PANHANDLE EASTERN PIPE LINE COMPANY, LP - FORM 10-K

Attached files

file	filename
EX-23.1 - CONSENT - PANHANDLE EASTERN PIPE LINE COMPANY, LP	consent23_1.htm
EX-12 - EXHIBIT 12 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhibit12.htm
EX-32.2 - EXHIBIT 32.2 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhibit32_2.htm
EX-32.1 - EXHIBIT 32.1 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhibit32_1.htm
EX-24 - POWER OF ATTORNEY - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhibit24.htm
EX-31.2 - EXHIBIT 31.2 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhbit31_2.htm
EX-31.1 - EXHIBIT 31.1 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	exhibit31_1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2010

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

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	(I.R.S. Employer
incorporation or organization)	Identification No.)


5444 Westheimer Road	77056-5306
Houston, Texas	(Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (713) 989-7000

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each Class		Name of each exchange in which registered
6.05% Senior Notes due 2013, Series B		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes £ No R

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 R

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 R 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 £ 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 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. R

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. (Check one):

Large accelerated filer £ Accelerated filer £ Non-accelerated filer R Smaller reporting company £

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

Yes £ No R

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 4, 6, 10, 11, 12 and 13 have been omitted in accordance with Instruction I.

==========================================================================================================

PANHANDLE EASTERN PIPE LINE COMPANY, LP

FORM 10-K

DECEMBER 31, 2010

Table of Contents

		Page
Glossary.	PART I	1
ITEM 1.	Business.	2
ITEM 1A.	Risk Factors.	5
ITEM 1B.	Unresolved Staff Comments.	15
ITEM 2.	Properties.	15
ITEM 3.	Legal Proceedings.	15
ITEM 4.	Reserved.	15
	PART II
ITEM 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	15
ITEM 6.	Selected Financial Data.	16
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	16
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	23
ITEM 8.	Financial Statements and Supplementary Data.	24
ITEM 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	24
ITEM 9A. .	Controls and Procedures.	24
ITEM 9B.	Other Information.	25
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance.	25
ITEM 11.	Executive Compensation.	25
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	25
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	26
ITEM 14.	Principal Accounting Fees and Services.	26
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.	26
Signatures.		29
Index to the Consolidated Financial Statements.		F-1

GLOSSARY

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

ARO Asset retirement obligation

Bcf Billion cubic feet

Bcf/d Billion cubic feet per day

CCE Holdings CCE Holdings, LLC

CFO Chief Financial Officer

CIAC Contribution in aid of construction

Code Internal Revenue Code of 1986, as amended

Company PEPL and its subsidiaries

COO Chief Operating Officer

CrossCountry Citrus CrossCountry Citrus, LLC

EITR Effective income tax rate

Energy Transfer Energy Transfer Partners, LP

EPA United States Environmental Protection Agency

Exchange Act Securities Exchange Act of 1934, as amended

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

Florida Gas Florida Gas Transmission Company, LLC

FSP FASB Staff Position

GAAP Accounting principles generally accepted in the United States of America

HAPs Hazardous air pollutants

HCAs High consequence areas

IEPA Illinois Environmental Protection Agency

IPCB Illinois Pollution Control Board

KDHE Kansas Department of Health and Environment

LNG Liquefied Natural Gas

LNG Holdings Trunkline LNG Holdings, LLC

MACT Maximum achievable control technology

MMcf/d Million cubic feet per day

Panhandle PEPL and its subsidiaries

PCBs Polychlorinate biphenyls

PEPL Panhandle Eastern Pipe Line Company, LP

PRPs Potentially responsible parties

SARs Stock appreciation rights

Sea Robin Sea Robin Pipeline Company, LLC

SEC U.S. Securities and Exchange Commission

Southern Union Southern Union Company and its subsidiaries

Southwest Gas Storage Pan Gas Storage, LLC (d.b.a. Southwest Gas)

SPCC Spill Prevention Control and Countermeasure

TBtu Trillion British thermal units

TCEQ Texas Commission on Environmental Quality

The Company PEPL and its subsidiaries

Trunkline Trunkline Gas Company, LLC

Trunkline LNG Trunkline LNG Company, LLC

PART I

ITEM 1. Business.

Our Business

Introduction. Panhandle, a Delaware limited partnership, is an indirect wholly-owned subsidiary of Southern Union Company. The Company is subject to the rules and regulations of the FERC. The Company’s entities include the following:

·	PEPL, an indirect wholly-owned subsidiary of Southern Union Company;

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

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

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

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

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

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

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 and net earnings 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 percent of total revenues in 2010.

The following table provides a summary of pipeline transportation (including deliveries made throughout the Company’s pipeline network) and LNG terminal usage volumes (in TBtu).

	Years Ended December 31,
	2010		2009		2008

PEPL transportation		563		676		702
Trunkline transportation		664		683		643
Sea Robin transportation		172		132		126
Trunkline LNG terminal usage		43		33		9

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



		December 31, 2010

Approximate Miles of Pipelines
	PEPL	6,200
	Trunkline	3,600
	Sea Robin	400
Peak Day Delivery Capacity (Bcf/d)
	PEPL	2.8
	Trunkline	1.7
	Sea Robin	1.0
	Trunkline LNG	2.1
Trunkline LNG Sustainable Send Out Capacity (Bcf/d)		1.8
Underground Storage Capacity-Owned (Bcf)		68.1
Underground Storage Capacity-Leased (Bcf)		32.3
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
	PEPL	6.8
	Trunkline	9.6
	Sea Robin (1)	N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts
	PEPL	10.1
	Trunkline	2.6

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

Recent System Enhancements

LNG Terminal Enhancement. Trunkline LNG commenced construction of an enhancement at its LNG terminal in February 2007. The key components of the enhancement were an ambient air vaporizer system and NGL recovery units. On March 11, 2010, Trunkline LNG received approval from FERC to place the infrastructure enhancement construction project in service. Total construction costs were approximately $440 million plus capitalized interest. The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. In addition, Trunkline LNG and BG LNG Services have extended the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement construction project contract, which runs 20 years from the in-service date.

For additional information related to expansion projects of the Company, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

Significant Customers. The following table provides the percentage and related average contract lives of the Company’s significant customers for the period presented.


Customer	Percent of Revenues For Year Ended December 31, 2010			Weighted Average Life of Contracts at December 31, 2010

BG LNG Services		29	%	19.3 years (LNG, transportation)
ProLiance		13		10.9 years (transportation), 15.3 years (storage)
Other top 10 customers		23			N/A
Remaining customers		35			N/A
Total percentage		100	%

The Company’s customers are subject to change during the year as a result of capacity release provisions that allow customers to release all or part of their capacity, which generally occurs for a limited time period. Under the terms of the Company’s tariffs, a temporary capacity release does not relieve the original customer from its payment obligations if the replacement customer fails to pay.

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 following table summarizes the status of rate proceedings applicable to the Company.

	Date of Last
Company	Rate Filing	Rate Proceedings Status

PEPL	May 1992	Settlement effective April 1997
Trunkline	January 1996	Settlement effective May 2001
Sea Robin	June 2007	Settlement effective December 2008 (1)
Trunkline LNG	June 2001	Settlement effective January 2002 (2)
Southwest Gas Storage	August 2007	Settlement effective February 2008
____________________
(1) Settlement requires another rate case to be filed by January 2014.
(2) Settlement provides for a rate moratorium through 2015.

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 Item 8. Financial Statements and Supplementary Data, Note 3 – Regulatory Matters.

Competition

The interstate pipeline 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.

The Company’s current direct competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas Pipeline Company of America, ONEOK Partners, Texas Gas Transmission Corporation, Northern Natural Gas Company, Vector Pipeline, Columbia Gulf Transmission, Rockies Express Pipeline and Midwestern Gas Transmission. In addition, FERC may authorize the construction of new interstate pipelines that compete with the Company’s existing pipelines.

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 Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies.

Insurance

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

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

Employees

At December 31, 2010, the Company had 1,184 employees. Of these employees, 213 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, 2012.

Available Information

PEPL files annual, quarterly and special reports and other information with the SEC as required. Any document that PEPL files with the SEC may be read or copied at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. PEPL’s SEC filings are also available at the SEC’s website at http://www.sec.gov and through its parent Southern Union’s website at http://www.sug.com. The information on Southern Union’s website is not incorporated by reference into and is not made a 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.

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, 2010, consolidated debt on the Consolidated Balance Sheet totalled $1.98 billion outstanding, compared to total capitalization (long and short term debt plus partners’ capital) of $3.61 billion.

Some of the Company’s debt obligations contain financial covenants concerning debt-to-capital ratios and interest coverage ratios. The Company’s failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or render it unable to borrow under certain credit agreements. 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. A deterioration in the Company’s financial condition could hamper its ability to access the capital markets.

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

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

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

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

As of December 31, 2010, the Company’s debt were rated Baa3 by Moody's Investor Services, Inc., BBB- by Standard & Poor's and BBB- by Fitch Ratings. If the Company’s credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," the Company could be negatively impacted as follows:

·	borrowing costs associated with debt obligations could increase annually up to approximately $4.3 million; and

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

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

The Company is controlled by Southern Union.

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

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

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

The Company is subject to 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.

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 business.

The ability of Panhandle to operate in certain geographic areas will depend on its 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 Panhandle 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 all 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.

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 those 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.

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

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

The 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.

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

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 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.

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

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

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

The Company’s top two customers accounted for 42 percent of its 2010 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 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 the recent disruptions in the financial markets and other 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 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.

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.

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

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

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

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

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

·	adverse weather conditions;

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

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

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

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

·	the lack of transportation, storage and throughput commitments.

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

The Company is subject to risks associated with climate change.

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

A 2009 EPA determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase the Company’s costs of doing business and the costs of its services.

On April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other GHGs presented an endangerment to human health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin regulating GHG emissions under existing provisions of the Clean Air Act. In late September 2009, EPA announced two sets of proposed regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of GHGs from motor vehicles and the other to control emissions of GHGs from stationary sources. The motor vehicle rule was adopted in March 2010, and the stationary source permitting rule was promulgated in May 2010. It may take the EPA several years to impose regulations limiting emissions of GHGs from existing stationary sources due to legal challenges on the stationary rule. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including the Company’s processing plants and many compressor stations, beginning in 2011 for emissions occurring in 2010. Any limitation imposed by the EPA on GHG emissions from the Company’s natural gas–fired compressor stations and processing facilities or from the combustion of natural gas or natural gas liquids that it produces could increase its costs of doing business and/or increase the cost and reduce demand for its services.

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products and services the Company provides.

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol. However on June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (ACESA), which would establish an economy-wide cap-and-trade program in the United States to reduce emissions of GHGs, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would require an overall reduction in GHG emissions of 17 percent (from 2005 levels) by 2020, and by over 80 percent by 2050. Under ACESA, covered sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, natural gas and NGLs.

The United States Senate attempted to pass its own legislation for controlling and reducing emissions of GHGs in the United States. The Senate failed to adopt GHG legislation in the last Congress. It is not possible to predict if the current or a future Congress will propose or pass climate change legislation as robust as the 2009 ACESA. President Obama has indicated that he continues to support the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require the Company to incur increased costs. Further, current or future rate structures or shipper or producer contracts and prevailing market conditions might not allow the Company to recover the additional costs incurred to comply with such laws and/or regulations and may affect the Company’s ability to provide services. While the Company may be able to include some or all of such increased costs in its rate structures or shipper or producer contracts, such recovery of costs is uncertain and may depend on events beyond the Company’s control. Such matters could have a material adverse effect on demand for the Company’s transportation and storage services.

Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, with most of the state-level initiatives focused on large sources of GHG emissions, such as coal-fired electric plants. It is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

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

The United States Department of Interior (DOI) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the blowout and explosion on April 20, 2010 at the British Petroleum Plc deepwater well in the Gulf of Mexico. The offshore drilling moratorium, which was scheduled to expire on November 30, 2010, was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies. The moratorium was lifted in October 2010. Additionally, the United States Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the United States Mineral Management Service) has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection. Certain enhanced regulatory mandates have been enacted with additional regulatory mandates expected. The new regulatory requirements will increase the cost of offshore drilling and production operations. The increased regulation and cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company. Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States. Business decisions to not drill in the areas serviced by the Company resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

The Company’s businesses require the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement its business plans.

The Company’s businesses require the retention and recruitment of a skilled workforce including engineers and other technical personnel. If the Company is unable to retain its current employees (many of whom are retirement eligible) or recruit new employees of comparable knowledge and experience, the Company’s business could be negatively impacted.

The costs of providing other postretirement health care benefits and related funding requirements are subject to changes in other postretirement fund values, changing demographics 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 other postretirement healthcare benefits to certain of its employees. The costs of providing other postretirement health care benefits and related funding requirements are subject to changes in other postretirement fund values, changing demographics 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 other 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.

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 and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas available to the Company;

·	the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas 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 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;

·	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 and authorized rates of recovery of costs (including pipeline relocation costs);

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

N/A

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 Item 8, Financial Statements and Supplementary Data, Note 3 – Regulatory Matters and Note 14 – Commitments and Contingencies. Also see Item 1A. Risk Factors – Cautionary Factors That May Affect Future Results.

ITEM 4. Reserved.

Item 4, Reserved, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

PART II

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

All of the partnership interests in the Company are privately held by Southern Union Panhandle, LLC, a wholly-owned subsidiary of Southern Union Company. See Item 8. Financial Statements and Supplementary Data, Note 1 - Corporate Structure.

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 Operation.

Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying consolidated financial statements and notes to help provide an understanding of the Company’s financial condition, changes in financial condition and results of operations. The following section includes an overview of the Company’s business as well as recent developments that management of the Company believes are important in understanding its results of operations, and to anticipate future trends in those operations. Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters. The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The Notes to Consolidated Financial Statements contain information that is pertinent to the analysis of the Company’s financial condition and its results of operations, including a discussion of the Company’s significant accounting policies.

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 5.5 Bcf/d of natural gas. 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 periodically file (or can 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 these regulatory proceedings have the potential to negatively impact the Company’s results of operations and financial condition. For information related to the status of current rate filings, see Item 1. Business – Regulation.

Results of Operations

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

	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Operating revenue:
Transportation and storage of natural gas	$	561,354		$	607,366		$	582,942
LNG terminalling revenue		199,182			134,026			128,950
Other revenue		8,914			7,769			9,748
Total operating revenue		769,450			749,161			721,640

Operating expenses:
Operating, maintenance and general		271,257			284,608			276,174
Depreciation and amortization		123,009			113,648			103,807
Taxes, other than on income		36,063			34,537			32,059
Total operating expenses		430,329			432,793			412,040

Operating income		339,121			316,368			309,600

Other income (expense):
Interest expense		(103,458	)		(84,496	)		(89,057	)
Other, net		8,793			10,443			26,663
Total other expense, net		(94,665	)		(74,053	)		(62,394	)

Earnings before income taxes		244,456			242,315			247,206

Income taxes		96,801			92,100			96,532

Net earnings	$	147,655		$	150,215		$	150,674

Year ended December 31, 2010 versus the year ended December 31, 2009

Operating Revenue. For the year ended December 31, 2010, operating revenue increased $20.3 million versus the same time period in 2009 primarily as the result of:

·	Higher LNG revenues of $65.2 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010; and

·	Decreased transportation and storage revenue of $46 million primarily attributable to:

o	Lower interruptible parking revenues of $36.9 million primarily due to less favorable market conditions resulting in lower rates in 2010;

o	Lower transportation reservation revenues of $13.4 million in 2010 versus 2009 primarily due to lower short-term firm capacity sold and at lower rates on PEPL, in addition to lower average rates realized on Trunkline; and

o	Higher transportation commodity revenues of $2.5 million primarily due to higher volumes flowing on Sea Robin in 2010 versus 2009, the 2009 volumes having been adversely impacted by Hurricane Ike.

Operating Expenses. Operating expenses for the year ended December 31, 2010 decreased $2.5 million versus the same period in 2009 primarily as the result of:

·	Lower operating, maintenance and general expenses of $13.4 million in 2010 versus 2009 primarily attributable to:

Impact of provisions for repair and abandonment costs of $10.2 million recorded in 2009 for damages to offshore assets resulting from Hurricane Ike and a reduction in 2010 in the repair and abandonment expenses for Hurricane Ike of $12.2 million primarily due to insurance recoveries, project scope reductions, favorable weather conditions experienced, and realized project efficiencies;

o	Impact of a $3.8 million increase in environmental reserves in 2009 primarily attributable to estimated costs to remediate PCBs at the Company’s facilities;

o	A $3.6 million decrease in fuel tracker costs primarily due to a net over-recovery in 2010 versus a net under-recovery in 2009;

o	A $3.1 million decrease in contract storage costs primarily due to a contract termination in March 2010;

A $7.9 million increase in outside service costs for field operations primarily attributable to higher in-line inspection costs in 2010 due to testing to meet pipeline safety requirements and plant services related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o	Higher allocated corporate service costs of $6.7 million primarily due to higher short- and long-term corporate incentive compensation; and

o	A $6.4 million increase in expense due to the impact of a provision reversal in 2009 related to past take-or-pay settlement contractual indemnities for which performance by the Company has not been required; and

Increased depreciation and amortization expense of $9.4 million in 2010 versus 2009 due to a $598.6 million increase in property, plant and equipment placed in service after December 31, 2009, most significantly the LNG terminal infrastructure enhancement project placed in service in March 2010. Depreciation and amortization expense is expected to continue to increase primarily due ongoing capital additions.

Other Expense, Net. Other expense, net for the year ended December 31, 2010 increased $20.6 million versus the same period in 2009 primarily as a result of higher interest expense of $19 million principally attributable to lower capitalized interest resulting from the LNG terminal infrastructure enhancement construction project placed in service in March 2010 and the $150 million 8.125% Senior Notes issued in June 2009, partially offset by lower interest expense resulting from the repayment of the $60.6 million 6.50% Senior Notes in July 2009 and the repayment of the $40.5 million 8.25% Senior Notes in April 2010.

Income Taxes. The Company’s EITR was 40 percent and 38 percent for the year ended December 31, 2010 and 2009, respectively. Income taxes during the year ended December 31, 2010, versus the same period in 2009, increased $4.7 million primarily due to higher pretax earnings and the impact of $2.9 million of higher income tax expense resulting from the elimination of the Medicare Part D tax subsidy in the PPACA legislation signed into law in March 2010.

See Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional information related to repair and abandonment provisions and insurance recovery resulting from hurricane damage.

Liquidity and Capital Resources

Cash generated from operations constitutes the Company’s primary source of liquidity. The $96.4 million working capital deficit at December 31, 2010 is expected to be funded by cash flows from operations and from repayments from Southern Union of intercompany loans. Based on the Company’s current level of operations, management believes that cash flow from operations, available existing cash, and other sources, including liquid working capital and new borrowings, will be adequate to meet liquidity needs for the next several years, although no assurances can be given as to the sufficiency of cash flows or the ability to refinance existing obligations.

Operating Activities. Cash generated from operations constitutes the Company’s primary source of liquidity. Additional sources of liquidity include use of affiliate note receivables, project and bank financings, issuance of long-term debt and proceeds from asset dispositions.

Cash flows provided by operating activities were $300.8 million for the year ended December 31, 2010 compared with cash flows provided by operating activities of $409.1 million for the same period in 2009, resulting in a decrease in cash of $108.3 million in 2010 compared to 2009. Changes in operating assets and liabilities used cash of $21.7 million in 2010 and contributed cash of $28.8 million in 2009, resulting in a decrease of cash from changes in operating assets and liabilities of $50.5 million in 2010 compared to 2009.

Accelerated First-Year Tax Depreciation. As a result of recent federal income tax legislation, bonus depreciation is allowed for the cost of qualified property placed in service after 2007 and before 2014. The majority of such qualifying property has historically been depreciated over a seven to fifteen year period. The Company has realized an estimated $21 million tax benefit for the years 2008 through 2010 associated with additional first-year bonus tax depreciation in excess of historical tax depreciation. The Company received this tax benefit through its tax sharing agreement with Southern Union Company. The amount of tax benefit applicable to years 2011 through 2013 will be subject to the level of qualified property placed in service during those years. For additional information related to the tax sharing agreement, see Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – Income Taxes.

Investing Activities. The Company’s business strategy includes making prudent capital expenditures across its base of interstate transmission assets. Changes in cash flow resulting from investing activities associated with these objectives are significantly impacted by the ongoing expansion of the Company’s existing asset base through additions to property, plant and equipment. Historically, the Company has utilized its operating cash flow to satisfy its general capital requirements and has accessed the capital markets only for extraordinary capital expenditures.

Cash flows used in investing activities for the year ended December 31, 2010 decreased by $236.7 million versus the same period in 2009. Such decrease in cash outlays from investing activities is primarily due to the impact of $127.8 million of net intercompany loans to Southern Union in 2010 versus $200 million of loan repayments to the Company in 2009, in addition to lower net capital and property retirement expenditures of $127.5 million in the 2010 period versus the 2009 period, largely attributable to placing the Trunkline LNG infrastructure enhancement construction project in service in March 2010. See Item 8. Financial Statements and Supplementary Data, Note 4 – Related Party Transactions for information related to the intercompany loans with Southern Union and Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for information related to insurance recoveries, which partially offset the capital and property retirement expenditures.

The following table presents a summary of property, plant and equipment additions related to major projects for the periods presented.

	Years Ended December 31,
Property, Plant and Equipment Additions	2010		2009		2008
	(In thousands)

LNG Terminal Expansions/Enhancements	$	21,877	$	82,033	$	157,325
Trunkline Field Zone Expansion		-		1,733		72,276
East End Enhancement		-		-		35,062
Compression Modernization		-		7,146		56,288
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and net hurricane expenditures		123,797		156,185		113,053
Total (1)	$	145,674	$	247,097	$	434,004

___________________

(1)	Related cash impact includes the net reduction in capital accruals totaling $17.2 million, $25 million and $24.6 million for the years ended December 31, 2010, 2009, and 2008, respectively.

2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Damage from the hurricanes affected the Company’s Transportation and Storage segment. Offshore transportation facilities, including Sea Robin and Trunkline, suffered damage to several platforms and gathering pipelines. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was back in service.

The capital replacement and retirement expenditure estimates relating to Hurricane Ike have been reduced from $185 million to approximately $150 million and are expected to be completed in 2011. Approximately $134 million, $110 million and $23 million of the capital replacement and retirement expenditures were incurred as of December 31, 2010, 2009 and 2008, respectively. The Company anticipates reimbursement from OIL for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. OIL announced that it has reached the $750 million aggregate exposure limit and currently calculates its estimated payout amount at 70 percent or less based on estimated claim information it has received. OIL is currently making interim payouts at the rate of 50 percent of accepted claims. The Company received a total of $25.8 million and $36.7 million in 2010 and 2009, respectively, for claims submitted to date with respect to Hurricane Ike. The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.

Potential Sea Robin Impairment. Sea Robin, comprised primarily of offshore facilities, suffered damage from Hurricane Ike related to several platforms and gathering pipelines. See Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – Asset Impairment for information related to the Company’s analysis of the Sea Robin assets for potential impairment as of December 31, 2009. As there were no indicators of potential impairment during 2010, the impairment test on Sea Robin was not performed as of December 31, 2010. The Company currently estimates that approximately $115 million of the approximately $150 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin. The Company anticipates partial reimbursement from its property insurance carrier for its damages in excess of its $10 million deductible, except for certain expenditures not reimbursable under the insurance policy terms. See Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information. Additionally, Sea Robin has implemented a rate surcharge approved by FERC in September 2009, subject to refund, to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties. To the extent the Company’s capital expenditures are not recovered through insurance proceeds or through its hurricane rate surcharge, its net investment in Sea Robin’s property and equipment would increase without necessarily generating additional revenues unless the incremental costs are recovered through future rate proceedings or additional throughput. See Item 8. Financial Statements and Supplementary Data, Note 3 – Regulatory Matters for information related to the surcharge filing. If the amount of the estimated Sea Robin insurance reimbursements are significantly reduced or Sea Robin experiences other adverse developments incrementally impacting the Company’s related net investment or anticipated future cash flows that are not remedied through rate proceedings, the Company could potentially be required to record an impairment of its net investment in Sea Robin.

Financing Activities. Financing activities used cash of $40.5 million and provided cash of $88 million for the years ended December 31, 2010 and 2009, respectively. The $128.5 million change is primarily due to net debt repayments of $40.5 million in 2010 versus net debt issuances of $88.1 million in 2009.

As of December 31, 2010, the Company’s debt was rated Baa3 by Moody’s Investor Services, Inc., BBB- by Standard & Poor’s and BBB- by Fitch Ratings. If the Company’s credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," the Company could be negatively impacted as follows:

·	Borrowing costs associated with debt obligations could increase annually up to approximately $4.3 million; and

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

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. At December 31, 2010, the Company, based on the currently most restrictive debt covenant requirements, was subject to a $1.06 billion limitation on additional restricted payments including dividends and loans to affiliates, and a limitation of $413 million of additional secured or subsidiary level indebtedness or other defined liens based on a limitation on liens covenant. The Company is also subject to a limitation of $1.03 billion of total additional indebtedness. If the Company’s debt ratings by Moody’s Investor Services, Inc. were to fall below Baa3 or if its debt ratings by Standard & Poor’s were to fall below BBB-, then the allowable restricted payments would be reduced to $343.7 million. At December 31, 2010, the Company was in compliance with all covenants.

8.125% Senior Notes. In June 2009, the Company issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). In connection with the issuance of the 8.125% Senior Notes, the Company incurred underwriting and discount costs totaling approximately $1 million, resulting in approximately $149 million in proceeds to the Company. The proceeds were initially loaned to Southern Union Company, under the demand note between the Company and Southern Union Company. A portion of such advanced amounts was subsequently repaid by Southern Union Company to the Company and used to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.

7.00% Senior Notes due 2018. In June 2008, the Company issued $400 million in senior notes due June 15, 2018 with an interest rate of 7.00 percent (7.00% Senior Notes). In connection with the issuance of the 7.00% Senior Notes, the Company incurred underwriting and discount costs totaling approximately $4.1 million, resulting in approximately $395.9 million in proceeds to the Company. The proceeds were initially loaned to Southern Union Company under the demand note between the Company and Southern Union Company. Such advanced amounts were repaid by Southern Union Company to the Company and used to repay the $300 million of 4.80% Senior Notes due August 15, 2008.

Retirement of Debt Obligations

Retirement of Debt Obligations. The Company repaid the $40.5 million 8.25% Senior Notes in April 2010 primarily using repayments from Southern Union Company of intercompany loans.

For additional information related to the Company’s debt, see Item 8. Financial Statements and Supplementary Data, Note 7 – Debt.

Other Matters

Regulation. See Item 8. Financial Statements and Supplementary Data, Note 3 – Regulatory Matters for information related to the Company’s rate 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 Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies.

Contractual Commitments. The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2010.

	Contractual Obligations
																			2016 and
	Total			2011			2012			2013			2014			2015			thereafter
	(In thousands)

Operating leases (1)		$	108,673		$	12,739		$	9,487		$	12,149		$	12,157		$	11,699		$	50,442
Total long term debt (2)			1,981,696			-			815,391			250,000			-			-			916,305
Interest payments on debt (3)			586,833			85,693			80,893			78,554			63,429			63,429			214,835
Firm capacity payments (4)			215,647			37,928			31,641			29,698			28,925			25,338			62,117
OPEB funding (5)			38,215			7,643			7,643			7,643			7,643			7,643			-
Total		$	2,931,064		$	144,003		$	945,055		$	378,044		$	112,154		$	108,109		$	1,243,699

___________________

(1)	Lease of various assets utilized for operations.

(2)	The long-term debt cash obligations exclude $2.7 million of unamortized debt premium as of December 31, 2010.

(3)	Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2010.

(4)	Charges for third party storage capacity.

(5)	Panhandle is committed to the funding levels of $7.6 million per year until modified by future rate proceedings, the timing of which is uncertain.

Inflation. The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, 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.

Trunkline LNG Cost and Revenue Study. On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders. Such filing, which was as of March 31, 2009, reflected an annualized cost of service level and associated revenues of $54.7 million and $68.5 million, respectively. BG LNG Services (BGLS) filed a motion to intervene and protest on July 14, 2009. By order dated July 26, 2010, FERC determined that since (i) Trunkline LNG has fixed negotiated rates with BGLS through 2015, which would be unaffected by any rate change that might be determined through hearing at this time, and (ii) current costs and revenues are not necessarily representative of Trunkline LNG’s costs and revenues at the termination of the negotiated rate period in 2015, there was no reason to expend FERC’s and the parties’ resources on a Natural Gas Act Section 5 proceeding at this time. The order is final and not subject to rehearing.

New Accounting Pronouncements

See Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – New Accounting Principles.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risks.

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. At December 31, 2010, the interest rate on 82 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2010, $19.7 million is included in Other Current Liabilities and $4.6 million is included in Other Non-current Liabilities in the Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012.

At December 31, 2010, a 100 basis point change in the annual interest rate on all outstanding floating-rate long-term debt would correspondingly change the Company’s interest payments by approximately $300,000 for each month during which such change continued. If interest rates changed significantly, the Company may take actions to manage its exposure to the change. No change has been assumed, as a specific action and the possible effects are uncertain.

The Company has entered into treasury rate locks from time to time to manage its exposure against changes in future interest payments attributable to changes in the US treasury rates. By entering into these agreements, the Company locks in an agreed upon interest rate until the settlement of the contract, which typically occurs when the associated long-term debt is sold. The Company accounts for the treasury rate locks as cash flow hedges. The Company’s most recent treasury rate locks were settled in February and June 2008.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2010 is not material to the Company.

See Item 8. Financial Statements and Supplementary Data, Note 10 – Derivative Instruments and Hedging Activities and Note 7 – Debt for additional related information.

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, 2010, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

ITEM 8. Financial Statements and Supplementary Data.

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

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

The Company has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the COO and CFO, as appropriate, to allow timely decisions regarding required disclosure. The Company performed an evaluation under the supervision and with the participation of management, including its COO and CFO, and with the participation of personnel from its legal, internal audit, insurance and financial reporting departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Company’s COO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2010. Management has also communicated that determination to the board of managers and Southern Union’s audit committee, which also serves as the Company’s audit committee.

Management’s Report on Internal Control Over Financial Reporting

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

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

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

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

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

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

Management’s evaluation of the effectiveness of the Company’s internal control over financial reporting was based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under that framework and applicable SEC rules, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.

Panhandle Eastern Pipe Line Company, LP

February 25, 2011

Changes in Internal Controls Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

ITEM 9B. Other Information.

All information required to be reported on Form 8-K for the quarter ended December 31, 2010 was appropriately reported.

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.

Below is a summary of fees billed to the Company by its principal audit firm for the periods indicated.

	Years Ended December 31,
	2010			2009
	(In thousands)
Audit Fees (1)
PricewaterhouseCoopers LLP		$	1,128		$	1,132

Audit-Related Fees (2)
PricewaterhouseCoopers LLP			85			136

Total Fees		$	1,213		$	1,268

___________________

(1)	Audit Fees represents fees billed for professional services rendered for the Company’s integrated annual audit.

(2)	Audit-Related Fees represents fees billed for the issuance of debt and audit of the Company’s centralized data center procedures.

The audit committee has adopted a policy requiring pre-approval of all audit and non-audit services (including the fees and terms thereof) to be provided to the Company by its independent auditor, other than non-audit services not recognized to be non-audit services at the time of the engagement that meet the de minimis exceptions described in Section 10A(i)(1)(B)(i) of the Securities Exchange Act of 1934; provided that they are approved by the audit committee prior to the completion of the audit.

PART IV

ITEM 15. Exhibits, Financial Statement Schedules.

(a)(1) and (2)

Financial Statements and Financial Statement Schedules.

(a)(3)

Exhibits.

Exhibit No.	Description

3(a)	Certificate of Formation of Panhandle Eastern Pipe Line Company, LP. (Filed as Exhibit 3.A to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)

3(b)	Limited Partnership Agreement of Panhandle Eastern Pipe Line Company, LP, dated as of June 29, 2004, between Southern Union Company and Southern Union Panhandle LLC. (Filed as Exhibit 3.B to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)

4(a)	Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(a) to the Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference.)


4(b)	First Supplemental Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company. (Filed as Exhibit 4(b) to the Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference.)

4(c)	Second Supplemental Indenture dated as of March 27, 2000, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(e) to the Form S-4 (File No. 333-39850) filed on June 22, 2000, and incorporated herein by reference.)

4(d)	Third Supplemental Indenture dated as of August 18, 2003, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(d) to the Form 10-Q for the quarter ended September 30, 2003, and incorporated herein by reference.)

4(e)	Fourth Supplemental Indenture dated as of March 12, 2004, between Panhandle and J.P. Morgan Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4.E to the Form 10-K for the year ended December 31, 2004 and incorporated herein by reference.)

4(f)	Fifth Supplemental Indenture dated as of October 26, 2007, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on October 29, 2007 and incorporated herein by reference.)

4(g)	Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on June 11, 2008 and incorporated herein by reference.)

10(a) 10(b)	Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between Panhandle and The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Panhandle’s Current Report on Form 8-K filed on May 28, 2009 and incorporated herein by reference). Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007 (Filed as Exhibit 10.1 to Panhandle’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)


10(c) 10(d)	Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008 (Filed as Exhibit 10(b) to the Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.) Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo- Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Panhandle’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)

10(e)	Amended and Restated Promissory Note made by CrossCountry Citrus, LLC, as borrower, in favor of Trunkline LNG Holdings LLC, as holder, dated as of June 13, 2008 (Filed as Exhibit 10(d) to the Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
12	Ratio of Earnings to Fixed Charges.
23.1	Consent of Independent Registered Public Accounting Firm for Panhandle Eastern Pipe Line Company, LP.
24	Power of Attorney.

31.1	Certificate by President and Chief Operating Officer pursuant to Rule 13a – 14(a) or 15d – 14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certificate by Senior Vice President and Chief Financial Officer pursuant to Rule 13a – 14(a) or 15d – 14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certificate by President and Chief Operating Officer pursuant to Rule 13a – 14(b) or 15d – 14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

32.2	Certificate by Senior Vice President and Chief Financial Officer pursuant to Rule 13a – 14(b) or 15d – 14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Panhandle Eastern Pipe Line Company, LP has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, on February 25, 2011.

	PANHANDLE EASTERN PIPE LINE COMPANY, LP

	By: /s/ ROBERT O. BOND
	Robert O. Bond
	President and Chief Operating Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed by the following persons on behalf of Panhandle Eastern Pipe Line Company, LP and in the capacities indicated as of February 25, 2011.

Signature		Title
(i)	Principal executive officer: /s/ Robert O. Bond Robert O. Bond	President and Chief Operating Officer
(ii)	Principal financial officer: /s/ Richard N. Marshall Richard N. Marshall	Vice President and Chief Financial Officer
(iii)	Principal accounting officer: /s/ Gary W. Lefelar Gary W. Lefelar	Vice President and Chief Accounting Officer

(iv)	A majority of the Board of Directors of Southern Union Company, Sole Member of Southern Union Panhandle, LLC, General Partner of Panhandle Eastern Pipe Line Company, L.P.

/s/ George L. Lindemann* George L. Lindemann /s/ Eric Herschmann* Eric Herschmann		Chairman, Southern Union Company Vice Chairman, Southern Union Company
/s/ David Brodsky* David Brodsky		Director, Southern Union Company
/s/ Frank W. Denius* Frank W. Denius		Director, Southern Union Company
/s/Kurt A. Gitter, M.D.* Kurt A. Gitter, M.D.		Director, Southern Union Company
/s/ Herbert H. Jacobi* Herbert H. Jacobi		Director, Southern Union Company
/s/ Thomas N. McCarter, III* Thomas N. McCarter, III		Director, Southern Union Company
/s/ George Rountree, III* George Rountree, III		Director, Southern Union Company
/s/ Allan D. Scherer* Allan D. Scherer		Director, Southern Union Company

*By: /s/ RICHARD N. MARSHALL		*By: /s/ ROBERT M. KERRIGAN, III
Vice President and Chief Financial Officer		Vice President and Secretary
Attorney-in-fact		Attorney-in-fact

PANHANDLE EASTERN PIPE LINE, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:
Consolidated Statement of Operations	F-2
Consolidated Balance Sheet	F-3 – F-4
Consolidated Statement of Cash Flows	F-5
Consolidated Statement of Partners' Capital and Comprehensive Income	F-6
Notes to Consolidated Financial Statements	F-7
Report of Independent Registered Public Accounting Firm	F-36

All schedules are omitted as the required information is not applicable or the information is presented in the consolidated financial statements or related notes.

F-1

PANHANDLE EASTERN PIPE LINE COMPANY, LP
CONSOLIDATED STATEMENT OF OPERATIONS


	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Operating revenue
Transportation and storage of natural gas	$	561,354		$	607,366		$	582,942
LNG terminalling revenue		199,182			134,026			128,950
Other revenue		8,914			7,769			9,748
Total operating revenues		769,450			749,161			721,640

Operating expenses
Operating, maintenance and general		216,359			237,035			225,517
Operating, maintenance and general - affiliate (Note 4)		54,898			47,573			50,657
Depreciation and amortization		123,009			113,648			103,807
Taxes, other than on income		36,063			34,537			32,059
Total operating expenses		430,329			432,793			412,040

Operating income		339,121			316,368			309,600

Other income (expenses):
Interest expense		(103,458	)		(84,496	)		(89,057	)
Interest income - affiliates (Note 4)		8,642			8,970			24,411
Other, net		151			1,473			2,252
Total other expenses		(94,665	)		(74,053	)		(62,394	)

Earnings before income taxes		244,456			242,315			247,206

Income taxes (Note 9)		96,801			92,100			96,532

Net earnings	$	147,655		$	150,215		$	150,674



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

F-2

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEET

ASSETS
	December 31,
	2010		2009
	(In thousands)

Current assets:
Cash and cash equivalents	$	56	$	55
Accounts receivable, billed and unbilled,
net of allowances of $897 and $1,147, respectively		77,888		67,485
Accounts receivable – related parties (Note 4)		5,922		6,083
Natural gas imbalances - receivable		51,607		126,842
System natural gas and operating supplies		147,254		214,706
Other		22,261		29,050
Total current assets		304,988		444,221

Property, plant and equipment (Note 12):
Plant in service		3,952,425		3,353,822
Construction work in progress		47,085		495,588
		3,999,510		3,849,410
Less accumulated depreciation and amortization		613,336		493,873
Net property, plant and equipment		3,386,174		3,355,537

Note receivable - related parties (Note 4)		823,406		695,606
Other		24,361		29,033


Total assets	$	4,538,929	$	4,524,397









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

F-3

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEET

PARTNERS' CAPITAL AND LIABILITIES

	December 31,
	2010			2009
	(In thousands)

Partners' capital
Partners' capital	$	1,640,691		$	1,493,036
Accumulated other comprehensive loss (Note 6)		(16,928	)		(19,541	)
Tax sharing note receivable - Southern Union		(3,188	)		(5,218	)
Total partners' capital		1,620,575			1,468,277

Long-term debt (Note 7)		1,984,427			1,984,246
Total capitalization		3,605,002			3,452,523

Current liabilities:
Current portion of long-term debt (Note 7)		-			40,500
Accounts payable		9,811			8,228
Accounts payable - related parties (Note 4)		56,393			24,881
Natural gas imbalances - payable		177,192			321,638
Accrued taxes		15,423			17,975
Accrued interest		14,298			15,125
Capital accruals		33,038			50,246
Other		95,191			121,039
Total current liabilities		401,346			599,632

Deferred income taxes, net (Note 9)		466,309			418,992
Other		66,272			53,250
Commitments and contingencies (Note 14)

Total partners' capital and liabilities	$	4,538,929		$	4,524,397








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

F-4

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Cash flows provided by (used in) operating activities:
Net earnings	$	147,655		$	150,215		$	150,674
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		123,009			113,648			103,807
Deferred income taxes, net		51,891			116,481			38,672
Changes in operating assets and liabilities:
Accounts receivable		(10,242	)		7,085			(1,614	)
Inventory		1,332			12,692			(3,273	)
Other assets		1,200			2,437			272
Accounts payable		10,678			4,970			(154	)
Accrued taxes		(523	)		7,757			4,303
Interest accrued		(827	)		(736	)		(4,443	)
Other liabilities		(23,348	)		(5,449	)		9,310
Net cash flows provided by operating activities		300,825			409,100			297,554

Cash flows provided by (used in) investing activities:
Net decrease (increase) in note receivable - related parties		(127,800	)		(175,685	)		113,954
Net increase (decrease) in income taxes payable - related parties (Note 4)		21,196			(34,347	)		15,005
Additions to property, plant and equipment		(160,876	)		(270,772	)		(472,254	)
Plant retirements and other		7,139			(16,271	)		14,554
Net cash flows used in investing activities		(260,341	)		(497,075	)		(328,741	)

Cash flows provided by (used in) financing activities:
Decrease in book overdraft		17			(111	)		(13,221	)
Issuance of long-term debt		-			150,000			400,000
Repayment of debt		(40,500	)		(60,623	)		(351,829	)
Issuance costs of debt		-			(1,264	)		(2,915	)
Other		-			-			(1,140	)
Net cash flows provided by (used in) financing activities		(40,483	)		88,002			30,895

Change in cash and cash equivalents		1			27			(292	)

Cash and cash equivalents at beginning of period		55			28			320
Cash and cash equivalents at end of period	$	56		$	55		$	28


Supplemental disclosures of cash flow information
Cash paid during the period for:
Interest (net of interest rate swap and amounts capitalized)	$	102,444		$	108,861		$	106,359
Income taxes (net of refunds)		21,684			6,623			38,713

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

F-5

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME


	Partners' Capital		Accumulated Other Comprehensive Income (Loss)			Tax Sharing Note Receivable-Southern Union			Total
	(In thousands)

Balance December 31, 2007	$	1,192,147	$	1,636		$	(12,704	)	$	1,181,079

Tax sharing receivable - Southern Union (Note 4)		-		-			4,143			4,143

Comprehensive income:
Net earnings		150,674		-			-			150,674
Net change in other comprehensive income (Note 6)		-		(29,937	)		-			(29,937	)
Comprehensive income		150,674		(29,937	)		-			120,737

Balance December 31, 2008	$	1,342,821	$	(28,301	)	$	(8,561	)	$	1,305,959

Tax sharing receivable - Southern Union (Note 4)		-		-			3,343			3,343

Comprehensive income:
Net earnings		150,215		-			-			150,215
Net change in other comprehensive income (Note 6)		-		8,760			-			8,760
Comprehensive income		150,215		8,760			-			158,975

Balance December 31, 2009	$	1,493,036	$	(19,541	)	$	(5,218	)	$	1,468,277

Tax sharing receivable - Southern Union (Note 4)		-		-			2,030			2,030

Comprehensive income:
Net earnings		147,655		-			-			147,655
Net change in other comprehensive income (Note 6)		-		2,613			-			2,613
Comprehensive income		147,655		2,613			-			150,268

Balance December 31, 2010	$	1,640,691	$	(16,928	)	$	(3,188	)	$	1,620,575






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

F-6

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Structure

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

·	PEPL, an indirect wholly-owned subsidiary of Southern Union Company;

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

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

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

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

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

The Company’s pipeline assets include approximately 10,000 miles 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. The pipelines have a combined peak day delivery capacity of 5.5 Bcf/d and approximately 68.1 Bcf of owned underground storage capacity. The Company also owns and operates an LNG import terminal located on Louisiana’s Gulf Coast, and has 9.0 Bcf of above ground LNG storage capacity.

Southern Union Panhandle, LLC, a direct wholly-owned subsidiary of Southern Union Company, serves as the general partner of PEPL and owns a one percent general partnership interest in PEPL. Southern Union Company owns a ninety-nine percent limited partnership interest in PEPL.

2. Summary of Significant Accounting Policies and Other Matters

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

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies under GAAP that do not conform to authoritative guidance which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. In 1999, the Company discontinued application of regulatory-based accounting policies for its units which had been applying such accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. The accounting required by the regulatory-based authoritative guidance differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, among others, recording of regulatory assets, the capitalization of an equity component of invested funds on regulated capital projects and depreciation differences. The Company periodically reviews its level of discounting and negotiated rate contracts, the length of rate moratoriums and other related factors to determine if the regulatory-based authoritative guidance should be applied.

Principles of Consolidation. The consolidated financial statements include the accounts of all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in businesses not controlled by PEPL, but over which it has significant influence, are accounted for using the equity method. Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents. Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

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

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

	December 31,
	2010		2009
	(In thousands)
Current
Natural gas (1)	$	129,727	$	198,712
Materials and supplies		17,527		15,994
Total current		147,254		214,706

Non-Current
Natural gas (1)		5,715		8,831
	$	152,969	$	223,537

______________________________

(1)	Natural gas volumes held for operations at December 31, 2010 and 2009 were 30,598,000 MMBtu and 35,039,000 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. Effective November 2008, Trunkline LNG entered into a settlement with its customer that provides for monthly reimbursement of actual fuel usage costs, resulting in Trunkline LNG no longer having a fuel tracker. The other FERC-regulated Panhandle entities record an expense when fuel is under-recovered or record a credit to expense to the extent any under-recovered prior period balances are subsequently recouped as they do not have such explicit billing rights specified in their tariffs. Liability accounts are maintained for net volumes of compressor fuel natural gas owed to customers collectively. The pipelines’ fuel reimbursement is in-kind and non-discountable.

Property, Plant and Equipment. 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. 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.

F-7

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

When property, plant and equipment is retired, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of property, plant and equipment are retired or sold or non-regulated properties are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in earnings.

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

Computer software, which is a component of property, plant and equipment, is stated at cost and is generally amortized on a straight-line basis over its useful life on a product-by-product basis.

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. The long-lived assets of Sea Robin were evaluated as of December 31, 2009 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricane Ike and due to reductions in the estimated payout from the Company’s insurance carrier for reimbursable expenditures for the repair, retirement or replacement of the Company’s property, plant and equipment damaged by Hurricane Ike, which is more fully discussed in Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage.

As there were no indicators of potential impairment during 2010, the impairment test on Sea Robin was not performed as of December 31, 2010. However, to the extent the Company’s capital expenditures resulting from Hurricane Ike damage are not recovered through insurance proceeds or through Sea Robin’s hurricane rate surcharge, its net investment in Sea Robin’s property and equipment will have increased without necessarily realizing corresponding cash inflows unless the incremental costs are recovered through future rate proceedings or additional throughput. See Note 3 – Regulation and Rates – Sea Robin for information related to the surcharge filing. If the surcharge filing is not ultimately approved by FERC or Sea Robin experiences other adverse developments incrementally impacting the Company’s related net investment or anticipated future cash flows that are not remedied through rate proceedings, the Company could potentially be required to record an impairment of its net investment in Sea Robin.

Related Party Transactions. Related party expenses primarily include payments for services provided by Southern Union. Other income is primarily related to interest income from the Notes receivable from Southern Union and CrossCountry Citrus, an indirect wholly-owned subsidiary of Southern Union. See Note 4 – Related Party Transactions.

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

F-8

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Unamortized Debt Premium, Discount and Expense. The Company amortizes premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.

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

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

Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards. Customers that do not meet minimum standards are required to provide additional credit support. The Company utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable. Increases in the allowance are recorded as a component of operating expenses. Reductions in the allowance are recorded when receivables are written-off or subsequently collected. Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.

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

	Years Ended December 31,
	2010			2009				2008
	(In thousands)

Beginning balance	$	1,147			$	1,161			$	1,163
Additions: charged (credited) to expense		(250	)			1				-
Deductions: write-off of uncollectible accounts		-				(15	)			(2	)
Ending balance	$	897			$	1,147			$	1,161

F-9

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Percent of Operating Revenue for
	Years Ended December 31,
	2010			2009			2008

BG LNG Services		29	%		22	%		23	%
ProLiance		13			13			12
Other top 10 customers		23			26			26
Remaining customers		35			39			39
Total percentage		100	%		100	%		100	%

Interest Cost Capitalized. The Company capitalizes a carrying cost on funds invested in its construction of long-lived assets that includes a return on the investment financed by debt, which is recorded as capitalized interest. The capitalized interest is calculated based on the Company’s average cost of debt. Capitalized interest for the years ended December 31, 2010, 2009 and 2008 was $6.6 million, $25.7 million and $18.9 million, respectively. The capitalized interest amounts are included as a reduction of interest expense. Capitalized carrying cost for debt is reflected as an increase in the cost of the asset on the balance sheet.

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

See Note 8 – Benefits for additional 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 if the short cut method of assessing effectiveness is not used. 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 – Derivative Instruments and Hedging Activities.

F-10

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

See Note 11 – Fair Value Measurement and Note 8 -- Benefits – Postretirement Benefit Plans – Plan Assets 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.

For more information, see Note 5 – Asset Retirement Obligations.

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.

F-11

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The determination of the Company’s 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. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes.

As a limited partnership, PEPL is treated as a disregarded entity for federal income tax purposes. Accordingly, for federal and certain state income tax purposes, PEPL and its subsidiaries are not treated as separate taxpayers; instead, their income is directly taxable to Southern Union Company. Pursuant to a tax sharing agreement with Southern Union Company, the Company 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. The Company will receive credit under an intercompany note from Southern Union Company for differences in tax depreciation resulting from the like-kind exchange over the taxable life of the related assets. See Note 9 – Income Taxes.

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

New Accounting Principles

Accounting Principles Recently Adopted.

In June 2009, the FASB issued authoritative guidance that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The guidance is effective as of the beginning of the first annual reporting period, and for interim periods within that first period, after November 15, 2009, with early adoption prohibited. This guidance did not materially impact the Company’s consolidated financial statements.

In January 2010, the FASB issued authoritative guidance to improve disclosure requirements related to fair value measurements. This guidance requires new disclosures associated with the three-tier fair value hierarchy for transfers in and out of Levels 1 and 2 and for activity within Level 3. It also clarifies existing disclosure requirements related to the level of disaggregation and disclosures about certain inputs and valuation techniques. This guidance is effective for interim or annual financial periods beginning after December 15, 2009, except for the disclosures related to activity within Level 3, which is effective for interim or annual financial periods beginning after December 15, 2010. This guidance did not materially impact the Company’s consolidated financial statements.

In July 2010, the FASB issued authoritative guidance to improve disclosure requirements related to financing receivables and the allowance for credit losses. This guidance requires a greater level of disaggregated information about the credit quality of financing receivables and the allowance for credit losses and requires the disclosure of credit quality indicators, past due information, and modifications of financing receivables. The enhanced disclosures as of the end of a reporting period are effective for interim and annual reporting periods ending on or after December 15, 2010. The enhanced disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. This guidance did not materially impact the Company’s consolidated financial statements.

F-12

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Regulatory Matters

Trunkline LNG commenced construction of an enhancement at its LNG terminal in February 2007. The key components of the enhancement are an ambient air vaporizer system and NGL recovery units. On March 11, 2010, Trunkline LNG received approval from FERC to place the infrastructure enhancement construction project in service. Total construction costs were approximately $440 million plus capitalized interest, which includes additional costs incurred during final commissioning. The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. In addition, Trunkline LNG and BG LNG Services have extended the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement construction project contract, which runs 20 years from the in-service date.

On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, with initial accumulated net costs of approximately $38 million included in the filing. On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings with FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts. On August 31, 2010, Sea Robin submitted its semiannual filing related to the surcharge which reflected updated costs incurred of approximately $46 million, net of insurance and surcharge recoveries, which were reflected in the updated surcharge rate effective October 1, 2010, subject to refund. The Administrative Law Judge issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted shippers, over a recovery period of 21.4 years and including applicable carrying charges. The Company, as well as other parties, have filed briefs for exception on certain aspects of the decision. The ultimate outcome of this matter is pending a final FERC decision.

On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to identify HCAs along their pipelines and to complete baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by December 2012. Operators were required to rank the risk of their pipeline segments containing HCAs, assessments are generally conducted on the higher risk segments first. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2010, the Company had completed approximately 90 percent of the baseline risk assessments required to be completed by December 2012. While identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $10 million to $20 million per year through 2012.

F-13

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. Related Party Transactions

	Years Ended December 31,
Related Party Transactions	2010		2009		2008
	(In thousands)

Transportation and storage
of natural gas (1)	$	3,477	$	3,821	$	4,317
Operation and maintenance:
Management and royalty fees		19,237		18,718		18,113
Other expenses (2)		35,661		28,855		32,544
Other income, net:
Interest income - Southern Union		1,373		1,376		5,866
Interest income - CCCitrus		7,269		7,594		18,545
Other		237		224		304

___________________________

(1)	Represents transportation and storage revenues with Missouri Gas Energy, a Southern Union division.

(2)	Primarily includes allocations of corporate charges from Southern Union, partially offset for expenses attributable to services provided by Panhandle on behalf of other affiliate companies.

Pursuant to a demand note with Southern Union Company 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.

The interest rate under the note receivable with CrossCountry Citrus is based on the variable interest rate under the term loan facility due in 2012 plus a credit spread over LIBOR of 112.5 basis points. See Note 7. Debt Obligations – LNG Holdings Term Loans for more information regarding this note receivable.

The counterparty to the notes receivable is the parent of the Company, Southern Union, whose debt is rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's.

Southern Union structured the acquisition of PEPL in a manner which qualified as a like-kind exchange of property under Section 1031 of the Code. For tax purposes, the Company’s assets that were part of the exchange were recorded at the tax basis of the Southern Union Company assets for which they were exchanged. The resulting transaction generated an estimated deferred tax liability at the acquisition date and a corresponding receivable from Southern Union Company reflected as a reduction to Partners’ Capital on the Company’s Consolidated Balance Sheet. Repayment of the receivable from Southern Union Company is limited to actual tax liabilities otherwise payable by the Company pursuant to the tax sharing agreement with Southern Union Company. For the years ended December 31, 2010 and 2009, the Company recorded $2 million and $3.3 million of income tax liability settlements against the tax sharing note receivable, respectively, with a balance of $3.2 million remaining at December 31, 2010. The Company settles the intercompany income tax liability with Southern Union on an annual basis. The settlements, which are settled against the demand note with Southern Union, are reported as investing activities in the Consolidated Statement of Cash Flows.

F-14

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides a summary of the related party balances included in the Consolidated Balance Sheet at the dates indicated.

	December 31,
	2010		2009
	(In thousands)
Notes receivable - related parties
Southern Union	$	455,280	$	327,480
CrossCountry Citrus		368,126		368,126
	$	823,406	$	695,606

Accounts receivable - related parties (1)	$	5,922	$	6,083

Accounts payable - related parties:
Southern Union - income taxes (2)	$	43,273	$	22,077
Southern Union - other (3)		12,940		2,615
Other (4)		180		189
	$	56,393	$	24,881

______________________________

(1)	Primarily related to interest income associated with the Note receivable – CrossCountry Citrus and services provided for Citrus.

(2)	Related to income taxes payable to Southern Union per the tax sharing agreement to provide for taxes to be remitted upon the filing of the tax return.

(3)	Primarily related to payroll funding provided by Southern Union. The December 31, 2010 and 2009 amount is net of insurance proceeds of $13.9 million and $16.1 million, respectively, owed by Southern Union to the Company.

(4)	Primarily related to various administrative and operating costs paid by other affiliate companies on behalf of the Company.

5. Asset Retirement Obligations

The Company’s recorded asset retirement obligations are primarily related to owned 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 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 on the pipeline system may be replaced, the pipeline system itself will remain intact indefinitely.

The following table is a general description of ARO and associated long-lived assets at December 31, 2010.

	In Service
ARO Description	Date	Long-Lived Assets	Amount
			(In thousands)

Retire offshore platforms and lines	Various	Offshore lines		$	15,114
Remove asbestos	Various	Mainlines and compressors			872

F-15

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2010, the Company recorded $159,000 that is legally restricted for the purpose of settling AROs.

The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented.

	Years Ended December 31,
	2010			2009				2008
	(In thousands)

Beginning balance	$	58,449			$	50,941			$	11,826
Incurred		28,605				8,289				33,773
Revisions		(11,395	)			(3,246	)			6,379
Settled		(19,721	)			(1,553	)			(1,861	)
Accretion expense		813				4,018				824
Ending balance	$	56,751			$	58,449			$	50,941

In 2010, additional AROs of $28.6 million were established primarily associated with offshore assets as a result of management assessment of additional information. Also in 2010, the Company recorded revisions of $11.4 million due to project scope adjustments, favorable weather conditions, and realized project efficiencies which resulted in reductions to the ARO liability. The ARO liability was further reduced by settlements of $19.7 million. Such revisions and settlements were primarily associated with AROs of $8.3 million and $33.8 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike. See Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information.

F-16

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. Comprehensive Income

The table below provides an overview of comprehensive income for the periods presented.

	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Net earnings	$	147,655		$	150,215		$	150,674

Realized gain (loss) on interest rate hedges, net of tax of $0, $0
and $197, respectively		-			-			309
Reclassification of unrealized loss (gain) on interest rate hedges
into earnings, net of tax of $8,711, $7,537 and $(3,138), respectively		12,968			11,223			(4,656	)
Change in fair value of interest rate hedges, net of tax of
$(5,237), $(3,051) and $(7,815), respectively		(7,790	)		(4,538	)		(11,663	)
Prior service cost relating to other postretirement benefit plan
amendments, net of tax of $0, $0 and $(3,020), respectively		-			-			(4,534	)
Actuarial gain (loss) relating to other postretirement benefits,
net of tax of $(427), $2,545 and $(3,742), respectively		(1,285	)		3,266			(7,821	)
Reclassification of net actuarial gain and prior service credit relating
to other postretirement benefits into earnings, net of tax
of $(809), $(400) and $(713), respectively		(1,280	)		(1,191	)		(1,572	)
Total other comprehensive income (loss)		2,613			8,760			(29,937	)

Total comprehensive income	$	150,268		$	158,975		$	120,737


	December 31,
	2010			2009
	(In thousands)
Other postretirement plan - net actuarial gain (loss) and prior
service credit (cost), net of tax	$	(1,282	)		$	1,283
Interest rate hedges, net of tax		(15,646	)			(20,824	)
Total Accumulated other comprehensive loss, net of tax	$	(16,928	)		$	(19,541	)

F-17

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Debt Obligations

The following table sets forth the debt obligations at the dates indicated.


	December 31, 2010					December 31, 2009
	Carrying Amount		Fair Value			Carrying Amount				Fair Value
	(In thousands)

6.05% Senior Notes due 2013	$	250,000		$	268,988		$	250,000			$	269,733
6.20% Senior Notes due 2017		300,000			322,893			300,000				319,455
8.125% Senior Notes due 2019		150,000			169,671			150,000				173,111
8.25% Senior Notes due 2010		-			-			40,500				41,143
7.00% Senior Notes due 2029		66,305			69,911			66,305				69,866
7.00% Senior Notes due 2018		400,000			442,120			400,000				434,560
Term Loans due 2012 (1)		815,391			799,084			815,391				758,108
Net premiums on long-term debt		2,731			2,731			2,550				2,550
Total debt outstanding		1,984,427		$	2,075,398			2,024,746			$	2,068,526
Current portion of long-term debt		-						(40,500	)
Total long-term debt	$	1,984,427					$	1,984,246

______________________________

(1)	See the LNG Holdings Term Loan discussion below for information related to these Term Loans.

The fair value of the Company’s term loans due 2012 as of December 31, 2010 and 2009 was determined using the market approach, which utilized reported recent loan transactions for parties of similar credit quality and remaining life, as there is no active secondary market for loans of that type and size.

The fair value of the Company’s other long-term debt as of December 31, 2010 and 2009 was also determined using the market approach, which utilized observable market data to corroborate the estimated credit spreads and prices for the Company’s non-bank long-term debt securities in the secondary market. Those valuations were based in part upon the reported trades of the Company’s non-bank long-term debt securities where available and the actual trades of debt securities of similar credit quality and remaining life where no secondary market trades were reported for the Company’s non-bank long-term debt securities.

8.125% Senior Notes. In June 2009, the Company issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). A portion of the proceeds were used to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.

LNG Holdings Term Loans. On March 15, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan). The interest rate under the 2012 Term Loan is a floating rate tied to LIBOR or the prime rate, at the Company’s option, in addition to a margin tied to the rating of PEPL’s senior unsecured debt. The proceeds of the 2012 Term Loan were used to repay approximately $455 million in existing indebtedness that matured in March 2007, including the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan. LNG Holdings has entered into interest rate swap agreements that effectively fix the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625 percent, based upon PEPL’s credit rating for its senior unsecured debt. The balance of the 2012 Term Loan was $455 million at December 31, 2010 and 2009. See Note 10 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.

F-18

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 1, 2006, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, as guarantors, entered into a $465 million unsecured term loan facility due April 4, 2008 (2006 Term Loan). On December 1, 2006, LNG Holdings loaned the proceeds of the 2006 Term Loan to CrossCountry Citrus in exchange for an interest-bearing promissory note with a principal amount of $465 million, the amount of the proceeds of the 2006 Term Loan. On June 29, 2007, the parties entered into an amended and restated term loan facility (Amended Credit Agreement). The Amended Credit Agreement extended the maturity of the term loan from April 4, 2008 to June 29, 2012, and decreased the interest rate from LIBOR plus 87.5 basis points to LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt. The balance of the Amended Credit Agreement was $360.4 million and $360.4 million at effective interest rates of 0.81 percent and 0.78 percent at December 31, 2010 and 2009, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 18, 2011 were $360.4 million and 0.81 percent, respectively.

Other. The Company’s notes are subject to certain requirements, such as the maintenance of a fixed charge coverage ratio and a leverage ratio, which if not maintained, restrict the ability of the Company to make certain payments and impose limitations on the ability of the Company to subject its property to liens. At December 31, 2010 the Company, based on the currently most restrictive debt covenant requirements, was subject to a $1.06 billion limitation on additional restricted payments including dividends and loans to affiliates, and a limitation of $413 million of additional secured or subsidiary level indebtedness or other defined liens based on a limitation on liens covenant. The Company is also subject to a limitation of $1.03 billion of total additional indebtedness.

As of December 31, 2010, the Company has scheduled long-term debt payments, excluding credit facility payments and net premiums on debt, as follows:

Year ended December 31:	(In thousands)
2011	$	-
2012		815,391
2013		250,000
2014		-
2015		-
Thereafter		916,305

Retirement of Debt Obligations

The Company repaid its $40.5 million 8.25% Senior Notes in April 2010 primarily using repayments from Southern Union of intercompany loans.

8. Benefits

Postretirement Benefit Plans.

The Company has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all employees. The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles and coinsurance on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

F-19

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

	Other Postretirement Benefits
	At December 31,
	2010			2009
	(In thousands)

Change in benefit obligation:
Benefit obligation at beginning of period	$	58,929		$	53,731
Service cost		2,215			2,230
Interest cost		3,515			3,245
Actuarial (gain) loss and other		4,665			(170	)
Benefits paid, net		(220	)		(103	)
Medicare Part D subsidy receipts		20			(4	)
Benefit obligation at end of period	$	69,124		$	58,929

Change in plan assets:
Fair value of plan assets at beginning of period	$	54,361		$	38,734
Return on plan assets and other		6,308			8,077
Employer contributions		7,679			7,653
Benefits paid, net		(220	)		(103	)
Fair value of plan assets at end of period	$	68,128		$	54,361

Amount underfunded at end of period (1)	$	996		$	4,568

Amounts recognized in Accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss (gain)	$	6,399		$	4,687
Prior service cost (credit)		(1,153	)		(3,242	)
	$	5,246		$	1,445

_____________________

(1)	Underfunded balance is recognized as a noncurrent liability in the Consolidated Balance Sheet.

Net Periodic Benefit Cost. Net periodic benefit cost of the Company’s other postretirement benefit plan for the periods presented includes the components noted in the table below.

	Years Ended December 31,
	2010				2009				2008
	(In thousands)
Net periodic benefit cost:
Service cost		$	2,215			$	2,230			$	1,899
Interest cost			3,515				3,245				3,256
Expected return on plan assets			(3,355	)			(2,435	)			(2,396	)
Prior service credit amortization			(2,089	)			(2,089	)			(2,286	)
Actuarial loss amortization			-				498				-
Net periodic benefit cost		$	286			$	1,449			$	473

F-20

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The estimated net actuarial loss and prior service credit for other postretirement plans that will be amortized from Accumulated other comprehensive income into net periodic benefit cost during 2011 are nil and $(2.1) million, respectively.

Assumptions. The weighted-average discount rate used in determining benefit obligations was 5.54 percent and 6 percent at December 31, 2010 and 2009, respectively.

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

	Years Ended December 31,
	2010			2009			2008

Discount rate		6.00	%		5.90	%		6.76	%
Expected return on assets:
Tax exempt accounts		7.00	%		7.00	%		7.00	%
Taxable accounts		5.00	%		5.00	%		5.00	%

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

The assumed health care cost trend rates used for measurement purposes are shown in the table below.

	December 31,
	2010			2009

Health care cost trend rate assumed for next year		9.00	%		8.50	%
Ultimate trend rate		4.75	%		4.85	%
Year that the rate reaches the ultimate trend rate		2019			2017

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			One Percentage
	Point Increase			Point Decrease
	(In thousands)

Effect on total of service and interest cost		$	786		$	(735	)
Effect on accumulated postretirement benefit obligation			9,469			(8,439	)

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 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent. These target allocations are monitored by the Investment Committee of Southern Union Company’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.

F-21

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Fair Value as of December 31,
	2010			2009
	(In thousands)
Asset Category:
Cash and cash equivalents		$	1,919		$	1,673
Mutual fund (1)			66,209			52,688
Total		$	68,128		$	54,361

___________________

(1)

This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2010, the fund was primarily comprised of approximately 17 percent large-cap U.S. equities, 4 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 2 percent in other investments. As of December 31, 2009, the fund was primarily comprised of approximately 16 percent large-cap U.S. equities, 3 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 4 percent in other investments.

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their fair value are based on active market quotes. See Note 2 – Summary of Significant Accounting Policies and Other Matters – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its other postretirement plan assets.

Contributions. The Company expects to contribute approximately $7.6 million to its other postretirement plans in 2011 and approximately $7.6 million annually thereafter until modified by rate case proceedings.

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

	Expected Benefits			Payments
	Before Effect of			Medicare Part D
Years	Medicare Part D			Subsidy Receipts			Net
	(In thousands)
2011		$	1,107		$	18		$	1,089
2012			1,627			24			1,603
2013			2,212			32			2,180
2014			2,814			69			2,745
2015			3,426			134			3,292
2016 - 2020			25,138			2,251			22,887

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

F-22

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the Acts) were signed into law. The Acts contain provisions that could impact the Company’s retiree medical benefits in future periods. However, the extent of that impact, if any, cannot be determined until additional interpretations of the Acts become available. Based on the analysis to date, the impact of provisions in the Acts that are reasonably determinable is not expected to have a material impact on the Company’s other postretirement benefit plans. Accordingly, a remeasurement of the Company’s postretirement benefit obligation is not required at this time. The Company will continue to assess the provisions of the Acts and may consider plan amendments in future periods to better align these plans with the provisions of the Acts.

Defined Contribution Plan

The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. The Company provided matching contributions of 100 percent of the first five percent of the participant’s compensation paid into the Savings Plan beginning January 16, 2009. Prior to that date, the Company provided matching contributions of 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Savings Plan. Company contributions are 100 percent vested after five years of continuous service. Company contributions to the Savings Plan during the years ended December 31, 2010, 2009 and 2008 were $4.5 million, $4.4 million and $2.8 million, respectively.

In addition, the Company makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan. The contribution amounts are determined as a percentage of compensation with the amount generally varying based on age and years of service. Company contributions are 100 percent vested after five years of continuous service. Company contributions to Retirement Power Accounts during the years ended December 31, 2010, 2009 and 2008 were $5.4 million, $5.5 million and $5 million, respectively.

9. Income Taxes

The following table provides a summary of the current and deferred components of income tax expense for the periods presented.

	Years Ended December 31,
	2010		2009		2008
	(In thousands)
Current income taxes
Federal	$	33,656	$	(25,027)	$	48,267
State		11,254		646		9,593
Total current income taxes		44,910		(24,381)		57,860

Deferred income taxes
Federal		50,551		102,871		32,589
State		1,340		13,610		6,083
Total deferred income taxes		51,891		116,481		38,672


Total income tax expense	$	96,801	$	92,100	$	96,532

Effective tax rate		40%		38%		39%

F-23

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company’s deferred tax assets (liabilities) at the dates indicated are as follows:

	December 31,
	2010			2009
	(In thousands)

Property, plant and equipment	$	(443,118	)	$	(380,829	)
Current assets		(2,719	)		(4,196	)
Investments		(253	)		(311	)
Other deferred debits		(17,748	)		(13,542	)
Other assets		(5,349	)		(2,222	)
Current liabilities		16,510			9,856
Deferred credits and other liabilities		35,822			23,210
Long term debt		2,850			6,959
Other		292			1,119
State deferred income taxes, net of federal tax effect		(38,702	)		(38,329	)
Net deferred income tax asset (liability)	$	(452,415	)	$	(398,285	)

Gross deferred tax liabilities	$	(507,895	)	$	(438,310	)
Gross deferred tax assets		55,480			40,025
Net deferred income tax asset (liability)	$	(452,415	)	$	(398,285	)

Non current deferred income tax asset (liability)	$	(466,309	)	$	(418,992	)
Current tax asset		13,894			20,707
Net deferred income tax asset (liability)	$	(452,415	)	$	(398,285	)

The actual income tax expense differs from the amount computed by applying the statutory federal tax rate of 35 percent to income before income taxes as follows:

	Years Ended December 31,
	2010			2009				2008
	(In thousands)

Computed statutory income tax expense at 35%		$	85,560		$	84,810			$	86,522
Changes in income taxes resulting from:
State income taxes, net of federal income tax benefit			8,436			9,267				10,190
Permanent differences and other			2,805			(1,977	)			(180	)
Total income tax expense		$	96,801		$	92,100			$	96,532

F-24

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the changes in unrecognized tax benefits for the periods presented is as follows:

	Years ended December 31,
	2010		2009
	(In thousands)

Beginning of the year	$	1,478	$	-

Additions:
Tax positions taken in prior years		-		1,167
Tax positions taken in current year		-		311

Reductions:
Lapse of statute of limitations		-		-
End of year	$	1,478	$	1,478

As of December 31, 2010, the Company has $ 1.5 million ($1.4 million, net of federal tax) of unrecognized tax benefits, none of which would impact the Company’s EITR if recognized. The Company does not expect that its unrecognized tax benefits will be reduced within the next twelve 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 period ended December 31, 2004 and prior years, except June 30, 2004, to the extent of $1.3 million of refund claims.

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 contracts may also be used from time to time. The Company recognizes all derivative instruments as assets or liabilities at fair value in the Consolidated Balance Sheet.

Interest Rate Contracts

The Company enters 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 enters 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. As of December 31, 2010, the Company had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the 2012 Term Loan. These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2010, approximately $11.8 million of net after-tax losses in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

F-25

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Treasury Rate Locks. As of December 31, 2010, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2010, approximately $165,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.

The Company had no asset derivative instruments at December 31, 2010 and 2009. The following table summarizes the fair value amounts of the Company’s liability derivative instruments and their location in the Consolidated Balance Sheet at the dates indicated.

		Fair Value (1)
	Balance Sheet	December 31,
	Location	2010		2009
		(In thousands)
Cash Flow Hedges:
Interest rate contracts	Other current liabilities	$	19,694	$	18,754
	Other noncurrent liabilities		4,652		13,975

		$	24,346	$	32,729

The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company’s consolidated financial statements for the periods presented.

	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Cash Flow Hedges: (1)
Change in fair value - increase in Accumulated other comprehensive loss,
excluding tax expense effect of $5,237, $3,051 and $7,815, respectively		$	13,027		$	7,589		$	19,478
Reclassification of unrealized loss (gain) from Accumulated other comprehensive
loss - increase (decrease) of Interest expense, excluding tax expense effect
of $8,711, $7,537 and $(3,138), respectively			21,679			18,760			(7,794	)

____________

(1)	See Note 6 – Comprehensive Income for additional related information.

F-26

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. Fair Value Measurement

The following tables set forth the Company’s liabilities that are measured at fair value on a recurring basis at the dates indicated.


				Fair Value Measurements Using Fair Value Hierarchy
	Fair Value as of			Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	December 31, 2010			(Level 1)			(Level 2)			(Level 3)
	(In thousands)

Liabilities:
Interest-rate swap derivatives		$	24,346		$	-		$	24,346		$	-
Total		$	24,346		$	-		$	24,346		$	-


				Fair Value Measurements Using Fair Value Hierarchy
	Fair Value as of			Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	December 31, 2009			(Level 1)			(Level 2)			(Level 3)
	(In thousands)
Liabilities:
Interest-rate swap derivatives		$	32,729		$	-		$	32,729		$	-
Total		$	32,729		$	-		$	32,729		$	-

The following table presents a reconciliation of the change in the Company’s Level 3 liabilities measured at fair value on a recurring basis using significant unobservable inputs for the period. There were no Level 3 assets or liabilities during the 2010 period.

	Level 3 Liabilities
	Interest-rate
	Derivatives
	(In thousands)

Balance at January 1, 2009	$	43,630
Total gains or losses (realized and unrealized):
Included in earnings		-
Included in other comprehensive income		4,787
Purchases and settlements, net		(12,696	)
Transfers out of Level 3		(35,721	)
Balance at December 31, 2009	$	-

The Company reclassified the interest-rate swap derivatives from Level 3 to Level 2 during 2009 as the Company obtained additional observable market data to corroborate the unobservable inputs to the model used to measure the fair value of these liabilities.

F-27

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

12. Property, Plant and Equipment

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

		December 31,
	Lives in Years	2010		2009
		(In thousands)

Transmission	5-46	$	2,239,762	$	2,130,979
Gathering	26		124,227		129,605
Underground storage	5-46		314,744		310,963
General plant - LNG	5-40		1,117,418		626,853
General plant - other (1)	2-40		156,274		155,422
Plant in service (2)			3,952,425		3,353,822
Construction work in progress			47,085		495,588
Total property, plant and equipment			3,999,510		3,849,410
Less accumulated depreciation and amortization			613,336		493,873
Net property, plant and equipment		$	3,386,174	$	3,355,537

_________________

(1) Includes capitalized computer software costs, CIAC and other intangible costs totaling:

Computer software cost	$	77,776	$	75,543
Less accumulated amortization		45,032		39,967
Net computer software costs		32,744		35,576

CIAC and other		52,857		52,926
Less accumulated amortization		5,906		4,427
Net CIAC and other		46,951		48,499
Total net intangible assets	$	79,695	$	84,075

(2) The composite weighted-average depreciation rates for the years ended December 31, 2010, 2009 and 2008 were 3.4 percent, 3.5 percent and 3.4 percent, respectively.

Amortization expense of capitalized computer software costs for the years ended December 31, 2010, 2009 and 2008 was $7.2 million, $9.4 million and $8.6 million, respectively. Amortization expense for CIAC and other intangible assets for the years ended December 31, 2010, 2009 and 2008 was $1.6 million, $1.6 million and $2 million, respectively. Computer software costs are amortized between 3 and 10 years. CIAC and other intangible assets are amortized between 2 and 40 years.

13. Stock-Based Compensation

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

F-28

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each stock option and SAR award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of Southern Union Company’s common stock. To the extent that volatility of Southern Union Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing share-based compensation expense in future periods. Additionally, the expected dividend yield is considered for each grant on the date of grant. The Company’s expected term of stock options and SARs granted was derived from the average midpoint between vesting and the contractual term. In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term. This change could impact the fair value of stock options and SARs granted in the future. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

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

	Years ended December 31,
	2010	2009	2008

Expected volatility	32.79% to 32.82%	32.22%	30.57%
Expected dividend yield	2.47	2.45%	2.19%
Risk-free interest rate	2.28% to 2.40%	2.72%	1.71%
Expected life	6 years	6 years	6 years

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

				Weighted-
	Shares			Average
	Under			Exercise
	Option			Price

Outstanding December 31, 2007		276,657		$	20.25
Granted		-			-
Exercised		(6,916	)		16.83
Forfeited		(221	)		16.83
Outstanding December 31, 2008		269,520		$	20.34
Granted		-			-
Exercised		(6,461	)		16.83
Forfeited		-			-
Outstanding December 31, 2009		263,059		$	20.42
Granted		-			-
Exercised		(59,156	)		20.92
Forfeited		-			-
Outstanding December 31, 2010		203,903		$	20.27

Exercisable December 31, 2008		192,827			20.39
Exercisable December 31, 2009		263,059			20.42
Exercisable December 31, 2010		203,903			20.27

F-29

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

				Weighted-Average
	SARs			Exercise Price

Outstanding December 31, 2007		145,192		$	28.38
Granted		268,954			12.55
Exercised		-			-
Outstanding December 31, 2008		414,146		$	18.10
Granted		147,004			21.64
Exercised		(4,347	)		12.55
Outstanding December 31, 2009		556,803		$	19.08
Granted		138,181			24.54
Exercised		(49,366	)		12.55
Forfeited		(28,815	)		19.35
Outstanding December 31, 2010		616,803		$	20.71

Exercisable December 31, 2008		60,764			28.31
Exercisable December 31, 2009		194,458			21.41
Exercisable December 31, 2010		308,799			20.90

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

As of December 31, 2010, there was $1.6 million of total unrecognized compensation cost related to non-vested SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 2.31 years. The total fair value of options and SARs vested as of December 31, 2010 was $3.7 million. Compensation expense recognized related to stock options and SARs totaled $778,000 ($480,000, net of tax), $1.1 million ($732,000, net of tax) and $1.1 million ($828,000, net of tax) for the years ended December 31, 2010, 2009 and 2008, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2010 was $3.5 million and $2.3 million, respectively. The intrinsic value of options and SARs exercised during the year ended December 31, 2010 was approximately $1 million.

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

F-30

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Number of
	Restricted Stock			Weighted-Average
	Equity Units			Grant Date
	Outstanding			Fair Value

Restricted shares at December 31, 2007		16,761		$	24.08
Granted		-			-
Released		(8,380	)		24.08
Forfeited		-			-
Restricted shares at December 31, 2008		8,381		$	24.08
Granted		-			-
Released		(8,381	)		24.08
Forfeited		-			-
Restricted shares at December 31, 2009		-		$	-

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

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

	Number of Restricted			Weighted-Average
	Stock Liability Units			Grant Date
	Outstanding			Fair Value

Restricted shares at December 31, 2007		110,118		$	28.35
Granted		132,452			12.75
Released		(42,556	)		28.31
Forfeited		-			-
Restricted shares at December 31, 2008		200,014		$	18.03
Granted		94,189			21.54
Released		(87,620	)		20.31
Forfeited		(463	)		25.06
Restricted shares at December 31, 2009		206,120		$	18.53
Granted		70,110			24.57
Released		(101,420	)		19.27
Forfeited		(8,940	)		18.49
Restricted shares at December 31, 2010		165,870		$	20.68

As of December 31, 2010, there was $3.8 million of total unrecognized compensation cost related to non-expired, restricted stock liability units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 2.11 years. The total fair value of restricted stock liability units that were released during the year ended December 31, 2010 was $2.2 million. Compensation expense recognized related to restricted stock equity and liability units totaled $2.2 million ($1.3 million, net of tax), $2.1 million ($1.3 million, net of tax) and $751,000 ($471,000, net of tax) for the years ended December 31, 2010, 2009 and 2008, respectively.

F-31

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company settled the restricted stock liability units released in 2010 with cash payments of $2.2 million.

14. Commitments and Contingencies

Litigation. 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, some of which involve substantial amounts. Where appropriate, the Company has established reserves in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including the Company, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010. The Company believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that the Company complied with the terms of its tariffs). In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case. The Company does not believe the outcome of the Will Price litigation will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The East End Project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana. Construction began in 2007 and was completed in the second quarter of 2008. PEPL is seeking recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project. Certain of the contractors have filed counterclaims against PEPL for alleged underpayments of approximately $18 million. The matter is pending in state court in Harris County, Texas. The trial date is currently set for May 2011. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Environmental Matters. The Company’s operations are 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.

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 developed and 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. The Company believes the total PCB remediation costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

F-32

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner. The costs incurred by the Company while performing such remediation is included in the estimates associated with probable environmental response actions.

The table below reflects the amount of accrued liabilities recorded at the dates indicated to cover probable environmental response actions.

	December 31,
	2010		2009
	(In thousands)

Current	$	4,273		$	5,891
Noncurrent		4,498			5,654
Total environmental liabilities	$	8,771		$	11,545

Air Quality Control. The Kansas Department of Health and Environment set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area. These measures must be revised to conform to the requirements of the EPA ozone standard discussed above. As such, the costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On December 18, 2009, PEPL received an information request from the EPA under Section 114(a) of the Federal Clean Air Act. The information request sought certain documents and records pertaining to maintenance activities and capital projects associated with combustion emission sources located at eight compressor stations in Illinois and Indiana. The complete responses were provided in February 2010.

In August 2010, 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 ten tons per year of any one Hazardous Air Pollutant (HAP) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five tons per year of all HAPs). Compliance is required by October 2013. It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016. This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

F-33

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nitrogen oxides are the primary air pollutant from natural gas-fired engines. Nitrogen oxide emissions may form ozone in the atmosphere. EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015. In January 2010, EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five ppb standard, with compliance required in 2014 or later.

In January 2010, 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 network may result in additional nitrogen dioxide non-attainment areas. In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

The Company is currently reviewing the potential impact of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule and proposed rules regarding HAPs and ozone 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. Costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

SPCC Rules. In October 2007, the EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements. On October 7, 2010, EPA amended the compliance date for certain facilities from November 10, 2010 to November 10, 2011. The Company is currently reviewing the impact of the modified regulations on its operations and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies.

2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Offshore transportation facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and gathering pipelines. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities were back in service.

In 2010, the Company recorded a reduction in Hurricane Ike related expenses of approximately $8.1 million and insurance recoveries of $4.1 million. The Company had previously recorded Hurricane Ike related expenses of approximately $12.3 million and $10.5 million, and insurance recoveries of $2.1 million and nil, in 2009 and 2008, respectively. The capital replacement and retirement expenditure estimates relating to Hurricane Ike have been reduced from $185 million to approximately $150 million and are expected to be completed in 2011. Approximately $134 million, $110 million and $23 million of the capital replacement and retirement expenditures were incurred as of December 31, 2010, 2009 and 2008, respectively. The Company anticipates reimbursement from OIL for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. OIL announced that it has reached the $750 million aggregate exposure limit and currently calculates its estimated payout amount at 70 percent or less based on estimated claim information it has received. OIL is currently making interim payouts at the rate of 50 percent of accepted claims. The Company received a total of $25.8 million and $36.7 million in 2010 and 2009, respectively, for claims submitted to date with respect to Hurricane Ike. The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.

F-34

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Controlled Group Pension Liabilities. Southern Union Company (including certain of its divisions) sponsors a number of defined benefit pension plans for employees. Under applicable pension and tax laws, upon being acquired by Southern Union, the Company became a member of Southern Union Company’s “controlled group” with respect to those plans and, along with Southern Union Company and any other members of that group, is jointly and severally liable for any failure by Southern Union (along with any other persons that may be or become a sponsor of any such plan) to fund any of these pension plans or to pay any unfunded liabilities that these plans may have if they are ever terminated. In addition, if any of the obligations of any of these pension plans is not paid when due, a lien in favor of that plan or the Pension Benefit Guaranty Corporation may be created against the assets of each member of Southern Union Company’s controlled group, including the Company and each of its subsidiaries. Based on the latest actuarial information available as of December 31, 2010, the aggregate amount of the projected benefit obligations of these pension plans was approximately $193.7 million and the estimated fair value of all of the assets of these plans was approximately $127 million.

See Note 3 – Regulatory Matters for other potential contingent matters applicable to the Company.

15. Quarterly Operations (Unaudited)

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

		Quarters Ended
2010	March 31			June 30			September 30			December 31
		(In thousands)

Operating revenues		$	186,675		$	187,090		$	186,563		$	209,122
Operating income			80,509			80,811			76,642			101,159
Net earnings			33,592			33,753			31,512			48,798

		Quarters Ended
2009	March 31			June 30			September 30			December 31
		(In thousands)

Operating revenues		$	192,295		$	172,615		$	176,092		$	208,159
Operating income			72,519			71,527			73,830			98,492
Net earnings			32,889			32,444			32,985			51,897

F-35

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm

To Southern Union Company and the Board of Managers of

Panhandle Eastern Pipe Line Company, LP:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of partners’ capital and comprehensive income and of cash flows present fairly, in all material respects, the financial position of Panhandle Eastern Pipe Line Company, LP and subsidiaries (the "Company") at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2011

F-36

PANHANDLE EASTERN PIPE LINE COMPANY, LP - FORM 10-K - February 25, 2011

Attached files

PANHANDLE EASTERN PIPE LINE COMPANY, LP Reports