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 88% of total revenues in 2013.

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



	Successor		Predecessor
	Year Ended December 31, 2013	Period from Acquisition (March 26, 2012) to December 31, 2012	Period from January 1, 2012 to March 25, 2012	Year Ended December 31, 2011
PEPL transportation	613	430	152	564
Trunkline transportation	722	533	177	743
Sea Robin transportation	141	91	20	113

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



		December 31, 2013
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		2.3
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		4.2
Trunkline		8.3
Sea Robin ⁽²⁾		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts ⁽¹⁾
PEPL		7.9
Trunkline		5.0


⁽¹⁾	Weighted by firm capacity volumes.

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⁽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.

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 14 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 14 to our consolidated financial statements.

Employees

At January 31, 2014, the Company had 745 employees. Of these employees, 197 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.

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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, 2013, consolidated debt on the consolidated balance sheets totaled $1.02 billion outstanding, compared to total capitalization (long- and short-term debt plus partners’ capital) of $4.58 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.

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.

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The Company’s credit rating can be impacted by the credit rating and activities of its parent company. Thus, adverse impacts to ETP 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 depends on distributions from its subsidiaries to meet its needs.

The Company is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, its subsidiaries to generate the funds necessary to meet its obligations. The availability of distributions from such entities is subject to their earnings and capital requirements, the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and in the case of the regulated subsidiaries, regulatory restrictions that limit their ability to distribute profits to the Company.

The Company is controlled by ETP.

The Company is an indirect wholly-owned subsidiary of ETP. ETP executives serve as the board of managers and as executive officers of the Company. Accordingly, ETP 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, on the one hand, and the Company’s creditors, on the other hand, the Company can give no assurance that ETP would not exercise its power to control the Company in a manner that would benefit ETP 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 creditors’ 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’s growth strategy entails risk.

The Company may actively pursue acquisitions in the energy industry to complement and diversify its existing businesses. As part of its growth strategy, Panhandle may:


•	examine and potentially acquire regulated or unregulated businesses, including transportation and storage assets and gathering and processing businesses within the natural gas industry;


•	enter into joint venture agreements and/or other transactions with other industry participants or financial investors;


•	selectively divest parts of its business, including parts of its core operations; and


•	continue expanding its existing operations.

The Company’s ability to acquire new businesses will depend upon the extent to which opportunities become available, as well as, among other things:


•	its success in valuing and bidding for the opportunities;

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•	its ability to assess the risks of the opportunities;


•	its ability to obtain regulatory approvals on favorable terms; and


•	its access to financing on acceptable terms.

Once acquired, the Company’s ability to integrate a new business into its existing operations successfully will largely depend on the adequacy of implementation plans, including the ability to identify and retain employees to manage the acquired business, and the ability to achieve desired operating efficiencies. The successful integration of any businesses acquired in the future may entail numerous risks, including:


•	the risk of diverting management’s attention from day-to-day operations;


•	the risk that the acquired businesses will require substantial capital and financial investments;


•	the risk that the investments will fail to perform in accordance with expectations; and


•	the risk of substantial difficulties in the transition and integration process.

These factors could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows, particularly in the case of a larger acquisition or multiple acquisitions in a short period of time.

The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. In addition, acquisitions or expansions may result in the incurrence of additional debt.

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 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 aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.

The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and 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.

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Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Security breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

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;

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•	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 of 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 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.

Our interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.

We are required to file tariff rates (also known as recourse rates) with the FERC that shippers may pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariffs rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of our interstate pipeline operations may increase and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for, and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

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The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, we thus remain eligible to include an income tax allowance in the tariff rates we charge for interstate natural gas transportation. The effectiveness of the FERC’s policy and the application of that policy remain subject to future challenges, refinement or change by the FERC or the courts.

Our interstate pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate pipelines, including:


•	terms and conditions of service;


•	the types of services interstate pipelines may or must offer their customers;


•	construction of new facilities;


•	acquisition, extension or abandonment of services or facilities;


•	reporting and information posting requirements;


•	accounts and records; and


•	relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose to do so in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof in these and other applicable areas may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA and HLPSA, as amended by the PSI Act, the PIPES Act and the 2011 Pipeline Safety Act, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:


•	perform ongoing assessments of pipeline integrity;


•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;


•	improve data collection, integration and analysis;


•	repair and remediate the pipeline as necessary; and


•	implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For instance, changes to regulations governing the safety of gas transmission pipelines and gathering lines are being considered by PHMSA, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed.

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

The positions taken by the Company in its 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, 2013, our consolidated balance sheet reflected $1.10 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.

During the fourth quarter of 2013, we recorded a goodwill impairment charge of $689 million on our Trunkline LNG reporting unit. See Note 2 to our consolidated financial statements for additional information.

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 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

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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 and regulations 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 were phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements were 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 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

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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, 2014, approximately 197 of the Company’s 745 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 adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the services we provide.

In December 2009, the EPA published its findings 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 adopted rules under the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources, which reviews could require securing PSD permits at covered facilities emitting greenhouse gases and meeting “best available control technology” standards for those greenhouse gas emissions. In addition, the EPA has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States on an annual basis, which include certain of our operations. While Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs. The adoption of any legislation or regulations that requires reporting of greenhouse gases or otherwise restricts emissions of greenhouse gases from our equipment and operations could require us to incur significant added costs to reduce emissions of greenhouse gases or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate. Moreover, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products, which could adversely affect the services we provide.

More stringent regulatory initiatives in the U.S. Gulf of Mexico in the aftermath of the Macondo well oil spill may result in increased costs and delays in offshore oil and natural gas exploration and production operations, which costs and delays could significantly decrease the volume of our business and have a material adverse effect on our results of operations, financial position and liquidity.

In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third party in ultra-deep water in the U.S. Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the U.S. Department of the Interior, or DOI, and its implementing agencies that have since evolved into the present day Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement has issued various rules, Notices to Lessees and Operators and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration, development and production operators in the U.S. Gulf of Mexico. These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the U.S. Gulf of Mexico due to adjustments in operating procedures and certification practices, increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits and thus result in increased costs for affected operators, some of whom are our customers. The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by us. Furthermore, business decisions by operators not to drill in the areas serviced by us in the future owing to the more rigorous regulatory environmental or increased costs of operating also could result in a reduction in the future development and production of natural gas reserves in the vicinity of our facilities, which could adversely affect our business, financial condition results of operations and cash flows. Also, if similar events were to occur in the future in the U.S. Gulf of Mexico in areas where we conducts operations, the United States could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development, which developments could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.

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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.

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.

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

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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.

Historically, a small number of customers has accounted for a large portion of the Company’s 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.

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.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains 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;


•	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;

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•	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.

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 14 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 ETP, serves as the general partner of PEPL and owns a 1% general partnership interest in PEPL. ETP also indirectly owns a 99% limited partnership interest in PEPL. See Note 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.

References to “we,” “us,” “our”, the “Company” and “Panhandle” shall mean Panhandle Eastern Pipe Line Company, LP and its subsidiaries.

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 6.8 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.”

Recent Developments

Trunkline LNG

On February 19, 2014, ETE and ETP completed the transfer to ETE of Trunkline LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, from ETP in exchange for the redemption by ETP of 18.7 million ETP common units held by ETE. The transaction was effective as of January 1, 2014.

Panhandle Merger

On January 10, 2014, the Company consummated a merger with Southern Union, a Delaware corporation and the indirect parent of the Company, and PEPL Holdings, a Delaware limited liability company and the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations, which comprised $83 million in aggregate principal amount of 7.6% Senior Notes due 2024, $33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have operations of its own, other than its ownership of the Company and noncontrolling interest in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units) and ETP (2.2 million common units). In connection with the Panhandle Merger, the Company also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

This transaction was a combination of entities under common control; therefore, the consolidated financial statements of the Company will be retrospectively adjusted to consolidate Southern Union for all periods, beginning when the Company issues financial statements that include the period when the transaction occurred. During 2012 and 2013, Southern Union had natural gas gathering, processing and local distribution operations conducted through Southern Union Gas Services, Missouri Gas Energy and New England Gas Company, all of which were deconsolidated by Southern Union during 2013. Upon retrospectively adjusting our 2012 and 2013 historical financial statements when presented for comparative purposes in the future, the Company’s consolidated financial statements will include these historical operations of Southern Union for prior periods through the dates when such operations were deconsolidated by Southern Union.

Results of Operations

The ETE 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.

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 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 ETE 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.

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The following table illustrates the results of operations of the Company:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012
OPERATING REVENUES:
Transportation and storage of natural gas	$	575		$	417		$	140
LNG terminalling	216			166			51
Other	10			9			3
Total operating revenues ⁽¹⁾	801			592			194
OPERATING EXPENSES:
Operating, maintenance and general	281			262			76
Depreciation and amortization	164			125			30
Goodwill impairment	689			—			—
Total operating expenses	1,134			387			106
OPERATING INCOME (LOSS)	(333		)	205			88
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(50		)	(43		)	(25		)
Interest income - affiliates	2			2			2
Total other expenses, net	(48		)	(41		)	(23		)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	(381		)	164			65
Income tax expense	118			76			25
NET INCOME (LOSS)	$	(499	)	$	88		$	40
Panhandle natural gas volumes transported (TBtu): ⁽²⁾
PEPL	613			430			152
Trunkline	722			533			177
Sea Robin	141			91			20


⁽¹⁾	Reservation revenues comprised 88% of total operating revenues for the year ended December 31, 2013. Reservation revenues comprised 87% and 88% of total operating revenues in the successor and predecessor periods in 2012, respectively.


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

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 for the year ended December 31, 2013 increased compared to the successor and predecessor periods in 2012 primarily due to the recognition of $52 million received in connection with the buyout of a customer’s contract, partially offset by lower capacity sold at overall average lower rates and lower parking revenues.

•

Operating Expenses. The period from March 26, 2012 to December 31, 2012 included merger-related employee severance expenses of $48 million, offset by a curtailment gain on our OPEB plans of $11 million. The remaining decrease in operating expenses for the year ended December 31, 2013 compared to the prior periods is attributable to a decrease in employee-related costs related to integration efforts subsequent to ETE’s acquisition of Southern Union. The successor periods also reflected higher depreciation due to the step-up in depreciable assets in connection with the ETE Merger and lower corporate allocations due to merger-related synergies.

•

Goodwill Impairment. During the year ended December 31, 2013 the company recorded a $689 million goodwill impairment of a subsidiary, Trunkline LNG. The decline in the estimated fair value was primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Trunkline LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our

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assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of our Trunkline LNG reporting unit was less than its carrying amount.


•	Interest Expense. Interest expense decreased in the successor periods primarily due to amortization of the long-term debt fair value adjustment recorded in connection with the ETE Merger as well as the termination of interest rate swaps.

•

Income Taxes. Income tax expense approximated the federal statutory rate, plus state income taxes, for all periods, except that the year ended December 31, 2013 also reflected the impact of a $689 million non-deductible goodwill impairment and the period from March 26, 2012 reflected the impact of $11 million in non-deductible executive compensation expenses included in the merger-related expenses for 2012.

For information regarding expenses related to the ETE 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	262			76			(37		)	(a)	301
Depreciation and amortization	125			30			8			(b)	163
Total operating expenses	387			106			(29		)		464
OPERATING INCOME	205			88			29				322
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(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


(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.

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(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.

OTHER MATTERS

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 14 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, 2013:



	Contractual Obligations
	Total		2014		2015		2016		2017		2018		2019 and thereafter
Operating leases ⁽¹⁾	$	45	$	9	$	9	$	9	$	9	$	4	$	5
Total long-term debt ^{(2) (3) (4)}	2,182		—		—		—		300		400		1,482
Interest payments on debt ^{(4) (5)}	554		75		75		75		75		42		212
Firm capacity payments ⁽⁶⁾	122		33		27		22		21		16		3
OPEB funding ⁽⁷⁾	48		8		8		8		8		8		8
Total ⁽⁸⁾	$	2,951	$	125	$	119	$	114	$	413	$	470	$	1,710


⁽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, 2013, the Company was in compliance with all of its covenants. See Note 7 to our consolidated financial statements.


⁽³⁾	The long-term debt cash obligations exclude $107 million of unamortized fair value adjustments as of December 31, 2013.


⁽⁴⁾	Following the merger of Southern Union, PEPL Holdings and Panhandle on January 10, 2014, Panhandle assumed Southern Union’s remaining debt obligations. See Note 7 to our consolidated financial statements.


⁽⁵⁾	Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2013.


⁽⁶⁾	Charges for third party storage capacity.


⁽⁷⁾	Panhandle is committed to the funding levels of $8 million per year until modified by future rate proceedings, the timing of which is uncertain.


⁽⁸⁾	Excludes non-current deferred tax liability of $911 million due to uncertainty of the timing of future cash flows for such liabilities.

Contingencies

See Note 14 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.

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Regulatory

See Note 14 to our consolidated financial statements.

Rate Matters

Sea Robin Rate Case. On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin seeks to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. The outcome of the filing will be determined by a regulatory process that includes a hearing currently scheduled for the fourth quarter of 2014, with a Commission order expected in 2015.

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, 2013, the interest rate on 100% of the Company’s long-term debt was fixed with no outstanding interest rate swaps.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2013 is not material to the Company.

See Note 7 and Note 10 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, 2013, 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 financial statements starting on page F-1 of this report are incorporated by reference.

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, 2013.

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, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 1992 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO framework”).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.

ITEM 9B. OTHER INFORMATION

None.

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



	Years Ended December 31,
	2013		2012
Audit fees ⁽¹⁾	$	834,250	$	456,250
Total Fees	$	834,250	$	456,250

⁽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.

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.

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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.

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: February 27, 2014	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	February 27, 2014

(ii)	Principal financial officer: /s/ Martin Salinas, Jr. Martin Salinas, Jr.	Chief Financial Officer	February 27, 2014

(iii)	The Board of Directors of SUG Holding Company, Sole Member of Southern Union Panhandle, LLC, General Partner of Panhandle Eastern Pipe Line Company, L.P

	Signature	Title	Date
	/s/ Kelcy L. Warren Kelcy L. Warren	Chief Executive Officer and Director, SUG Holding Company	February 27, 2014

	/s/ John W. McReynolds John W. McReynolds	Director, SUG Holding Company	February 27, 2014

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INDEX TO EXHIBITS




	Exhibit Number	Description

(*)	3(a)	Certificate of Formation of Panhandle Eastern Pipe Line Company, LP. (Filed as Exhibit 3.A to Panhandle’s Form 10-K for the year ended December 31, 2004.)

(*)	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 Panhandles’s Form 10-K for the year ended December 31, 2004.)

(*)	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 Panhandle’s Form 10-Q for the quarter ended March 31, 1999.)

(*)	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 Panhandle’s Form 10-Q for the quarter ended March 31, 1999.)

(*)	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 Panhandle’s Form S-4 (File No. 333-39850) filed on June 22, 2000.)

(*)	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 Panhandle’s Form 10-Q for the quarter ended September 30, 2003.)

(*)	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 Panhandle’s Form 10-K for the year ended December 31, 2004.)

(*)	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 Form 8-K filed on October 29, 2007.)

(*)	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 Form 8-K filed on June 11, 2008.)

(*)	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 (Filed as Exhibit 10(a) to Panhandle’s Form 10-K for the year ended December 31, 2011)

(*)	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 Form 8-K filed on May 28, 2009.)

(*)	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 Form 8-K filed on July 6, 2007.)

(*)	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 Panhandle’s Form 10-Q for the quarter ended June 30, 2008.)

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	Exhibit Number	Description
(*)	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 Panhandle’s Form 10-Q for the quarter ended June 30, 2008.)

	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



*	Indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
**	Furnished herewith.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Panhandle Eastern Pipe Line Company, LP and Subsidiaries



Financial Statements and Supplementary Data:	Page:
Report of Independent Registered Public Accounting Firm	F - 2
Report of Independent Registered Public Accounting Firm	F - 3
Consolidated Balance Sheets - December 31, 2013 and 2012	F - 4
Consolidated Statements of Operations - Year Ended December 31, 2013, the Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Year Ended December 31, 2011	F - 7
Consolidated Statements of Comprehensive Income (Loss) - Year Ended December 31, 2013, the Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Year Ended December 31, 2011	F - 8
Consolidated Statement of Partners’ Capital - Year Ended December 31, 2013, the Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Year Ended December 31, 2011	F - 9
Consolidated Statements of Cash Flows - Year Ended December 31, 2013, the Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Year Ended December 31, 2011	F - 10
Notes to Consolidated Financial Statements	F - 11

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers of

Panhandle Eastern Pipe Line Company, LP

We have audited the accompanying consolidated balance sheets of Panhandle Eastern Pipe Line Company, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for the year ended December 31, 2013, 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 audits.

We conducted our audits 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. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits 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 audits 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 subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the year ended December 31, 2013, 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

February 27, 2014

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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 statements of operations, of comprehensive income (loss), of partners’ capital and of cash flows for the year ended December 31, 2011 present fairly, in all material respects, the results of operations and cash flows of Panhandle Eastern Pipe Line Company, LP and its subsidiaries for the year 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 audit. We conducted our audit 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 audit provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2012

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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.

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.”

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Accounts receivable, net	$	63		$	74
Accounts receivable from related companies	4			14
Exchanges receivable	19			10
System natural gas and operating supplies	203			144
Other	22			20
Total current assets	311			262
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	4,138			4,076
Construction work in progress	69			45
	4,207			4,121
Accumulated depreciation and amortization	(211		)	(57		)
Net property, plant and equipment	3,996			4,064
GOODWILL	1,096			1,785
NOTE RECEIVABLE FROM RELATED PARTY	532			831
OTHER NON-CURRENT ASSETS, net	137			108
Total assets	$	6,072		$	7,050

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2013		2012
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Current portion of long-term debt	$	—	$	258
Accounts payable	6		12
Accounts payable to related companies	14		27
Exchanges payable	207		130
Accrued taxes	9		13
Accrued interest	7		13
Customer advances and deposits	17		4
Other	41		65
Total current liabilities	301		522
LONG-TERM DEBT, less current portion	1,023		1,499
DEFERRED INCOME TAXES	911		853
OTHER NON-CURRENT LIABILITIES	283		135
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS’ CAPITAL:
Partners’ capital	3,551		4,050
Accumulated other comprehensive income (loss)	3		(9		)
Total partners’ capital	3,554		4,041
Total liabilities and partners’ capital	$	6,072	$	7,050

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
OPERATING REVENUES:
Transportation and storage of natural gas	$	575		$	417		$	140		$	574
LNG terminalling	216			166			51			220
Other	10			9			3			10
Total operating revenues	801			592			194			804
OPERATING EXPENSES:
Operating, maintenance and general	281			262			76			314
Depreciation and amortization	164			125			30			128
Goodwill impairment	689			—			—			—
Total operating expenses	1,134			387			106			442
OPERATING INCOME (LOSS)	(333		)	205			88			362
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(50		)	(43		)	(25		)	(108		)
Interest income - affiliates	2			2			2			9
Total other expenses, net	(48		)	(41		)	(23		)	(99		)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	(381		)	164			65			263
Income tax expense	118			76			25			95
NET INCOME (LOSS)	$	(499	)	$	88		$	40		$	168

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Year Ended December 31, 2011
Net income (loss)	$	(499	)	$	88		$	40	$	168
Other comprehensive income (loss), net of tax:
Reclassification of unrealized loss on interest rate hedges into earnings	—			—			3		13
Change in fair value of interest rate hedges	—			—			—		(1		)
Actuarial gain (loss) relating to postretirement benefits	12			(9		)	—		(10		)
Reclassification of prior service credit relating to other postretirement benefits into earnings	—			—			—		(1		)
	12			(9		)	3		1
Comprehensive income (loss)	$	(487	)	$	79		$	43	$	169

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Dollars in millions)



	Partners’ Capital			Accumulated Other Comprehensive Income (Loss)			Tax Sharing Note Receivable-Related Party			Total
Predecessor
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
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
Net loss	(499		)	—			—			(499		)
Other comprehensive income, net of tax	—			12			—			12
Balance, December 31, 2013	$	3,551		$	3		$	—		$	3,554

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(499	)	$	88		$	40		$	168
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	164			125			30			128
Goodwill impairment	689			—			—			—
Deferred income taxes	51			86			19			76
Amortization included in interest expense	(28		)	(24		)	—			—
Net gain on curtailment of OPEB plan benefits	—			(11		)	—			—
Changes in operating assets and liabilities, net of Merger impact	56			(77		)	23			(28		)
Net cash flows provided by operating activities	433			187			112			344
CASH FLOWS FROM INVESTING ACTIVITIES:
Net decrease (increase) in note receivable - related parties	299			(55		)	255			(207		)
Net increase (decrease) in income taxes payable - related parties	68			(43		)	5			(10		)
Additions to property, plant and equipment	(94		)	(90		)	(28		)	(111		)
Other	2			—			—			—
Net cash flows provided by (used in) investing activities	275			(188		)	232			(328		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			—			455			—
Repayment of debt	(705		)	—			(797		)	(18		)
Other	(3		)	1			(2		)	2
Net cash flows (used in) provided by financing activities	(708		)	1			(344		)	(16		)
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.

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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 ETP;


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


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


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


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

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

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


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

Principles of Consolidation. The consolidated financial statements include the accounts of all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.

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

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

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

Cash and Cash Equivalents. Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. Total cash balances at December 31, 2013, 2012 and 2011 were each less than $1 million, respectively.

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



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

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

The following table presents the components of inventory:



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


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

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

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

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Property, Plant and Equipment.

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

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

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

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

For additional information, see Note 12.

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

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

During the fourth quarter of 2013, we performed a goodwill impairment test on our Trunkline LNG reporting unit. In accordance with GAAP, we performed step one of the goodwill impairment test and determined that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Trunkline LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Trunkline LNG reporting unit was less than its carrying amount. We then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, we estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, we recorded a goodwill impairment of $689 million during the fourth quarter of 2013.

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

PEPL and certain of its subsidiaries are not treated as separate taxpayers for federal and certain state income tax purposes. Instead, the Company’s income is taxable to Southern Union. The Company has entered into a tax sharing agreement

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with Southern Union pursuant to which the Company will be required to make payments to Southern Union in order to reimburse Southern Union for federal and state taxes that it pays on the Company’s income, or to receive payments from Southern Union to the extent that tax losses generated by the Company are utilized by Southern Union. In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by Southern Union. The Company’s liability generally is equal to the liability that the Company and its subsidiaries would have incurred based upon the Company’s taxable income if the Company was a taxpayer filing separately from Southern Union, except that the Company will receive credit under an intercompany note for any increased liability resulting from its tax basis in its assets having been reduced as a result of the like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended. The tax sharing agreement may be amended from time to time.

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

Revenues. The Company’s revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered for the customer, based on the tariff of that particular Panhandle entity, with any differences in volumes received and delivered resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.

Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards. Customers that do not meet minimum standards are required to provide additional credit support. The Company considers many factors including historical customer collection experience, general and specific economic trends and know specific issues related to individual customers and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.

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



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

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



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

Retirement Benefits. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in other comprehensive income in partners’ capital in the year in which the change occurs. See Note 8 for additional related information.

Derivatives and Hedging Activities. All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in accumulated other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use. See Note 10 for information related to derivative instruments and hedging activities.

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

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


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

•

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

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•

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

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

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

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

See Note 5 for additional related information.

Income Taxes. Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

As a limited partnership, the Company is treated as a disregarded entity for federal income tax purposes. Accordingly, the Company and its subsidiaries are not treated as separate taxpayers; instead, their income is directly taxable to Southern Union. Upon completion of the Holdco transaction on October 5, 2012, Southern Union became a member of a new federal consolidated tax return filing group of which Holdco is the parent company. As a result of the Holdco transaction, Southern Union entered into a tax sharing agreement with Holdco. However, the Company will continue its tax sharing agreement with Southern Union, and will pay its share of taxes based on its taxable income, which will generally equal the liability that the Company would have incurred as a separate taxpayer.


3.	MERGERS, DECONSOLIDATIONS, AND RELATED TRANSACTIONS:

2014 Transactions

Panhandle Merger

On January 10, 2014, the Company consummated a merger with Southern Union, the indirect parent of the Company, and PEPL Holdings, the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and Floating Rate Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have operations of its own, other than its ownership of the Company and noncontrolling

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interest in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units) and ETP (2.2 million common units). In connection with the Panhandle Merger, the Company also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Trunkline LNG Transaction

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

2013 Transaction

ETP’s Acquisition of ETE’s Holdco Interest

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

2012 Transactions

ETE Merger

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

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

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

Holdco Transaction

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

Allocation of Consideration Transferred

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

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


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

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

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


4.	RELATED PARTY TRANSACTIONS:

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



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

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

Cash advances from affiliate	$	120	$	—

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


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


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


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

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



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


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


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

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


5.	ASSET RETIREMENT OBLIGATIONS:

The Company’s recorded asset retirement obligations are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, the Company is legally or contractually required to abandon in place or remove the asset. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

Individual component assets have been and will continue to be replaced, but the pipeline system will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets may be replaced, the pipeline system itself will remain intact indefinitely.

The Company had recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. Amounts reflected in long-lived assets related to AROs aggregated approximately $13 million and $1 million and were reflected as non-current assets on our balance sheet as of December 31, 2013 and 2012, respectively.

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

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

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


6.	COMPREHENSIVE INCOME:

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



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

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



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

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7.	DEBT OBLIGATIONS:

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



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

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

Senior Notes

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

Term Loans

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

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

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

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



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

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, Panhandle assumed Southern Union’s long-term debt obligations. As of December 31, 2013, there was $83 million in aggregate principal amount of 7.6% Senior Notes due 2024,

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$33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066 outstanding. See Note 3.

Compliance With Our Covenants

The Company’s notes are subject to certain requirements, such as the maintenance of a fixed charge coverage ratio and a leverage ratio, which if not maintained, restrict the ability of the Company to make certain payments and impose limitations on the ability of the Company to subject its property to liens. Other covenants impose limitations on restricted payments, including dividends and loans to affiliates, and additional indebtedness. As of December 31, 2013, the Company is in compliance with these covenants.


8.	RETIREMENT BENEFITS:

Postretirement Benefit Plans

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

Obligations and Funded Status

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



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

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

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


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

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

⁽¹⁾

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

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

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

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



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

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets with proper consideration for diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.

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

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



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

Plan Assets. The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%. These target allocations are monitored by the Investment Committee of Southern Union’s Board of Directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.

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



	December 31,
	2013		2012
Cash and cash equivalents	$	2	$	2
Mutual fund ⁽¹⁾	101		88
Total	$	103	$	90

⁽¹⁾

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

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their fair values are based on active market quotes. See Note 2 for information related to the framework used by the Company to measure the fair value of its other postretirement plan assets.

Contributions. The Company expects to make $8 million contributions to its other postretirement plans in 2014 and approximately $8 million annually thereafter until modified by rate case proceedings.

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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. The Company does not expect to receive any Medicare Part D subsidies in any future periods.



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

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. The Company is eligible for such subsidies through December 31, 2013. As a result of changes the Company made to the retiree medical plan effective January 1, 2014, the Company will no longer receive such subsidy payments for coverage provided after December 31, 2013. Those subsidy payments are instead provided to the Company’s insurance carrier and will be reflected in the insurance charges for coverage for 2014 and beyond. These changes are reflected in the measurement of plan obligations as of December 31, 2013.

Defined Contribution Plan

The Company sponsors a defined contribution savings plan (“Savings Plan”) that is available to virtually all employees. The Company provided matching contributions of 100% of the first 5% of the participant’s compensation paid into the Savings Plan. Company contributions to the Savings Plan during the year ended December 31, 2013, the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the year ended December 31, 2011 were $3 million, $3 million, $1 million and $5 million, respectively.

In addition, the Company provides a 3% profit sharing contribution to eligible employees with annual base compensation below a specific threshold. Company contributions are 100% vested after five years of continuous service. The Company’s fixed contributions during the year ended December 31, 2013, the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the year ended December 31, 2011 were $2 million, $2 million, $1 million and $6 million, respectively.

9.TAXES ON INCOME:

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



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

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



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

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



	December 31,
	2013			2012
Deferred income tax assets:
Other postretirement benefits	$	5		$	13
Debt amortization	43			52
Other	19			18
Total deferred income tax assets	67			83

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

As of December 31, 2013, the Company has $1 million ($1 million, net of federal tax) of unrecognized tax benefits, none of which would impact the Company’s effective income tax rate if recognized. The Company does not expect that its unrecognized tax benefits will be reduced within the next 12 months.

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

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


10.	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

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contracts may also be used from time to time. The Company recognizes all derivative assets and liabilities at fair value in the consolidated balance sheets.

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

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

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

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

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



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


11.	FAIR VALUE MEASUREMENT:

The fair value of the Trunkline LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Trunkline LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business’s ability to attain the projected cash flows.

The approximate fair value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.

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12.	PROPERTY, PLANT AND EQUIPMENT:

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



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

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

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


13.	STOCK-BASED COMPENSATION

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

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

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

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



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

Exercisable December 31, 2011	165,307		20.90

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



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

Exercisable December 31, 2011	423,815		19.61

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

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

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

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

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



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

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

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


14.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Trunkline Transfer Applications

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

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

FERC Audit

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

Sea Robin Rate Case

On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin seeks to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. The outcome of the filing will be determined by a regulatory process that includes a hearing currently scheduled for the fourth quarter of 2014, with a Commission order expected in 2015.

PEPL Holdings Guarantee of Collection

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

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and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

Environmental Matters

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

Environmental Remediation

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

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

Environmental Remediation Liabilities

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



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

Litigation and Other Claims

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

Liabilities for Litigation and Other Claims

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable. When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss

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in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made. As of December 31, 2013 and 2012, the Company recorded litigation and other claim-related accrued liabilities of $6 million and $6 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

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

Future Regulatory Compliance Commitments

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

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

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

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

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

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15.	QUARTERLY FINANCIAL DATA (UNAUDITED):

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



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

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

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PEPL_12.31.2013_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 year ended December 31, 2013, 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 and 2009. 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.



	Successor						Predecessor
	Year Ended December 31,			Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
	2013						Period from January 1, 2012 to March 25, 2012		2011			2010			2009
Fixed Charges:
Interest expense, net	$	78		$	67		$	25	$	106		$	102		$	83
Net amortization of debt discount, premium and issuance expense	(28		)	(24		)	—		2			1			1
Capitalized interest	1			1			—		1			7			26
Interest charges included in rental expense	3			3			1		4			4			4
Total fixed charges	$	54		$	47		$	26	$	113		$	114		$	114
Earnings:
Consolidated pre-tax income (loss) from continuing operations	$	(381	)	$	164		$	65	$	263		$	245		$	243
Distributed income of equity investees	—			—			—		1			—			—
Capitalized interest	(1		)	(1		)	—		(1		)	(7		)	(26		)
Total fixed charges (from above)	54			47			26		113			114			114
Earnings Available for Fixed Charges	$	(328	)	$	210		$	91	$	376		$	352		$	331

Ratio of earnings to fixed charges	(a)			4.5			3.5		3.3			3.1			2.9


^(a)	For the year ended December 31, 2013, fixed charges exceeded earnings by $382 million. In 2013, Panhandle Eastern Pipe Line Company, LP recognized a $689 million goodwill impairment charge associated with its Trunkline LNG reporting unit.

PEPL_12.31.2013_EX 31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kelcy L. Warren, certify that:


1.	I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”);


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 control 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: February 27, 2014



/s/ Kelcy L. Warren
Kelcy L. Warren
Chief Executive Officer

PEPL_12.31.2013_EX 31.2

Exhibit 31.2

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Martin Salinas, Jr., certify that:


1.	I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”);


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 control 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: February 27, 2014



/s/ Martin Salinas, Jr.
Martin Salinas, Jr.
Chief Financial Officer

PEPL_12.31.2013_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 annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2014



/s/ Kelcy L. Warren
Kelcy L. Warren
Chief Executive Officer

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Panhandle Eastern Pipe Line Company, LP.

PEPL_12.31.2013_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 annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Martin Salinas, Jr., Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2014



/s/ Martin Salinas, Jr.
Martin Salinas, Jr.
Chief Financial Officer

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Panhandle Eastern Pipe Line Company, LP.