suform10k_123108.htm

10-K 1 suform10k_123108.htm SOUTHERN UNION FORM 10-K, DECEMBER 31, 2008 suform10k_123108.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, 2008

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

Commission File No. 1-6407

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-0571592
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

Registrant's telephone number, including area code: (713) 989-2000

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

Title of each class	Name of each exchange on which registered
Common Stock, par value $1 per share	New York Stock Exchange
7.55% Depositary Shares	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 P No ____

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 P

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 P 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. ____

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 P Accelerated filer _____ Non-accelerated filer _____ 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 P

The aggregate market value of the Common Stock held by non-affiliates of the Registrant as of June 30, 2008 was $3,029,851,720 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2008). For purposes of this calculation, shares held by non-affiliates exclude only those shares beneficially owned by executive officers, directors and stockholders of more than 10% of the Common Stock of the Company.

The number of shares of the registrant's Common Stock outstanding on February 24, 2009 was 124,047,270.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders that is scheduled to be held on May 28, 2009 are incorporated by reference into Part III.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2008

Table of Contents

		Page
Glossary.	PART I	1
ITEM 1.	Business.	2
ITEM 1A.	Risk Factors.	17
ITEM 1B.	Unresolved Staff Comments.	28
ITEM 2.	Properties.	28
ITEM 3.	Legal Proceedings.	28
ITEM 4.	Submission of Matters to a Vote of Security Holders.	28
	PART II
ITEM 5.	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities.	29
ITEM 6.	Selected Financial Data.	32
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	33
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	61
ITEM 8.	Financial Statements and Supplementary Data.	64
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	64
ITEM 9A.	Controls and Procedures.	64
ITEM 9B.	Other Information.	66
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance.	66
ITEM 11.	Executive Compensation.	66
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	66
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	66
ITEM 14.	Principal Accountant Fees and Services.	66
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.	67
Signatures.		72
Index to the Consolidated Financial Statements.		F-1

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GLOSSARY

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

Bcf Billion cubic feet

Bcf/d Billion cubic feet per day

Btu British thermal units

CCE Holdings CCE Holdings, LLC

CEO Chief Executive Officer

CFO Chief Financial Officer

Citrus Citrus Corp.

Company Southern Union and its subsidiaries

EBIT Earnings before interest and taxes

EBITDA Earnings before interest, taxes, depreciation and amortization

EITR Effective income tax rate

EPA Environmental Protection Agency

Exchange Act Securities Exchange Act of 1934

FASB Financial Accounting Standards Board

FDOT/FTE Florida Department of Transportation/ Florida’s Turnpike Enterprise

FERC Federal Energy Regulatory Commission

Florida Gas Florida Gas Transmission Company, LLC

GAAP Accounting principles generally accepted in the United States of America

Grey Ranch Grey Ranch Plant, LP

IEPA Illinois Environmental Protection Agency

IPCB Illinois Pollution Control Board

IRS Internal Revenue Service

KDHE Kansas Department of Health and Environment

LNG Liquified natural gas

LNG Holdings Trunkline LNG Holdings, LLC

MDEP Massachusetts Department of Environmental Protection

MDPU Massachusetts Department of Public Utilities

MGPs Manufactured gas plants

MMBtu Million British thermal units

MMcf Million cubic feet

MMcf/d Million cubic feet per day

MPSC Missouri Public Service Commission

NGL Natural gas liquids

Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs Polychlorinated biphenyls

PEPL Panhandle Eastern Pipe Line Company, LP

PRPs Potentially responsible parties

RCRA Resource Conservation and Recovery Act

RIDEM Rhode Island Department of Environmental Management

SARs Stock appreciation rights

Sea Robin Sea Robin Pipeline Company, LLC

SEC Securities and Exchange Commission

Sid Richardson Energy Services Sid Richardson Energy Services, Ltd. and related entities

Southern Union Southern Union Company

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

SPCC Spill Prevention, Control and Countermeasure

SUGS Southern Union Gas Services

TBtu Trillion British thermal units

TCEQ Texas Commission on Environmental Quality

Transwestern Transwestern Pipeline Company, LLC

Trunkline Trunkline Gas Company, LLC

Trunkline LNG Trunkline LNG Company, LLC

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PART I

ITEM 1. Business.

OUR BUSINESS

Introduction

The Company was incorporated under the laws of the State of Delaware in 1932. The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

BUSINESS SEGMENTS

Reportable Segments

The Company’s operations, as reported, include three reportable segments:

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle and its 50 percent equity ownership interest in Florida Gas through Citrus.

·	The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and NGL in Texas and New Mexico. Its operations are conducted through SUGS.

·	The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. Its operations are conducted through Missouri Gas Energy and New England Gas Company.

The Company has other operations that support and expand its natural gas and other energy sales, which are not included in its reportable segments. These operations do not meet the quantitative thresholds for determining reportable segments and have been combined for disclosure purposes in the Corporate and Other category. For information about the revenues, operating income, assets and other financial information relating to the Corporate and Other category, see Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

The Company also provides various corporate services to support its operating businesses, including executive management, accounting, communications, human resources, information technology, insurance, internal audit, investor relations, environmental, legal, payroll, purchasing, risk management, tax and treasury.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. There were no material intersegment revenues during the years ended December 31, 2008, 2007 or 2006.

Transportation and Storage Segment

Services

The Transportation and Storage segment is primarily engaged in the interstate transportation of natural gas to Midwest, Southwest and Florida markets and related storage, and also provides LNG terminalling and regasification services. The Transportation and Storage segment’s operations are conducted through Panhandle and Florida Gas.

For the years ended December 31, 2008, 2007 and 2006, the Transportation and Storage segment’s operating revenues were $721.6 million, $658.4 million and $577.2 million, respectively. Earnings from unconsolidated investments related to Citrus were $74.9 million and $98.9 million for the years ended December 31, 2008 and 2007. For the year ended December 31, 2006, Earnings from unconsolidated investments contributed through CCE Holdings were $141.1 million. See discussion below in Citrus and CCE Holdings related to the Company’s increased ownership interest in Florida Gas through Citrus effective December 1, 2006.

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For information about operating revenues, EBIT, earnings from unconsolidated investments, assets and other financial information relating to the Transportation and Storage segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Transportation and Storage Segment and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

Panhandle. Panhandle owns and operates a large natural gas open-access interstate pipeline network. The pipeline network, consisting of the PEPL transmission system, the Trunkline transmission system and the Sea Robin transmission system, serves customers in the Midwest and Southwest 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 and Indiana to a point on the Indiana-Michigan border. 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 gas transmission and storage systems, Panhandle has five 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, Panhandle 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 or store natural gas, or LNG, in its facilities. Panhandle provides firm transportation services under contract to local distribution company customers and their affiliates, gas marketers, producers, other pipelines, electric power generators and a variety of end-users. Panhandle’s pipelines offer both firm and interruptible transportation to customers on a short-term or seasonal basis. Demand for gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and net earnings occurring in the traditional winter heating season in the first and fourth calendar quarters. Average reservation revenue rates realized by Panhandle are dependent on certain factors, including but not limited to rate regulation, customer demand for reserved capacity, capacity sold levels for a given period and, in some cases, utilization of capacity. Commodity revenues, which are more short-term sensitive in nature, are dependent upon a number of variable factors including weather, storage 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.

Citrus and CCE Holdings. On December 1, 2006, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Florida Gas from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern. On September 14, 2006, Energy Transfer Partners, LP (Energy Transfer) entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings held by GE Energy Financial Services and other investors. At the same time, Energy Transfer and CCE Holdings entered into a definitive redemption agreement (Redemption Agreement), pursuant to which Energy Transfer’s 50 percent ownership interest in CCE Holdings would be redeemed in exchange for 100 percent of the equity interests in Transwestern. Upon closing of the Redemption Agreement on December 1, 2006, the Company became the sole owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus which, in turn, owns 100 percent of Florida Gas.

Florida Gas is an open-access interstate pipeline system with a mainline capacity of 2.1 Bcf/d and approximately 4,900 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. Florida Gas’ pipeline system primarily receives natural gas from natural gas producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico. Florida Gas is the principal transporter of natural gas to the Florida energy market, delivering over 68 percent of the natural gas consumed in the state. In addition, Florida Gas’ pipeline system operates and maintains 60 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to diverse natural gas producing regions.

Florida Gas earns the majority of its revenue by entering into firm transportation contracts, providing capacity for customers to transport natural gas in its pipelines. Florida Gas also earns variable revenue from charges assessed on each unit of transportation provided.

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Demand for gas transmission service on the Florida Gas pipeline system is somewhat seasonal, with the highest throughput and related net earnings occurring in the summer period due to gas-fired generation loads in the second and third calendar quarters. The Company’s share of net earnings of Florida Gas and, until its transfer on December 1, 2006, Transwestern have been reported in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

The following table provides a summary of transportation volumes (in TBtu) associated with the reported results of operations for the periods presented:

	Year Ended		Year Ended		Year Ended
	December 31, 2008		December 31, 2007		December 31, 2006

Panhandle
PEPL		702		662		579
Trunkline		643		648		486
Sea Robin		126		144		115
Trunkline LNG Usage Volumes		9		261		149

Citrus and CCE Holdings (1)
Florida Gas		786		751		737
Transwestern		N/A		N/A		572	(2)

_______________________

(1)	Represents 100 percent of Transwestern and Florida Gas versus the Company's effective equity ownership interest.

The Company's effective equity ownership interests in Transwestern and Florida Gas were 50 percent and 25 percent,

respectively, until December 1, 2006, when the Company's interest in Transwestern was transferred to Energy

Transfer, increasing the Company's effective interest in Florida Gas to 50 percent.

(2)	Represents transportation volumes for Transwestern for the eleven-month period ended November 30, 2006.

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The following table provides a summary of certain statistical information associated with Panhandle and Florida Gas at December 31, 2008:

	As of
	December 31, 2008
Panhandle
Approximate Miles of Pipelines
PEPL		6,000
Trunkline		3,500
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		5.8
Trunkline		8.3
Sea Robin (1)		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts
PEPL		8.6
Trunkline		2.9

Florida Gas (2)
Approximate Total Miles of Pipelines		4,900
Peak Day Delivery Capacity (Bcf/d)		2.3
Average Number of Transportation Customers		132
Weighted Average Remaining Life of Firm Transportation Contracts		8.2

___________________

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

(2) Represents 100 percent of Florida Gas versus the Company's effective equity ownership interest of 50 percent at December 31, 2008.

Recent System Enhancements – Completed or Under Construction

LNG Terminal Enhancement. The Company commenced construction of an enhancement at its Trunkline LNG terminal in February 2007. This infrastructure enhancement project will increase send out flexibility at the terminal and lower fuel costs. Recent cost projections indicate the construction costs will be approximately $430 million, plus capitalized interest. The revised cost reflects increases in the quantities and cost of materials required, higher contract labor costs, including reduced productivity due to an August 2008 tropical storm and two September 2008 hurricanes, and an allowance for additional contingency funds, if needed. 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. The project is currently expected to be in operation in the third quarter of 2009. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement project contract, which runs 20 years from the in-service date. Approximately $351.3 and $178.3 million of costs, including capitalized interest, are included in the line item Construction work-in-progress at December 31, 2008 and 2007, respectively.

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Compression Modernization. The Company has received approval from FERC to modernize and replace various compression facilities on PEPL. Four stations have been completed as of December 31, 2008. Construction activities at two compressor stations are in progress and planned to be completed by the end of 2010, with the remaining cost for these stations estimated at approximately $43 million, plus capitalized interest. Approximately $19.7 million and $124.7 million of costs related to these projects are included in the line item Construction work-in-progress at December 31, 2008 and 2007, respectively.

Trunkline Field Zone Expansion. Trunkline completed construction on its field zone expansion project with the majority of the project put into service in late December 2007 and the remainder placed in-service in February 2008. The expansion project included the north Texas expansion and creation of additional capacity on Trunkline’s pipeline system in Texas and Louisiana to increase deliveries to Henry Hub. Trunkline has increased the capacity along existing rights-of-way from Kountze, Texas to Longville, Louisiana by approximately 625 MMcf/d with the construction of approximately 45 miles of 36-inch diameter pipeline. The project included horsepower additions and modifications at existing compressor stations. Trunkline has also created additional capacity to Henry Hub with the construction of a 13.5 mile, 36-inch diameter pipeline loop from Kaplan, Louisiana directly into Henry Hub. The Henry Hub lateral provides capacity of 1 Bcf/d from Kaplan, Louisiana to Henry Hub. Approximately $99.4 million and $178.3 million of costs for this project were closed to Plant in service in 2008 and 2007, respectively.

Phase VIII Expansion. Florida Gas, a wholly-owned subsidiary of Citrus, filed a certificate application on October 31, 2008 with FERC to construct an expansion to increase its natural gas capacity into Florida by approximately 820 MMcf/d (Phase VIII Expansion). The proposed Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. Pending FERC approval, which is expected in the latter half of 2009, Florida Gas anticipates an in-service date during 2011, at a currently estimated cost of approximately $2.4 billion, including capitalized equity and debt costs. To date, Florida Gas has entered into precedent agreements with shippers for transportation services for 25-year terms accounting for approximately 74 percent of the available expansion capacity which, depending on elections by one of the shippers, may increase to 83 percent of such capacity. For additional related information about the Citrus Phase VIII Expansion, see Item 8. Financial Statements and Supplementary Data, Note 9 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus – Phase VIII Expansion.

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Significant Customers

The following table provides the percentage of Transportation and Storage segment Operating revenues and related weighted average contract lives of Panhandle’s significant customers at December 31, 2008:

	Percent of			Weighted
	Segment Revenues			Average Life
	For Year Ended			of Contracts at
Customer	December 31, 2008 (1)			December 31, 2008

BG LNG Services		23	%	15 years (LNG, transportation)
ProLiance		12		9.6 years (transportation) 13.9 years (storage)
Other top 10 customers		26		N/A
Remaining customers		39		N/A
Total percentage		100	%

____________________

(1)	Panhandle has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s total consolidated operating revenues.

Panhandle’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 Panhandle’s tariffs, a temporary capacity release does not relieve the original customer from its payment obligations if the replacement customer fails to pay.

The following table provides information related to Florida Gas’ significant customers at December 31, 2008:

	Percent of
	Florida Gas'
	Total Operating			Weighted
	Revenues			Average Life
	For Year Ended			of Contracts at
Customer	December 31, 2008 (1)			December 31, 2008

Florida Power & Light		39	%		6.3 Years
Tampa Electric/Peoples Gas		16			9.3 Years
Other top 10 customers		29			N/A
Remaining customers		16			N/A
Total percentage		100	%

____________________

(1)	The Company accounts for its investment in Florida Gas through its equity investment in Citrus using the equity method. Accordingly, it reports its share of Florida Gas’ net earnings within Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Regulation and Rates

Panhandle and Florida Gas are subject to regulation by various federal, state and local governmental agencies, including those specifically described below. See also Item 1A. Risk Factors – Risks That Relate to the Company’s Transportation and Storage Segment and Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

FERC has comprehensive jurisdiction over PEPL, Trunkline, Sea Robin, Trunkline LNG, Southwest Gas and Florida Gas as natural gas companies within the meaning of the Natural Gas Act of 1938. For natural gas companies, FERC’s jurisdiction relates, among other things, to the acquisition, operation and disposition of assets and facilities and to the service provided and rates charged.

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

The following table summarizes the status of the rate proceedings applicable to the Transportation and Storage segment:

	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
Trunkline LNG	June 2001	Settlement effective January 2002 (1)
Southwest Gas Storage	August 2007	Settlement effective February 2008
Florida Gas	October 2003	Settlement effective March 2005 (2)

____________________

(1)	Settlement provides for a rate moratorium through 2015.

(2)	Rate moratorium was in effect until October 2007; required to file by October 2009.

Panhandle and Florida Gas are also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of gas pipelines.

For a discussion of the effect of certain FERC orders on Panhandle, see Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates – Panhandle.

Competition

The interstate pipeline systems of Panhandle and Florida Gas 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 Panhandle and Florida Gas.

Federal and state regulation of natural gas interstate pipelines has changed dramatically in the last two decades and could continue to change over the next several years. These regulatory changes have resulted, and will likely continue to result, in increased competition in the pipeline business. In order to meet these challenges, Panhandle and Florida Gas will need to adapt their marketing strategies, the types of transportation and storage services provided and their pricing and rates to address competitive forces.

FERC may authorize the construction of new interstate pipelines that are competitive with existing pipelines. Recently, Kinder Morgan completed its Rockies Express Pipeline project (REX) to transport large volumes of natural gas to the Midwest from the Rockies. REX is in the process of completing an expansion of its pipeline to make deliveries beyond the Midwest to Ohio, and potentially beyond. These pipelines and expansions could potentially compete with the Company.

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The Company’s 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 and Midwestern Gas Transmission.

Florida Gas competes in peninsular Florida with Gulfstream, a joint venture of Spectra Energy Corporation and The Williams Companies. Florida Gas also serves the Florida panhandle, where it competes with Gulf South Pipeline Company and the natural gas transportation business of Southern Natural Gas. Florida Gas faces competition, to a lesser degree, from alternate fuels, including residual fuel oil, in the Florida market, as well as from proposed LNG regasification facilities.

Gathering and Processing Segment

Services

SUGS’ operations consist of a network of approximately 4,900 miles of natural gas and NGL pipelines, four cryogenic processing plants with a combined capacity of 415 MMcf/d and five natural gas treating plants with a combined capacity of 640 MMcf/d. The principal assets of SUGS are located in the Permian Basin of Texas and New Mexico.

SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering or marketing the treated natural gas and/or processed NGL to a variety of markets. Its primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial end-users located primarily in the Gulf Coast and southwestern United States. SUGS receives natural gas for purchase or gathering and redelivery to market from more than 250 producers and suppliers. SUGS’ business is not generally seasonal in nature.

As a result of the operational flexibility built into SUGS’ gathering system and plants, it is able to offer a broad array of services to producers, including:

·	field gathering and compression of natural gas for delivery to its plants;

·	treating, dehydration, sulfur recovery and other conditioning; and

·	natural gas processing and marketing of natural gas and NGL.

For the years 2008 and 2007 and the 2006 period subsequent to the March 1, 2006 acquisition, SUGS’ gross margin (Operating revenues net of Cost of gas and other energy) was $304.1 million, $210.8 million and $172.2 million, respectively. For information about operating revenues, EBIT, assets and other financial information relating to the Gathering and Processing segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Gathering and Processing Segment and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

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Significant Customers

The following table provides the percentage of Gathering and Processing segment Operating revenues and related weighted average contract lives of SUGS’ significant customers at December 31, 2008:

	Percent of			Weighted
	Segment Revenues			Average Life
	For Year Ended			of Contracts at
Customer	December 31, 2008 (1)			December 31, 2008

Louis Dreyfus Energy Services, LP		11	%		5.8	(2)
Other top 10 customers		49			N/A
Remaining customers		40			N/A
Total percentage		100	%

_________________

(1)	SUGS has no single customer or group of customers under common control that accounted for ten percent or more of the Company’s total consolidated operating revenues.

(2)	The weighted average contract life excludes evergreen arrangements.

Natural Gas and NGL Connections

SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline Texas, El Paso Natural Gas Company, Energy Transfer Fuel, LP, DCP Guadalupe Pipeline, LP, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, LP, ONEOK Westex Transmission, LP, Public Service Company of New Mexico and Transwestern. Its major NGL pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

Natural Gas Supply Contracts

SUGS’ gas supply contracts primarily include fee-based, percent-of-proceeds, conditioning fee and wellhead purchase contracts which, as of December 31, 2008, comprised 51 percent, 38 percent, 9 percent and 2 percent by volume of its gas supply contracts, respectively. These gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years.

Following is a summary description of the gas supply contracts utilized by SUGS:

Fee-Based. Under fee-based arrangements, SUGS receives a fee or fees for one or more of the following services: gathering, compressing, dehydrating, treating or processing natural gas. The fee or fees are usually based on the volume or level of service provided to gather, compress, dehydrate, treat or process natural gas. While fee-based arrangements are generally not subject to commodity risk, certain operating conditions as well as certain provisions of these arrangements, including fuel recovery mechanisms, may subject SUGS to a limited amount of commodity risk.

Percent-of-Proceeds, Percent-of-Value or Percent-of-Liquids. Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue natural gas and NGL. The percent-of-value and percent-of-liquids arrangements are variations on the percent-of-proceeds structure. These types of arrangements expose SUGS to significant commodity price risk as the costs and revenues from the contracts are directly related to the price of natural gas and NGL.

Conditioning Fee. Conditioning fee arrangements provide a guaranteed minimum margin or fee on gas that must be processed for liquid hydrocarbon extraction in order to meet the quality specifications of the transmission pipelines. In addition to the minimum margin or fee, SUGS keeps all or a large percentage of the value of the NGL, if any. While the revenue earned is directly related to the processing value of the gas, SUGS is kept whole with a minimum value or fee in low processing spread environments.

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Keep-Whole and Wellhead. A keep-whole arrangement allows SUGS to keep 100 percent of the NGL produced and requires the return of the Btu or dollar value of the produced gas to the producer or owner. Since some of the gas is converted to NGL during processing, SUGS must compensate the producer or owner for the Btu shrinkage entailed in processing by replacing the Btu shrinkage or by paying an agreed value for the Btu utilized. These arrangements have the highest commodity price exposure for SUGS because the costs are dependent on the price of natural gas and the revenues are based on the price of NGL. As a result, SUGS benefits from these types of arrangements when the value of the NGL is high relative to the cost of the natural gas and is disadvantaged when the cost of the natural gas is high relative to the value of NGL. Rather than incurring the negative margins during an unfavorable processing environment, SUGS has the ability to eliminate its exposure to negative processing spreads by treating, dehydrating and blending the wellhead gas with leaner gas in order to meet downstream transmission pipeline specifications rather than processing the gas. In situations where the negative processing spread is eliminated, such contracts are referred to as wellhead contracts.

NGL Fractionation

SUGS contracts with ONEOK Hydrocarbon, LP (ONEOK) for fractionation of the NGL delivered into Chaparral, Louis Dreyfus and Chevron. The contract with ONEOK expires at the end of 2009.

SUGS has entered into a multi-year, firm fractionation agreement with Enterprise Products Operations, LLC (Enterprise), effective January 1, 2010, for the fractionation of the NGL delivered into Chaparral, Louis Dreyfus and Chevron. Enterprise owns several fractionation facilities in the Gulf Coast area.

Natural Gas Sales Contracts

SUGS’ gas sales contracts (physical) are consummated under North American Energy Standards Board or Gas Industry Standards Board contracts. Pricing is predominately based on Platt’s Gas Daily at El Paso-Permian or Waha pricing points. Some monthly baseload sales are made using FERC (Platt’s) pricing at El Paso-Permian or Waha pricing points.

NGL Sales Contracts

SUGS’ NGL sales contracts are predominately month-long in term with pricing at the monthly average Oil Price Information Service (OPIS) daily price for each NGL component. OPIS pricing is based on Mont Belvieu, Texas delivery points.

For information related to SUGS’ use of various derivative financial instruments to manage its commodity price risk and related operating cash flows, see Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

Regulation

SUGS’ facilities are not currently regulated by FERC but are subject to oversight by various other governmental agencies, including matters of asset integrity, safety and environmental protection. The relevant agencies include the U.S. EPA and its state counterparts, the Occupational Safety and Health Administration and the U.S. Department of Transportation’s Office of Pipeline Safety and its state counterparts. The Company believes that its operations are in material compliance with applicable safety and environmental statutes and regulations.

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Competition

SUGS competes with other midstream service providers and producer-owned midstream facilities in the Permian Basin. The Company’s direct competitors include Targa Resources Partners LP, DCP Midstream Partners, LP (formerly Duke Energy Field Services), Enterprise Texas Field Services, Anadarko Petroleum, Atlas Pipeline Partners, LP and Regency Gas Services. Industry factors that typically affect the Company’s ability to compete in this segment are:

·	contract fees charged;

·	pressures maintained on the gathering systems;

·	location of the gathering systems relative to competitors and producer drilling activity;

·	capacity and type of processing and treating available to SUGS and its competitors;

·	efficiency and reliability of the operations;

·	availability of third-party NGL transportation and fractionation capacity; and

·	delivery capabilities in each system and plant location.

Commodity prices for natural gas and NGL also play a major role in drilling activity on or near the Company’s gathering and processing systems. Generally, lower commodity prices will result in less producer drilling activity and, conversely, higher commodity prices will result in increased producer drilling activity.

SUGS has responded to these industry conditions by positioning and configuring its gathering and processing facilities to offer a broad array of services to accommodate the types and quality of natural gas produced in the region, while many competing systems provide but a single level of service.

Distribution Segment

Services

The Company’s Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, through Missouri Gas Energy, and Massachusetts, through New England Gas Company. The utilities serve over 550,000 residential, commercial and industrial customers through local distribution systems consisting of 9,119 miles of mains, 6,148 miles of service lines and 45 miles of transmission lines. The utilities’ natural gas rates and operations in Missouri and Massachusetts are regulated by the MPSC and the MDPU, respectively.

The utilities operations have historically been sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 67 percent of its operating revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

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The Distribution segment customers served, gas volumes sold or transported and weather-related information for the years ended December 31, 2008, 2007 and 2006 are as follows:

	Years Ended December 31,
	2008			2007			2006
Average number of customers:
Residential		485,971			483,753			482,882
Commercial		65,479			66,631			67,120
Industrial		122			122			129
Total average customers served		551,572			550,506			550,131
Transportation customers		1,579			1,517			1,473
Total average gas sales and transportation customers		553,151			552,023			551,604

Gas sales (MMcf):
Residential		43,018			37,916			34,946
Commercial		17,977			15,988			14,938
Industrial		427			504			517
Gas sales billed		61,422			54,408			50,401
Net change in unbilled gas sales		47			1,788			(1,025	)
Total gas sales		61,469			56,196			49,376
Gas transported		28,214			26,911			26,340
Total gas sales and gas transported		89,683			83,107			75,716

Gas sales revenues ($ in thousands):
Residential	$	559,293		$	495,464		$	472,926
Commercial		223,141			186,987			189,837
Industrial		9,352			10,900			11,140
Gas revenues billed		791,786			693,351			673,903
Net change in unbilled gas sales revenues		3,632			9,491			(25,681	)
Total gas sales revenues		795,418			702,842			648,222
Gas transportation revenues		14,135			12,669			12,253
Other revenues		12,120			16,598			8,246
Total operating revenues	$	821,673		$	732,109		$	668,721


Weather:
Missouri Utility Operations:
Degree days (1)		5,499			4,776			3,996
Percent of 10-year measure (2)		106	%		92	%		77	%
Percent of 30-year measure (2)		106	%		92	%		77	%

Massachusetts Utility Operations:
Degree days (1)		5,348			5,371			4,901
Percent of 10-year measure (2)		83	%		86	%		90	%
Percent of 30-year measure (2)		88	%		89	%		85	%

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(1) "Degree days" are a measure of the coldness of the weather experienced. A degree day is equivalent to each degree that the daily mean

temperature for a day falls below 65 degrees Fahrenheit.

(2) Information with respect to weather conditions is provided by the National Oceanic and Atmospheric Administration. Percentages of 10-

and 30-year measures are computed based on the weighted average volumes of gas sales billed. The 10- and 30-year measures are

used for consistent external reporting purposes. Measures of normal weather used by the Company's regulatory authorities to set rates

vary by jurisdiction. Periods used to measure normal weather for regulatory purposes range from 10 years to 30 years.

The Distribution segment has no single customer, or group of customers under common control, which accounted for ten percent or more of the Company’s Distribution segment or the Company’s total consolidated operating revenues for the years ended December 31, 2008, 2007 and 2006.

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For information about operating revenues, EBIT, assets and other financial information relating to the Distribution segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Distribution Segment and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

Gas Supply

The cost and reliability of natural gas service are dependent upon the Company's ability to achieve favorable mixes of long-term and short-term gas supply agreements and fixed and variable transportation contracts. The Company has been acquiring its natural gas supplies directly since the mid-1980s when interstate pipeline systems opened their systems for transportation service. The Company sought to ensure reliable service to customers by developing the ability to dispatch and monitor natural gas volumes on a daily, hourly or real-time basis.

For the year ended December 31, 2008, the majority of the natural gas requirements for the utility operations of Missouri Gas Energy were delivered under short- and long-term transportation contracts through five major pipeline companies and approximately twenty commodity suppliers. For this same period, the majority of the natural gas requirements for the Massachusetts utility operations of New England Gas Company were delivered under long-term contracts through five major pipeline companies and contracts with four commodity suppliers. Collectively, these contracts have various expiration dates ranging from 2010 through 2026. Missouri Gas Energy and New England Gas Company also have firm natural gas supply commitments under short- and long-term arrangements available for all of its service territories. Missouri Gas Energy and New England Gas Company hold contract rights to over 17 Bcf and 1 Bcf of storage capacity, respectively, to assist in meeting peak demands.

Like the natural gas industry as a whole, Missouri Gas Energy and New England Gas Company utilize natural gas sales and/or transportation contracts with interruption provisions, by which large volume users purchase natural gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the natural gas is needed by higher priority customers for load management. In addition, during times of special supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.

Regulation and Rates

The Company’s utilities are regulated as to rates, operations and other matters by the regulatory commissions of the states in which each operates. In Missouri, natural gas rates are established by the MPSC on a system-wide basis. In Massachusetts, natural gas rates for New England Gas Company are subject to the regulatory authority of the MDPU. For additional information concerning recent state and federal regulatory developments, see Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

The Company holds non-exclusive franchises with varying expiration dates in all incorporated communities where it is necessary to carry on its business as it is now being conducted. Fall River, Massachusetts; Kansas City, Missouri; and St. Joseph, Missouri are the largest cities in which the Company's utility customers are located. The franchise in Kansas City, Missouri expires in 2010. The Company fully expects this franchise to be renewed prior to its expiration. The franchises in Fall River, Massachusetts and St. Joseph, Missouri are perpetual.

Regulatory authorities establish gas service rates so as to permit utilities the opportunity to recover operating, administrative and financing costs, and the opportunity to earn a reasonable return on equity. Natural gas costs are billed to customers through purchased gas adjustment clauses, which permit the Company to adjust its sales price as the cost of purchased gas changes. This is important because the cost of natural gas accounts for a significant portion of the Company's total expenses. The appropriate regulatory authority must receive notice of such adjustments prior to billing implementation. The MPSC allows Missouri Gas Energy to make rate adjustments for purchased gas cost changes up to four times per year. The MDPU permits New England Gas Company to file for purchased gas cost rate adjustments at any time its projected revenues and purchased gas costs vary by more than five percent.

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The Company supports any service rate changes that it proposes to its regulators using an historic test year of operating results adjusted to normal conditions and for any known and measurable revenue or expense changes. Because the regulatory process has certain inherent time delays, rate orders in these jurisdictions may not reflect the operating costs at the time new rates are put into effect.

Except for Missouri Gas Energy’s residential customers, who are billed a fixed monthly charge for services provided and a charge for the amount of natural gas used, the Company’s monthly customer bills contain a fixed service charge, a usage charge for service to deliver natural gas, and a charge for the amount of natural gas used. Although the monthly fixed charge provides an even revenue stream, the usage charge increases the Company's revenue and earnings in the traditional heating load months when usage of natural gas increases.

In addition to public service commission regulation of its utility businesses, the Distribution segment is affected by other regulations, including pipeline safety regulations under the Natural Gas Pipeline Safety Act of 1968, the Pipeline Safety Improvement Act of 2002, safety regulations under the Occupational Safety and Health Act and various state and federal environmental statutes and regulations. The Company believes that its utility operations are in material compliance with applicable safety and environmental statutes and regulations.

The following table summarizes the rate proceedings applicable to the Distribution segment:

	Date of Last
Utility Operations	Rate Filing	Rate Proceedings Status (1)

Missouri	May 2006	MPSC rate order effective April 2007.

Massachusetts	July 2008	MDPU rate order effective February 2009.

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(1) For more information related to these rate filings, see Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

Competition

As energy providers, Missouri Gas Energy and New England Gas Company have historically competed with alternative energy sources available to end-users in their service areas, particularly electricity, propane, fuel oil, coal, NGL and other refined products. At present rates, the cost of electricity to residential and commercial customers in the Company’s regulated utility service areas generally is higher than the effective cost of natural gas service. There can be no assurance, however, that future fluctuations in gas and electric costs will not reduce the cost advantage of natural gas service.

Competition between the use of fuel oils, natural gas and propane, particularly by industrial and electric generation customers, has increased due to the volatility of natural gas prices and increased marketing efforts from various energy companies. Competition among the use of fuel oils, natural gas and propane is generally greater in the Company’s Massachusetts service area than in its Missouri service area. Nevertheless, this competition affects the nationwide market for natural gas. Additionally, the general economic conditions in the Company’s regulated utility service areas continue to affect certain customers and market areas, thus impacting the results of the Company’s operations. The Company’s regulated utility operations are not currently in significant direct competition with any other distributors of natural gas to residential and small commercial customers within their service areas.

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OTHER MATTERS

Environmental

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 18 – Commitments and Contingencies.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses. Insurance deductibles range from $100,000 to $10 million for the various policies utilized by the Company.

Employees

As of December 31, 2008, the Company had 2,413 employees, of whom 1,540 are paid on an hourly basis and 873 are paid on a salary basis. Unions represent approximately 49 percent of the 1,540 hourly paid employees. The table below sets forth the number of employees represented by unions for each division, as well as the expiration dates of the current contracts with the respective bargaining units.

	Number of employees
Company	Represented by Unions	Expiration of Current Contract

PEPL
USW Local 348	214	May 27, 2009

Missouri Gas Energy (1)
Gas Workers 781	204	April 30, 2009
IBEW Local 53	97	April 30, 2009
USW Local 5-267	26	April 30, 2009
USW Local 12561, 14228	142	April 30, 2009

New England Gas Company
UWUA Local 431	72	April 30, 2010

________________

(1)	The Company recently completed negotiation of a five year contract with the collective bargaining units representing certain of its Missouri Gas Energy employees. The contract will be effective on May 1, 2009. The contract has been ratified by the respective bargaining units.

As of December 31, 2008, the number of persons employed by each segment was as follows: Transportation and Storage segment – 1,179 persons; Gathering and Processing segment – 322 persons; Distribution segment – 802 persons; All Other subsidiary operations – 12 persons. In addition, the corporate employees of Southern Union totaled 98 persons.

The employees of Florida Gas are not employees of Southern Union or its segments and, therefore, were not considered in the employee statistics noted above. As of December 31, 2008, Florida Gas had 314 non-union employees.

The Company believes that its relations with its employees are good. From time to time, however, the Company may be subject to labor disputes. The Company did not experience any strikes or work stoppages during the years ended December 31, 2008, 2007 or 2006.

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Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information with the SEC as required. Any document that Southern Union 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. Southern Union’s SEC filings are also available at the SEC’s website at http://www.sec.gov and through 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.

The Company, by and through the audit committee of its board of directors, has adopted a Code of Ethics and Business Conduct (Code) designed to reflect requirements of the Sarbanes-Oxley Act of 2002, New York Stock Exchange rules and other applicable laws, rules and regulations. The Code applies to all of the Company’s directors, officers and employees. Any amendment to the Code will be posted promptly on Southern Union’s website.

Southern Union, by and through the corporate governance committee of its board of directors, also has adopted Corporate Governance Guidelines (Guidelines). The Guidelines set forth the responsibilities and standards under which the major board committees and management shall function. The Code, the Guidelines and the charters of the audit, corporate governance, compensation, finance and investment committees are posted on the Corporate Governance section of Southern Union’s website under “Governance Documents” and are available free of charge by calling Southern Union at (713) 989-2000 or by writing to:

Southern Union Company

Attn: Corporate Secretary

5444 Westheimer Road

Houston, TX 77056

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 occur, the Company’s business, financial condition, results of operations or cash flows could be materially and adversely affected.

RISKS THAT RELATE TO SOUTHERN UNION

Southern Union 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 Southern Union from meeting its future capital needs.

Southern Union has a significant amount of debt outstanding. As of December 31, 2008, consolidated debt on the Consolidated Balance Sheet totaled $3.7 billion outstanding, compared to total capitalization (long and short-term debt plus stockholders' equity) of $6.1 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 the Company 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-term 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.

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Global financial markets and economic conditions have been, and may continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and may continue to make, it more difficult to obtain funding.

As a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to current debt and reduced and, in some cases, ceased to provide funding to borrowers.

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 refinance its debt, grow its existing business, complete acquisitions 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, because of the need for certain state regulatory approvals in order to incur long-term debt and issue capital stock, the Company may not be able to access the capital markets on a timely basis. 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.

See additional related information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Financial Sector Exposure.

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

As of December 31, 2008, both Southern Union’s and Panhandle’s debt is rated Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. Fitch Ratings has rated Southern Union’s debt BBB- and Panhandle’s debt is rated BBB. If the Company’s credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect the Distribution segment’s relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

The Company’s growth strategy entails risk for investors.

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

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

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

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

·	continue expanding its existing operations.

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

·	its success in bidding for the opportunities;

·	its ability to assess the risks of the opportunities;

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

·	its access to financing on acceptable terms.

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

·	the risk of diverting management's attention from day-to-day operations;

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

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

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

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

Additionally, if the Company expands its existing operations, the success of any such expansion is subject to substantial risk and may expose the Company to significant costs. The Company cannot assure that its development or construction efforts will be successful.

The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. To the extent it issues shares of capital stock or other rights to purchase capital stock, including options or other rights, existing stockholders may be diluted and earnings per share may decrease. In addition, acquisitions or expansions may result in the incurrence of additional debt.

The Company depends on distributions from its subsidiaries and joint ventures to meet its needs.

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

The Company owns 50 percent of Citrus, the holding company for Florida Gas. As such, the Company cannot control or guarantee the receipt of distributions from Florida Gas through Citrus.

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 or NGL, 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. Although the Company maintains insurance coverage, such coverage may be inadequate to protect the Company from all expenses related to these risks.

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 operation, 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 and have tended to become increasingly strict over time. These laws and regulations have necessitated, and in the future may necessitate, increased capital expenditures and operating costs. In addition, certain environmental laws may result in liability without regard to fault concerning contamination at a broad range of properties, including currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of, waste.

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The Company is currently monitoring or remediating contamination at a number of its facilities and at third party 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 potentially responsible parties.

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 the War on Terror and the Iraq conflict may adversely impact the Company’s results of operations.

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

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

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

The success of the pipeline and gathering and processing businesses 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 Panhandle and Florida Gas. Additionally, third parties produce all the natural gas or NGL gathered and processed by SUGS, and third parties provide all of the fractionation services for SUGS. As a result, the volume of natural gas or NGL transported, stored, gathered, processed or fractionated 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, storage, gathering or processing rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity.

The success of the pipeline and gathering and processing businesses depends on the continued development of additional natural gas reserves in the vicinity of their facilities and their ability to access additional reserves to offset the natural decline from existing wells connected to their systems.

The amount of revenue generated by Panhandle and Florida Gas ultimately depends upon their access to reserves of available natural gas. Additionally, the amount of revenue generated by SUGS depends substantially upon the volume of natural gas or NGL gathered and processed. As the reserves available through the supply basins connected to these systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission, gathering or processing. Investments by

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third parties in the development of new natural gas reserves connected to the Company’s facilities depend on many factors beyond the Company’s control.

The financial soundness of the Company’s customers could affect its business and operating results.

As a result of the disruptions in the financial markets and other macro-economic challenges currently affecting 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. Any inability of the Company’s customers to pay for services may adversely affect the Company’s financial condition, results of operations and cash flows.

The pipeline and gathering and processing businesses revenues are generated under contracts that must be renegotiated periodically.

The revenues of Panhandle, Florida Gas and SUGS are generated under contracts that expire periodically. Although the Company will actively pursue the renegotiation, extension and/or replacement of most or 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.

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

During 2007 and 2008, the domestic energy industry experienced an unprecedented level of expansion activity, including new natural gas and LNG pipelines and compression infrastructure projects. In such an environment, requirements for material, equipment and construction resources could be constrained and result in significant industry-wide cost increases. While the Company’s project cost estimates include provisions for cost escalation, future costs are uncertain. Further, the Company’s construction productivity was adversely affected in 2007 and 2008 by contractor employee turnover and shortages of experienced contractor staff, as well as other factors beyond the Company’s control, such as weather conditions. These factors could affect the ultimate cost and timing of the Company’s expansion projects.

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

The ability of Panhandle, Florida Gas or SUGS to operate in certain geographic areas will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion projects. Even for Panhandle and Florida Gas, which generally have the right of eminent domain, the Company cannot assure that it will be able to acquire all of the necessary new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants 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 grants materially increase or the Company is unable to obtain or extend the rights-of-way grants timely.

RISKS THAT RELATE TO THE COMPANY’S TRANSPORTATION AND STORAGE BUSINESS

The Company’s transportation and storage 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 Panhandle and Florida Gas 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 related to the importation of LNG.

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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 25 years 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 deemed unrecoverable in rates.

The Company’s transportation and storage business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, outside contractor services costs 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.

The pipeline businesses are subject to competition.

The interstate pipeline businesses of Panhandle and Florida Gas 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 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 Panhandle and Florida Gas.

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 be inadequate to cover all liabilities or expenses incurred or revenues lost.

Fluctuations in energy commodity prices could adversely affect the pipeline businesses.

If natural gas prices in the supply basins connected to the pipeline systems of Panhandle and Florida Gas are higher than prices in other natural gas producing regions able to serve the Company’s customers, the volume of 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.

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The pipeline businesses are dependent on a small number of customers for a significant percentage of their sales.

Panhandle’s top three customers accounted for 42 percent of its 2008 revenue. Florida Gas’ top two customers accounted for 55 percent of its 2008 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 Company is exposed to the credit risk of its transportation and storage customers in the ordinary course of business.

Transportation service contracts obligate customers to pay charges for reservation of capacity, or reservation charges, regardless of whether they transport natural gas on the pipeline system. Customers with natural gas imbalances on the pipeline system may also owe natural gas to the Company. As a result, the Company’s profitability will depend upon the continued financial performance and creditworthiness of its customers rather than just upon the amount of capacity provided under service contracts.

Generally, customers are rated investment grade or, as permitted by the Company’s tariff, are required to make pre-payments or deposits, or to provide collateral, if their creditworthiness does not meet certain criteria. Nevertheless, the Company cannot predict to what extent future declines in customers' creditworthiness may negatively impact its business.

RISKS THAT RELATE TO THE COMPANY’S GATHERING AND PROCESSING BUSINESS

The Company’s gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas and NGL gathering and processing operations conducted at SUGS are not regulated for cost-based ratemaking purposes and may potentially have a higher level of risk in recovering incurred costs than the Company’s regulated operations.

Although SUGS operates in an unregulated market, the business is subject to certain regulatory risks, most notably environmental and safety regulations. Moreover, the Company cannot predict when additional legislation or regulation might affect the gathering and processing industry, nor the impact of any such changes on the Company’s business, financial position, results of operations or cash flows.

The Company’s gathering and processing business is subject to competition.

The gathering and processing industry is expected to remain highly competitive. Most customers of SUGS have access to more than one gathering and/or processing system. The Company’s ability to compete depends on a number of factors, including the infrastructure and contracting strategies of competitors in the Company’s gathering region; the efficiency, quality and reliability of the Company’s plant and gathering system.

In addition to SUGS’ current competitive position in the gathering and processing industry, its business is subject to pricing risks associated with changes in the supply of, and the demand for, natural gas and NGL. If natural gas or NGL prices in the producing areas connected to the Company’s gathering system are comparatively higher than prices in other natural gas producing regions, the volume of gas that SUGS chooses to process may, to the extent that is operationally feasible, be reduced to maximize returns to the Company. Similarly, since the demand for natural gas or NGL is primarily a function of commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions and service costs, the volume processed, or the NGL extracted during processing, by SUGS may be reduced based on these market conditions on a daily basis after analysis by the Company.

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The Company’s profit margin in the gathering and processing business is highly dependent on energy commodity prices.

SUGS’ gross margin is largely derived from (a) percentage of proceeds arrangements based on the volume of gas gathered and/or NGL recovered through its facilities and (b) specified fee arrangements for a range of services. Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue gas and NGL. The percent-of-proceeds arrangements, in particular, expose SUGS’ revenues and cash flows to risks associated with the fluctuation of the price of natural gas, NGL, crude oil and their relationships to each other.

The markets and prices for natural gas and NGL depend upon factors beyond the Company’s control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions, and other factors, including:

·	the impact of seasonality and weather;

·	general economic conditions;

·	the level of domestic crude oil and natural gas production and consumption;

·	the level of worldwide oil production and consumption;

·	the availability and level of natural gas and NGL storage;

·	the availability of imported natural gas, NGL and crude oil;

·	actions taken by foreign oil and natural gas producing nations;

·	the availability of local, intrastate and interstate transportation systems;

·	the availability of NGL transportation and fractionation capacity;

·	the availability and marketing of competitive fuels;

·	the impact of energy conservation efforts; and

·	the extent of governmental regulation and taxation.

To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e. receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps and exchange-traded futures and options. These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are highly effective in offsetting changes in physical market commodity prices and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations. For information related to derivative financial instruments, see Item 8. Financial Statements and Supplementary Data – Note 11 Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect the Company’s gathering and processing business.

The NGL products the Company produces have a variety of applications, including for use as heating fuels, petrochemical feed stocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather, severe weather such as hurricanes causing damage to Gulf Coast petrochemical facilities or other reasons, could result in a decline in the value of the NGL products the Company sells and/or reduce the volume of NGL products the Company produces.

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Operational risks are involved in operating a gathering and processing business.

Numerous operational risks are associated with the operation of a natural gas gathering and processing business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

The Company does not typically obtain independent evaluations of natural gas reserves dedicated to its gathering and processing business, potentially resulting in future volumes of natural gas available to the Company being less than anticipated.

The Company does not typically obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, the Company does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated lives of the reserves connected to the Company’s gathering systems are less than anticipated and the Company is unable to secure additional sources of natural gas, then the volumes of natural gas in the future could be less than anticipated. A decline in the volumes of natural gas and associated NGL in the Company’s gathering and processing business could have a material adverse effect on its business.

The Company’s gathering and processing business accepts some credit risk in dealing with customers.

SUGS derives its revenues from customers engaged primarily in the natural gas and utility industries and extends payment credit to these customers. SUGS’ accounts receivable primarily consist of mid- to large-size domestic customers with credit ratings of investment grade or better. Moreover, SUGS maintains trading relationships with counterparties that include reputable U.S. broker-dealers and other financial institutions and evaluates the ability of each counterparty to perform under the terms of the derivative agreements. Nevertheless, the Company cannot predict to what extent future declines in customers’ creditworthiness may negatively impact its business.

The Company depends on one natural gas producer for a significant portion of its supply of natural gas. The loss of this producer or the replacement of its contracts on less favorable terms could result in a decline in the Company’s volumes and/or gross margin.

SUGS’ largest natural gas supplier for the year ended December 31, 2008 accounted for approximately 14.7 percent of the Company’s wellhead throughput under multiple contracts. The loss of all or even a portion of the natural gas volumes supplied by this producer or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce the Company’s gross margin. Although this producer represents a large volume of natural gas, the gross margin per unit of volume is significantly lower than the average gross margin per unit of volume on the Company’s gathering and processing system due to the lack of need for services required to make the natural gas merchantable (e.g. high pressure, low NGL content, essentially transmission pipeline quality natural gas).

RISKS THAT RELATE TO THE COMPANY’S DISTRIBUTION BUSINESS

The distribution business is highly regulated and the Company’s revenues, operating results and financial condition may fluctuate with the distribution business’ ability to achieve timely and effective rate relief from state regulators.

The Company’s distribution business is subject to regulation by the MPSC and the MDPU. These authorities regulate many aspects of the Company’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that can be charged to customers and the maximum rates of return that the Company is allowed to realize. The ability to obtain rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion.

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The distribution business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, changes in the provision for the allowance for doubtful accounts associated with volatile natural gas costs and other operating costs. The profitability of regulated operations depends on the business’ ability to pass through to its customers costs related to providing them service. To the extent that such operating costs increase in an amount greater than that for which rate recovery is allowed, this differential could impact operating results until the business files for and is allowed an increase in rates. The lag between an increase in costs and the rate relief obtained from the regulators 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, regulators may prevent the business from passing along some costs in the form of higher rates.

The distribution business’ operating results and liquidity needs are seasonal in nature and may fluctuate based on weather conditions and natural gas prices.

The natural gas distribution business is a seasonal business and is subject to weather conditions. The utilities’ operations have historically been sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 67 percent of its operating revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

The business is also subject to seasonal and other variations in working capital due to changes in natural gas prices and the fact that customers pay for the natural gas delivered to them after they use it, whereas the business is required to pay for the natural gas before delivery. As a result, fluctuations in weather between years may have a significant effect on results of operations and cash flows. In years with warm winters, revenues may be adversely affected.

Operational risks are involved in operating a distribution business.

Numerous risks are associated with the operations of a natural gas distribution business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of suppliers’ processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

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CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS

The disclosure and analysis in this Form 10-K contains forward-looking statements that set forth anticipated results based on management’s plans and assumptions. From time to time, Southern Union also provides forward-looking statements in other materials it releases to the public as well as oral forward-looking statements. Such statements give the Company’s current expectations or forecasts of future events; they do not relate strictly to historical or current facts. Southern Union has tried, wherever possible, to identify such statements by using words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “will” and similar expressions in connection with any discussion of future operating or financial performance. In particular, these include statements relating to future actions, future performance or results of current and anticipated services, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

Southern Union cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent in its plans and assumptions. Achievement of future results is subject to risks, uncertainties and potentially inaccurate assumptions. If known or unknown risks or uncertainties should materialize, or if underlying assumptions should prove inaccurate, actual results could differ materially from past results and those anticipated, estimated or projected. Readers should bear this in mind as they consider forward-looking statements.

Southern Union undertakes no obligation to update publicly forward-looking statements, whether as a result of new information, future events or otherwise. Readers are advised, however, to consult any further disclosures the Company makes on related subjects in its Form 10-K, Form 10-Q and Form 8-K reports to the SEC. Also note that Southern Union provides the following cautionary discussion of risks, uncertainties and possibly inaccurate assumptions relevant to its businesses. These are factors that, individually or in the aggregate, management believes could cause the Company’s actual results to differ materially from expected and historical results. Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.

Factors that could cause actual results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to, the following:

·	changes in demand for natural gas or NGL and related services by the Company’s 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 or NGL as well as electricity, oil, coal and other bulk materials and chemicals;

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

·	changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies affecting or involving Southern Union, 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 is introduced to Southern Union’s business and the resulting effect on revenues;

·	the outcome of pending and future litigation;

·	the Company’s ability to comply with or to challenge successfully existing or new environmental regulations;

·	unanticipated environmental liabilities;

·	the Company’s exposure to highly competitive commodity businesses through its Gathering and Processing segment;

·	the Company’s 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 Company’s 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, gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;

·	exposure to customer concentration 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 debt securities of Southern Union or any of its subsidiaries;

·	changes in interest rates and other general capital markets conditions, and in the Company’s ability to continue to access the capital markets;

·	acts of nature, sabotage, terrorism or other acts causing damage greater than the Company’s insurance coverage limits;

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

·	other risks and unforeseen events.

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ITEM 1B. Unresolved Staff Comments.

N/A

ITEM 2. Properties.

TRANSPORTATION AND STORAGE

See Item 1. Business – Business Segments – Transportation and Storage Segment for information concerning the general location and characteristics of the important physical properties and assets of the Transportation and Storage segment.

GATHERING AND PROCESSING

See Item 1. Business – Business Segments – Gathering and Processing Segment for information concerning the general location and characteristics of the important physical properties and assets of the Gathering and Processing segment.

DISTRIBUTION

See Item 1. Business – Business Segments – Distribution Segment for information concerning the general location and characteristics of the important physical properties and assets of the Distribution segment.

OTHER

The Company’s other businesses primarily consist of PEI Power Corporation, a wholly-owned subsidiary of the Company, which has ownership interests in two electric power plants that share a site in Archbald, Pennsylvania. PEI Power Corporation wholly owns one plant, a 25 megawatt electric cogeneration facility fueled by a combination of natural gas and methane, and owns 49.9 percent of the second plant, a 45 megawatt natural gas-fired electric generation facility, through a joint venture with Cayuga Energy.

ITEM 3. Legal Proceedings.

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Item 8. Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies. Also see Item 1A. Risk Factors – Cautionary Factors That May Affect Future Results.

ITEM 4. Submission of Matters to a Vote of Security Holders.

N/A

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PART II

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

MARKET INFORMATION

Southern Union’s common stock is traded on the New York Stock Exchange under the symbol “SUG.” The high and low sales prices for shares of Southern Union common stock and the cash dividends per share declared in each quarter since January 1, 2007 are set forth below:

	Dollars per share
	High		Low		Dividends


December 31, 2008	$	20.69	$	10.60	$	0.15
September 30, 2008		27.24		19.70		0.15
June 30, 2008		27.73		23.26		0.15
March 31, 2008		29.77		21.56		0.15


December 31, 2007	$	33.01	$	28.46	$	0.15
September 30, 2007		35.05		27.20		0.10
June 30, 2007		35.50		30.35		0.10
March 31, 2007		30.50		26.81		0.10

Provisions in certain of Southern Union’s long-term debt and bank credit facilities limit the issuance of dividends on capital stock. Under the most restrictive provisions in effect, Southern Union may not declare or issue any dividends on its common stock or acquire or retire any of Southern Union’s common stock, unless no event of default exists and the Company meets certain financial ratio requirements, which presently are met. Southern Union’s ability to pay cash dividends may be limited by certain debt restrictions at Panhandle and Citrus that could limit Southern Union’s access to funds from Panhandle and Citrus for debt service or dividends. For additional related information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Financing Activities – Dividend Restrictions and Item 8. Financial Statements and Supplementary Data, Note 10 – Stockholders’ Equity and Note 13 – Debt Obligations.

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COMMON STOCK PERFORMANCE GRAPH

The following performance graph compares the performance of Southern Union’s common stock to the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Bloomberg U.S. Pipeline Index. The comparison assumes $100 was invested on December 31, 2003, in Southern Union common stock, the S&P 500 Index and in the Bloomberg U.S. Pipeline Index. Each case assumes reinvestment of dividends.

	2003	2004	2005	2006	2007	2008
Southern Union	100	137	142	170	181	83
S&P 500 Index	100	111	116	135	142	90
Bloomberg U.S. Pipeline Index	100	131	173	201	238	146

The following companies are included in the Bloomberg U.S. Pipeline Index used in the graph: Crosstex Energy Inc., El Paso Corp., Enbridge Inc., Kinder Morgan Management LLC, National Fuel Gas Co., Oneok Inc., Promigas SA, Spectra Energy Corp., TransCanada Corp., and Williams Companies Inc.

HOLDERS

As of February 24, 2009, there were 6,067 holders of record of Southern Union’s common stock, and 124,047,270 shares of Southern Union’s common stock were issued and outstanding. The holders of record do not include persons whose shares are held of record by a bank, brokerage house or clearing agency, but do include any such bank, brokerage house or clearing agency that is a holder of record.

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EQUITY COMPENSATION PLANS

Equity compensation plans approved by stockholders include the Southern Union Company Second Amended and Restated 2003 Stock and Incentive Plan and the 1992 Long-Term Stock Incentive Plan (1992 Plan). While Southern Union options are still outstanding under the 1992 Plan, the 1992 Plan expired on July 1, 2002 and no shares are available for future grant thereunder. Under both plans, stock options are issued having an exercise price equal to the fair market value of the common stock on the date of grant and typically vest ratably over three, four or five years.

The following table sets forth the number of outstanding options and SARs, the weighted-average exercise price of outstanding options and the number of shares remaining available for issuance as of December 31, 2008:

	Number of Securities
	to Be Issued Upon	Weighted-Average	Number of Securities
	Exercise of	Exercise Price of	Remaining Available for
	Outstanding	Outstanding	Future Issuance Under
Plan Category	Options/SARs	Options/SARs	Equity Compensation Plans
Plans approved by stockholders	2,647,461 (1)	$19.24	3,933,940

_________________

(1) Excludes 363,185 shares of restricted stock that were outstanding at December 31, 2008.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table presents information with respect to purchases during the three months ended December 31, 2008 made by Southern Union or any “affiliated purchaser” of Southern Union (as defined in Rule 10b-18(a)(3)) of equity securities that are registered pursuant to Section 12 of the Exchange Act.

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Average Price Paid per Share		Maximum Number of Shares that May Yet Be Purchased Under the Publicly Announced Plans or Programs (2)
October 1, 2008 through October 31, 2008		6,233	$	13.85		198,900	$	21.75
November 1, 2008 through November 30, 2008		673		13.36		-		-
December 1, 2008 through December 31, 2008		5,050		12.38		-		-
Total		11,956	$	13.20		198,900	$	21.75		4,600,013

__________________

(1)	Shares of common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans).

(2)

On May 22, 2008, the Company announced that the Finance Committee of its Board of Directors had authorized a program to repurchase a portion of the depositary shares representing ownership of its Preferred Stock at the Company’s discretion in the open market and/or through privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors. Effective October 8, 2008, the Company has the right to redeem all of the Preferred Stock at par upon applicable notice. See Item 8. Financial Statements and Supplementary Data, Note 12 – Preferred Securities for additional information related to the repurchase of depositary shares.

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ITEM 6. SELECTED FINANCIAL DATA.

											For the			For the
	For the years ended										six months ended			year ended
	December 31,										December 31,			June 30,
	2008		2007		2006 (1)			2005			2004 (2)			2004
	(In thousands of dollars, except per share amounts)

Total operating revenues	$	3,070,154	$	2,616,665	$	2,340,144		$	1,266,882		$	517,849		$	1,149,268
Earnings from unconsolidated
investments		75,030		100,914		141,370			70,742			4,745			200
Net earnings (loss):
Continuing operations (3)		279,412		211,346		199,718			135,731			(1,635	)		51,729
Discontinued operations (4)		-		-		(152,952	)		(132,413	)		7,723			49,610
Available for common stockholders		279,412		211,346		46,766			3,318			6,088			101,339
Net earnings (loss) per diluted
common share (5):
Continuing operations		2.26		1.75		1.70			1.20			(0.02	)		0.63
Discontinued operations		-		-		(1.30	)		(1.17	)		0.09			0.61
Available for common stockholders		2.26		1.75		0.40			0.03			0.07			1.24
Total assets		7,997,907		7,397,913		6,782,790			5,836,819			5,568,289			4,572,458
Stockholders’ equity		2,367,952		2,205,806		2,050,408			1,854,069			1,497,557			1,261,991
Current portion of long-term debt and
capital lease obligation		60,623		434,680		461,011			126,648			89,650			99,997
Long-term debt and capital lease
obligation, excluding current portion		3,257,434		2,960,326		2,689,656			2,049,141			2,070,353			2,154,615
Cash dividends declared on common
stock (6)		74,384		53,968		46,289			-			-			-

___________________

(1)

Includes the impact of significant acquisitions and sales of assets. See Item 8. Financial Statements and Supplementary Data, Note 3 – Acquisitions and Sales and Item 8. Financial Statements and Supplementary Data, Note 19 – Discontinued Operations for information related to the acquisitions and sales.

(2)

The Company’s investment in CCE Holdings, which was accounted for using the equity method until it became a wholly-owned subsidiary on December 1, 2006, was included in the Company’s Consolidated Balance Sheet at December 31, 2004. The Company’s share of net income from CCE Holdings was recorded as Earnings from unconsolidated investments in the Company’s Consolidated Statement of Operations since its acquisition on November 17, 2004. For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisition is not comparable to the year of acquisition. See Item 8. Financial Statements and Supplementary Data, Note 3 – Acquisitions and Sales – CCE Holdings Transactions for information related to CCE Holding becoming a wholly-owned subsidiary of the Company on December 1, 2006.

(3)

Net earnings from continuing operations are net of dividends on preferred stock of $12.2 million, $17.4 million, $17.4 million, $17.4 million, $8.7 million and $12.7 million for the years ended December 31, 2008, 2007, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively. Additionally, net earnings from continuing operations are net of the $3.5 million Loss on extinguishment of preferred stock applicable to the year ended December 31, 2008. For additional related information, see Item 8. Financial Statements and Supplementary Data, Note12 – Preferred Securities.

(4)

On August 24, 2006, the Company completed the sales of the assets of its PG Energy natural gas distribution division to UGI Corporation and the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA. These dispositions were accounted for as discontinued operations in the Consolidated Statement of Operations. For additional related information, see Item 8. Financial Statements and Supplementary Data, Note 19 – Discontinued Operations.

(5)	Earnings per share for all periods presented were computed based on the weighted average number of shares of common stock and common stock equivalents outstanding during the period, adjusted for the five percent stock dividends distributed on September 1, 2005, August 31, 2004 and July 31, 2003.

(6)

No cash dividends on common stock were paid during the reporting periods prior to 2006. See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Item 8. Financial Statements and Supplementary Data, Note 10 – Stockholders’ Equity – Dividends.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

This 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 Southern Union’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 on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and NGL in a safe, efficient and dependable manner. The Company’s reportable business segments are determined based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

BUSINESS STRATEGY

The Company’s strategy is focused on achieving profitable growth and enhancing stockholder value. The Company seeks to balance its entrepreneurial focus with respect to maximizing cash and capital appreciation return to shareholders with preservation of its investment grade credit ratings. The key elements of its strategy include the following:

Expanding through development of the Company’s existing businesses. The Company will continue to pursue growth opportunities through the expansion of its existing asset base, while maintaining its focus on providing safe and reliable service to its customers. In each of its business segments, the Company identifies opportunities for organic growth through incremental volumes and system enhancements to generate operating efficiencies. In its interstate transmission and distribution businesses, the Company seeks rate increases and/or improved rate design as appropriate to achieve a fair return on its investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Investing Activities for information related to the Company’s principal capital expenditure projects. See Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates for information related to ratemaking activities.

·	New initiatives. The Company regularly assesses strategies to enhance stockholder value, including diversification of earning sources through strategic acquisitions or joint ventures in the diversified natural gas industry.

·	Disciplined capital expenditures and cost containment programs. The Company will continue to focus on system optimization and cost savings while making prudent capital expenditures across its base of energy infrastructure assets.

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RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:

·	items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;

·	income taxes;

interest;

·	dividends on preferred stock; and

·	loss on extinguishment of preferred stock.

EBIT may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders.

	Years Ended December 31,
	2008			2007			2006
	(In thousands)
EBIT:
Transportation and storage segment (1)	$	404,834		$	407,459		$	431,959
Gathering and processing segment		145,363			65,368			62,630
Distribution segment (1)		61,418			62,195			36,349
Corporate and other (1)		(4,281	)		(7,906	)		5,435
Total EBIT		607,334			527,116			536,373
Interest expense		207,408			203,146			210,043
Earnings from continuing operations before
income taxes		399,926			323,970			326,330
Federal and state income taxes		104,775			95,259			109,247
Earnings from continuing operations		295,151			228,711			217,083

Discontinued operations:
Loss from discontinued operations
before income taxes		-			-			(2,369	)
Federal and state income taxes		-			-			150,583
Loss from discontinued operations		-			-			(152,952	)
Preferred stock dividends		12,212			17,365			17,365
Loss on extinguishment of preferred stock		3,527			-			-

Net earnings available for common stockholders	$	279,412		$	211,346		$	46,766

_____________________

(1)

In the fourth quarter of 2008, the Company ceased including the management and royalty fees charged by Southern Union to its Transportation and Storage segment in its evaluation of segment results as it was no longer deemed necessary by executive management. The Company had not previously included management and royalty fees in the evaluation of its other reportable segments. Additionally, in the fourth quarter of 2008, the Company commenced allocating certain corporate administrative services costs to the Distribution segment. Previously, the corporate administrative services costs allocation was limited to the Transportation and Storage and Gathering and Processing segments. Executive management determined that such allocation to all of the Company's reportable segments would enable it to better measure and evaluate the performance of each of its reportable segments. The allocation to the Distribution segment was $9.5 million, representing the estimated 2008 annual allocation provided to the Distribution segment. The administrative services allocation was primarily based upon each reportable segment's pro-rata share of combined net investment, margin and certain expenses. Management believes that the allocation method and underlying assumptions utilized by the Company were reasonable.

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For comparability between reporting periods purposes, the 2007 and 2006 annual periods have been recast as indicated below to (i) exclude the management and royalty fee charged to the Transportation and Storage segment and (ii) include the corporate administrative services allocation to the Distribution segment.

					Recast Adjustments
	EBIT as Reported				Increase (Decrease)						Recast EBIT
Segment	2007		2006		2007			2006			2007			2006
	(In thousands)

Transportation and Storage	$	391,029	$	417,536	$	16,430		$	14,423		$	407,459		$	431,959
Distribution		70,568		41,883		(8,373	)		(5,534	)		62,195			36,349
Corporate and Other		151		14,324		(8,057	)		(8,889	)		(7,906	)		5,435

Year ended December 31, 2008 versus the year ended December 31, 2007. The Company’s $68.1 million increase in Net earnings available for common stockholders was primarily due to:

Higher EBIT contributions of $80 million from the Gathering and Processing segment primarily due to higher market-driven realized average natural gas and NGL prices and the impact of $50.1 million of higher net hedging gains in the 2008 period versus the 2007 period, partially offset by a reduction of gross margin of approximately $10.6 million resulting from the impact of Hurricane Ike on the Company’s third-party NGL fractionator, the establishment of a $3 million bad debt reserve for a customer that filed for bankruptcy protection, and higher depreciation expense of $3.2 million.

This earnings improvement was partially offset by:

Higher interest expense of $4.3 million primarily attributable to higher interest expense of $21.1 million in 2008 associated with new debt issued during the 2008 and 2007 periods primarily to fund capital expenditures for enhancement projects in the Transportation and Storage segment and retire maturing debt, partially offset by lower interest expense of $13.1 million on the $465 million 2012 Term Loan agreement in 2008 primarily due to lower LIBOR interest rates, and higher capitalized interest of $4.3 million resulting from higher average capital project balances outstanding in the 2008 period versus the 2007 period;

Lower EBIT contribution of $2.6 million from the Transportation and Storage segment primarily due to lower equity earnings attributable to Citrus of $24 million primarily resulting from $18.7 million of nonrecurring gains in the 2007 period related to the settlement of litigation and the sale of bankruptcy-related receivables, partially offset by higher EBIT contributions of $21.4 million in 2008 from Panhandle primarily attributable to higher transportation reservation revenues, partially offset by higher operating expenses; and

Higher income taxes of $9.5 million primarily due to higher pre-tax income in 2008, partially offset by a lower EITR in the 2008 period versus the 2007 period primarily attributable to a $22.1 million tax benefit resulting from a reduction in the Company’s deferred income tax liability in the fourth quarter of 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus.

Year ended December 31, 2007 versus the year ended December 31, 2006. The Company’s $164.6 million increase in Net earnings available for common stockholders was primarily due to:

·	Impact of the $153 million loss from discontinued operations in the 2006 period associated with the August 2006 sales of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division;

·	Higher EBIT contributions of $25.8 million from the Distribution segment primarily due to higher net operating revenue resulting from the Missouri Gas Energy rate increase effective April 3, 2007 eliminating the impact of weather and conservation for residential margin revenues;

Lower interest expense of $6.9 million primarily due to the retirement of debt in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, partially offset by increased interest expense related to the $600 million Junior Subordinated Notes issued in October 2006 and higher interest expense on Panhandle debt primarily due to higher debt balances; and

Lower income tax expense from continuing operations of $14 million primarily due to the lower federal and state EITR of 29 percent in the 2007 period versus 33 percent in the 2006 period primarily due to the tax benefit associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus.

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These earnings improvements were partially offset by:

Lower EBIT contributions of $24.5 million from the Transportation and Storage segment largely due to the gain on CCE Holdings’ exchange of Transwestern in 2006, partially offset by higher LNG terminalling revenue associated with the Trunkline LNG Phase I and Phase II expansions completed in April 2006 and July 2006, respectively, higher pipeline reservation revenues driven by higher average rates on contracts, higher parking revenues and higher equity earnings from Citrus resulting from the Company’s increased equity ownership in Citrus from 25 percent to 50 percent effective December 1, 2006; and

·	Impact of the pre-acquisition pre-tax mark-to-market gain of $37.2 million in the 2006 period on the put options associated with the acquisition of the Sid Richardson Energy Services business, partially offset by $12.8 million of executive bonus compensation awarded and paid in 2006.

Business Segment Results

Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services. The Transportation and Storage segment’s operations, conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. Demand for gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. Florida Gas’ pipeline system experiences the highest throughput in the summer period due to gas-fired generation loads in the second and third calendar quarters.

The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers. Shorter-term contracts, which can increase the volatility of revenues, are driven by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices. Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, changes in commodity prices and 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 commodity prices and volumes transported. Over the past several years, the weighted average life of contracts has actually trended somewhat higher as customers have exhibited an increased focus in securing longer-term supply and related transport capacity from the supply and market areas served by the Company. For additional information related to Transportation and Storage segment risk factors and the weighted average remaining lives of firm transportation and storage contracts, see Item 1A. Risk Factors – Risks that Relate to the Company’s Transportation and Storage Segment, and Item 1. Business – Business Segments – Transportation and Storage Segment, respectively.

The Company’s regulated transportation and storage businesses periodically file for changes in their rates, which are subject to approval by FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition. For information related to the status of current rate filings, see Item 1. Business – Business Segments – Transportation and Storage Segment.

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The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented:

	Years Ended December 31,
Transportation and Storage Segment	2008		2007		2006
	(In thousands)

Operating revenues	$	721,640	$	658,446	$	577,182

Operating expenses		258,062		236,473		191,758
Depreciation and amortization		103,807		85,641		72,724
Taxes other than on income and revenues		32,061		29,699		25,405
Total operating income		327,710		306,633		287,295
Earnings from unconsolidated investments		75,173		99,222		141,310
Other income, net		1,951		1,604		3,354
EBIT	$	404,834	$	407,459	$	431,959

Operating information:
Panhandle natural gas volumes transported (TBtu)		1,471		1,454		1,180
CCE Holdings natural gas volumes transported (TBtu) (1)
Florida Gas		786		751		737
Transwestern		N/A		N/A		572

_____________

(1)

Represents 100 percent of Florida Gas and Transwestern natural gas volumes transported versus the Company’s effective equity ownership interests. The Company’s effective equity ownership interests in Florida Gas and Transwestern were 25 percent and 50 percent, respectively, until December 1, 2006, when the Company’s indirect interest in Transwestern was transferred to Energy Transfer, increasing the Company’s effective indirect ownership interest in Florida Gas to 50 percent.

See Item 1. Business – Business Segments – Transportation and Storage Segment for additional related operational and statistical information associated with the Transportation and Storage segment.

Year ended December 31, 2008 versus the year ended December 31, 2007. The $2.6 million EBIT reduction in the year ended December 31, 2008 versus the same period in 2007 was primarily due to lower equity earnings from unconsolidated investments of $24 million, partially offset by a higher 2008 EBIT contribution from Panhandle totaling $21.4 million.

Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were lower by $24 million in 2008 versus 2007 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

·	A $15.1 million nonrecurring gain recorded in the 2007 period related to the settlement of litigation;

·	A $3.6 million nonrecurring gain recorded in the 2007 period related to the sale of bankruptcy-related receivables;

·	Higher operating expenses of $6 million primarily due to increased property taxes and higher overall costs experienced in 2008 applicable to employee labor and benefits, outside contract services costs and other operating costs;

·	Higher depreciation expense of $2.6 million primarily due to increased plant placed in service;

·	Higher interest expense of $4.5 million due to higher debt balances, including the $500 million Construction Loan Agreement related to the Phase VIII Expansion project, which was funded on October 1, 2008;

·	Higher operating revenues of $4.7 million primarily due to higher reservation revenues of $4.5 million attributable to increased capacity from prior expansions and the extra day in 2008 for the leap year; and

·	Lower income taxes of $9.4 million primarily due to lower pre-tax earnings.

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Panhandle’s $21.4 million EBIT improvement was primarily due to $63.2 million in higher operating revenues primarily related to the following items:

Higher transportation reservation revenues of $49.1 million primarily due to the phased completion of the Trunkline Field Zone Expansion project during the period from December 2007 to February 2008 and reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand, and approximately $1.2 million of additional revenues attributable to the extra day in the 2008 leap year;

·	Higher transportation commodity revenues of $7.1 million primarily due to a rate increase on Sea Robin, net of related customer liability refund provisions and the impact of approximately $4.1 million of lower revenues attributable to reduced volumes flowing after Hurricane Ike;

·	Higher parking revenues of $8.2 million resulting from customer demand for parking services and market conditions;

·	Higher storage revenues of $6.7 million primarily due to increased leased storage capacity; and

·	A $6.5 million decrease in LNG terminalling revenue due to lower volumes from decreased LNG cargoes during 2008.

These increased revenues were offset by:

·	Higher operating expenses of $21.6 million primarily attributable to:

o	Expense of $13.5 million related to damages to the Company’s facilities resulting from Hurricanes Gustav and Ike;

o	A $10.2 million increase in contract storage costs resulting from an increase in leased storage capacity;

o	A $4 million increase in insurance costs primarily due to higher property premiums;

o	A $3.5 million net increase in labor primarily due to merit increases;

o	A $5.7 million decrease in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2007; and

o	A $5.5 million decrease in LNG power costs resulting from a reduced number of LNG cargoes during 2008;

Increased depreciation and amortization expense of $18.2 million due to a $387.8 million increase in property, plant and equipment placed in service after December 31, 2007. Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, primarily from the LNG terminal infrastructure enhancement and compression modernization projects and other capital expenditures; and

·	Increased taxes, other than on income, of $2.4 million primarily due to higher property taxes attributable to higher property tax assessments resulting from increased earnings, partially offset by lower compressor fuel tax on a reduced number of LNG cargoes.

Year ended December 31, 2007 versus the year ended December 31, 2006. The $24.5 million EBIT reduction in the year ended December 31, 2007 versus the same period in 2006 was primarily due to lower equity earnings from unconsolidated investments of $42.1 million, primarily consisting of the Company’s investment in Citrus, offset by improved contributions from Panhandle totaling $17.6 million.

Panhandle’s $17.6 million EBIT increase was primarily related to higher operating revenues of $81.3 million as the result of the following items:

·	Increased transportation and storage revenue of $59.8 million attributable to:

o	Higher transportation reservation revenues of $27.4 million primarily due to reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand and utilization of contract capacity;

o	Higher parking revenues of $18 million resulting from customer demand for parking services and market conditions;

o	Higher storage revenues of $7.8 million due to increased contracted capacity; and

o	Higher other commodity revenues of $6.5 million due to higher throughput volumes including transportation of higher LNG volumes on Trunkline, higher volumes on Sea Robin due to adverse hurricane impacts on 2006 throughput, and higher throughput on Panhandle due to storage refill activity;

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A $23.6 million increase in LNG terminalling revenue based on a capacity increase on the BG LNG Services contract as a result of the Trunkline LNG Phase I and Phase II expansions, which were placed in service in April 2006 and July 2006, respectively, as well as higher volumes resulting from an increase in LNG cargoes; and

·	A decrease in other revenue of $2.2 million primarily due to higher operational sales of gas in 2006.

These increased revenues were offset by:

·	Higher operating expenses of $44.7 million as the result of:

o	A $15.6 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units;

o	A $13.1 million increase in contract storage costs attributable to an increase in leased capacity;

o	A $6.2 million increase in LNG power costs resulting from increased cargoes;

o	A $3.4 million increase in fuel tracker costs primarily due to a net under-recovery in 2007;

o	A $2.4 million net increase in labor and benefits primarily due to incentive and merit increases; and

o	A $1.8 million increase in insurance due to higher premiums;

Increased depreciation and amortization expense of $12.9 million due to a $411.2 million increase in property, plant and equipment placed in service in 2007. Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, including compression modernization and other expenditures; and

·	Higher taxes other than on income of $4.3 million primarily due to a $2.8 million refund received in 2006 for franchise and sales taxes and higher property and compressor fuel taxes in 2007.

Equity earnings were lower by $42.1 million in 2007 versus 2006 primarily due to the following items, adjusted where applicable to reflect the Company’s proportionate equity share:

·	$74.8 million nonrecurring gain in 2006 resulting from the transfer of Transwestern to Energy Transfer in December 2006 in connection with the redemption of Energy Transfer’s interest in CCE Holdings pursuant to the Redemption Agreement;

·	$28 million of earnings in 2006 attributable to Transwestern;

·	Higher equity earnings of approximately $42 million from Citrus’ core business largely due to the increase in the Company’s effective ownership from 25 percent to 50 percent as a result of the transactions under the Redemption Agreement, which closed in December 2006;

·	A $7.6 million gain in 2007 related to a reduction in a previously established liability to Enron associated with the Duke lawsuit;

·	A gain of $7.5 million recognized by Citrus in 2007 associated with settlement of the Duke lawsuit; and

·	A $3.6 million gain in 2007 related to the sale of Enron bankruptcy claim receivables.

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Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. The results of operations provided by SUGS have been included in the Consolidated Statement of Operations since its March 1, 2006 acquisition.

The following table presents the results of operations applicable to the Company’s Gathering and Processing segment:

	Years Ended December 31,
Gathering and Processing Segment	2008			2007			2006
	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	1,463,966		$	1,214,806		$	1,079,297
Realized and unrealized commodity derivatives		57,075			6,941			10,919
Operating revenues		1,521,041			1,221,747			1,090,216
Cost of gas and other energy		(1,216,953	)		(1,010,967	)		(918,064	)
Gross margin (1)		304,088			210,780			172,152
Operating expenses		90,657			84,550			61,428
Depreciation and amortization		62,716			59,560			47,321
Taxes other than on income and revenues		4,466			2,742			2,156
Total operating income		146,249			63,928			61,247
Earnings (loss) from unconsolidated investments		(990	)		1,300			(188	)
Other income, net		104			140			1,571
EBIT	$	145,363		$	65,368		$	62,630


Operating Statistics:
Volumes
Avg natural gas processed (MMBtu/d)		410,511			426,097			451,675
Avg NGL produced (gallons/d)		1,321,325			1,337,450			1,423,138
Avg natural gas wellhead volumes (MMBtu/d)		596,150			637,794			585,185
Natural gas sales (MMBtu) (2)		92,376,383			105,677,108			113,362,236
NGL sales (gallons) (2)		542,311,822			469,907,600			421,896,247

Average Pricing
Realized natural gas ($/MMBtu) (3)	$	7.67		$	6.26		$	5.83
Realized NGL ($/gallon) (3)		1.37			1.13			0.97
Natural Gas Daily WAHA ($/MMBtu)		7.57			6.35			5.78
Natural Gas Daily El Paso ($/MMBtu)		7.44			6.20			5.68
Estimated plant processing spread ($/gallon)		0.64			0.55			0.43

________________

(1) Gross margin consists of Operating revenues less Cost of gas and other energy. The Company believes that this measurement is more meaningful for understanding and analyzing the Gathering and Processing segment’s

operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.

(2)

Volumes processed by SUGS include volumes sold under various buy-sell arrangements. For the years ended December 31, 2008 and 2007 and the ten-months ended December 31, 2006, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $95.7 million, $91.6 million and $75.3 million, and 12.2 million MMBtus, 13.6 million MMBtus and 12.4 million MMBtus, respectively. The Company’s operating revenues and related volumes in 2008 attributable to its buy-sell arrangements for NGL totaled $117.9 million and 83 million gallons, respectively, and was insignificant for the 2007 and 2006 periods.

(3)	Excludes impact of realized and unrealized commodity derivative gains and losses detailed in the above EBIT presentation.

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Year ended December 31, 2008 versus the year ended December 31, 2007. The $80 million EBIT increase for the year ended December 31, 2008 versus the same period in 2007 was primarily due to the following items:

·	Higher gross margin of $93.3 million primarily as the result of:

o	Impact of $50.1 million of higher net hedging gains in the 2008 period versus the 2007 period (which includes the impact of $59.7 million of unrealized gains recorded in 2008);

o	Higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $7.67 per MMBtu and $1.37 per gallon in the 2008 period versus $6.26 per MMBtu and $1.13 per gallon in the 2007 period;

Favorable gross margin impact of lower levels of fuel, flare, and unaccounted for gas losses in the 2008 period versus the unusually high levels experienced in the first and second quarters of 2007; and unfavorable gross margin impact of approximately $10.6 million resulting from damage by Hurricane Ike on the Company’s third-party NGL fractionator. Commencing September 11, 2008, the Company was forced to shut in its natural gas processing plants and attendant production for approximately a week and operated at reduced production levels for the remainder of the month.

SUGS’ higher gross margin was partially offset by the following items:

·	Operating expenses were higher by $6.1 million primarily due to:

o	A $3 million bad debt reserve for receivables associated with a customer that filed for bankruptcy protection in the third quarter of 2008;

o	A $2.3 million increase in chemical and lubricants costs, which generally track with the price of oil; and

o	A $2.1 million increase in utility costs primarily due to higher compressor fuel costs resulting from rising overall average cost of natural gas in 2008 versus 2007.

·	Higher depreciation expense of $3.2 million primarily attributable to a $50.3 million increase in property, plant and equipment placed in service after 2007; and

·	Lower equity earnings of $2.3 million from the Company’s unconsolidated investment in Grey Ranch, which was out of service for approximately five months during 2008 because of a fire at the Grey Ranch processing plant.

Year ended December 31, 2007 versus the year ended December 31, 2006. The $2.7 million EBIT increase for the year ended December 31, 2007 versus the post-acquisition ten-month period ended December 31, 2006 was primarily due to the following items:

·	Gross margin was higher by $38.6 million primarily due to:

o	Realization of operating results for the complete twelve-month period in 2007 versus ten months in the 2006 period;

o	Favorable impact of market-driven higher average realized natural gas and NGL prices of $6.26 per MMBtu and $1.13 per gallon in the 2007 period versus $5.83 per MMBtu and $0.97 per gallon in the 2006 period, respectively; and

o	Higher producer fee revenues of $5 million primarily due to increased volumes from the Atoka producing region associated with the Company’s Mi Vida system.

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The favorable gross margin impact was partially offset by unusually high levels of fuel, flare and unaccounted for gas losses in the 2007 period versus the 2006 period primarily attributable to capacity and treating limitations experienced during 2007 at the Jal Plant treating facility;

SUGS’ higher gross margin was partially offset by the following items:

·	Operating expenses were higher by $23.1 million primarily due to:

o	Incurrence of twelve months of activity in the 2007 period versus ten months in the 2006 period;

o	A $4.9 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units; and

Increases in operating costs such as employee labor and benefit costs and contractor services costs resulting from competitive forces within the midstream energy industry, as well as higher costs incurred for chemical and lubricant petroleum products used in SUGS’ gathering and processing operations;

·	Depreciation and amortization expense was higher by $12.2 million primarily due to the incurrence of twelve months of activity in the 2007 period versus ten months in the 2006 period and a $57.5 million increase in property, plant and equipment placed in service in 2007;

Earnings (loss) from unconsolidated investments increased by $1.5 million primarily due to the Company’s proportionate equity share of $463,000 related to a settlement with a producer for damages incurred from sour gas delivered into the Grey Ranch facility and the benefit derived from improved operating efficiencies realized at the Grey Ranch facility; and

Other income, net decreased by $1.4 million primarily due to approximately $911,000 of lower interest income resulting from higher available cash balances for investment purposes in the 2006 period versus the 2007 period, principally due to the $53.7 million of cash on hand at the March 1, 2006 acquisition date.

To alleviate the treating limitations discussed above related to the Jal Plant, the Company completed construction of an 18-mile, 16-inch high pressure pipeline to utilize existing treating capacity at the Keystone Plant. The pipeline was put into service on June 21, 2007 at an approximate cost of $6.1 million.

For further information related to SUGS’ derivative instruments and hedging activities, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment and Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

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Distribution Segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company divisions, respectively. The Distribution segment’s operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. For information related to the status of current rate filings relating to the Distribution segment, see Item 1. Business – Business Segments – Distribution Segment. The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total natural gas sales customers and approximately 67 percent of its gross natural gas sales revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented:

	Years Ended December 31,
Distribution Segment	2008			2007			2006
	(In thousands)

Net operating revenues (1)	$	221,111		$	222,097		$	174,584

Operating expenses		116,288			117,161			95,712
Depreciation and amortization		30,530			30,251			30,353
Taxes other than on income
and revenues		11,045			10,588			10,040
Total operating income		63,248			64,097			38,479
Other income (expenses), net		(1,830	)		(1,902	)		(2,130	)
EBIT	$	61,418		$	62,195		$	36,349

Operating Information:
Gas sales volumes (MMcf)		61,469			56,196			49,376
Gas transported volumes (MMcf)		28,214			26,911			26,340

Weather – Degree Days: (2)
Missouri Gas Energy service territories		5,499			4,776			3,996
New England Gas Company service territories		5,348			5,371			4,901

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(1) Operating revenues for the Distribution segment are reported net of Cost of gas and other energy and Revenue-related taxes, which are pass-through costs.
(2) "Degree days" are a measure of the coldness of the weather experienced. A degree day is equivalent to each degree that the daily mean temperature for a day falls below 65 degrees Fahrenheit.

See Item 1. Business – Business Segments – Distribution Segment for additional related operational and statistical information related to the Distribution segment.

Year ended December 31, 2008 versus the year ended December 31, 2007. The $800,000 EBIT reduction in the year ended December 31, 2008 versus the same period in 2007 was primarily due to the following items:

·	Lower net operating revenues of $1 million primarily due to lower market-driven pipeline capacity release and off-system sales at Missouri Gas Energy in the 2008 period versus the 2007 period;

·	Higher taxes other than on income of $500,000 primarily attributable to higher property taxes resulting from increased property appraisals; and

·	Lower operating expenses of $900,000 primarily attributable to:

o	Lower injuries and damage claims of $1.2 million primarily due to an insurance reimbursement of $900,000 in 2008 related to prior year expenditures;

o	Lower provisions for uncollectible customer accounts of approximately $2.1 million primarily resulting from the impact of governmental assistance provided to Missouri Gas Energy’s low income customers, which has reduced the Company’s customer allowance reserve; and

Higher environmental remediation costs of $2 million primarily attributable to site investigation evaluations completed during 2008. The MPSC has denied Missouri Gas Energy’s request during the third quarter of 2008 to defer certain environmental costs for recovery consideration in a future rate proceeding.

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Year ended December 31, 2007 versus the year ended December 31, 2006. The $25.8 million EBIT improvement in the year ended December 31, 2007 versus the same period in 2006 was primarily due to the following items:

Net operating revenues increased $47.5 million primarily due to the Missouri Gas Energy $27.2 million annual revenue rate increase effective April 3, 2007 and higher consumption volumes resulting from colder weather in 2007 versus 2006 as evidenced by a 13.8 percent increase in consumption volumes and a 14 percent increase in degree days;

·	The net operating revenues increase was partially offset by higher operating expenses of $21.4 million in the 2007 period versus the 2006 period primarily due to:

o	Increased benefit costs of approximately $7.1 million primarily due to higher pension costs resulting from the recent Missouri Gas Energy rate case;

o	Increased general expenses of approximately $4.5 million primarily due to cathodic protection maintenance, the establishment of a customer education program for energy efficiency associated with the 2007 rate case and other costs;

o	Increased labor expenses of approximately $5.5 million primarily due to the filling of vacant positions and incentive and merit increases in 2007 versus 2006;

o	Higher corporate services costs of $2.8 million relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units; and

o	Higher uncollectible accounts of approximately $1.8 million resulting primarily from higher revenues realized in the 2007 period versus the 2006 period.

Corporate and Other

Year ended December 31, 2008 versus the year ended December 31, 2007. The $3.6 million EBIT increase for the year ended December 31, 2008 versus the same period in 2007 was primarily due to the following items:

·	Impact of a $6.9 million impairment in 2007 related to the Company’s former corporate office building;

·	Higher non-allocable corporate legal expenses of $6 million incurred in the 2008 period versus the 2007 period;

·	Higher contribution of $1 million from PEI Power Corporation primarily due to higher revenues resulting from increased electricity production and higher electricity prices in 2008;

·	Impact of an $800,000 charge in 2007 to reserve for an other-than-temporary impairment of the Company’s investment in a technology company; and

·	Higher interest income of $700,000 in the 2008 period versus the 2007 period associated with short-term investments held by the Company.

Year ended December 31, 2007 versus the year ended December 31, 2006. The $13.3 million EBIT reduction for the year ended December 31, 2007 versus the same period in 2006 was primarily due to the following items:

·	Impact of a mark-to-market gain in 2006 of $37.2 million on put options for the pre-acquisition period associated with the March 1, 2006 acquisition of the Sid Richardson Energy Services business; and

Favorable offsetting impact of a decrease in operating expenses in 2007 versus 2006 due to executive bonus compensation of $12.8 million awarded by the compensation committee of the Company’s Board of Directors in 2006 in respect of transactional activity and a $13.1 million increase in corporate services costs allocated to the Company’s business units in 2007.

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Interest Expense

Year ended December 31, 2008 versus the year ended December 31, 2007. Interest expense was $4.3 million higher in 2008 compared with 2007 primarily due to:

Higher interest expense of $21.1 million primarily due to higher outstanding debt balances from the $300 million 6.20% Senior Notes, the $400 million 7.00% Senior Notes, and the $455 million 2012 Term Loan issued in October 2007, June 2008, and March 2007, respectively, partially offset by lower interest expense from the repayment in August 2008 of the $300 million 4.80% Senior Notes and the $125 million 6.15% Senior Notes and the repayment in March 2007 of the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan;

·	Higher net interest expense of $1.5 million associated with the remarketing of the $100 million 4.375% Senior Notes in February 2008, which were replaced with the higher interest rate $100 million 6.089% Senior Notes;

·	Lower interest expense of $13.1 million primarily due to the effect of lower LIBOR interest rates on the $465 million 2012 Term Loan agreement;

·	Lower interest expense of $4.3 million primarily due to the impact of the higher level of interest costs capitalized attributable to higher average capital project balances outstanding in 2008 compared to 2007; and

Lower interest expense of $2.4 million associated with borrowings under the Company’s credit agreements primarily due to lower average interest rates, partially offset by higher average outstanding balances in 2008 compared to 2007 and higher interest expense resulting from the issuance of the $150 million Short-Term-Facility in October 2008.

Year ended December 31, 2007 versus the year ended December 31, 2006. Interest expense was $6.9 million lower in 2007 compared with 2006 primarily due to:

·	Impact of interest expense of $49.2 million and debt issuance cost amortization of $7.8 million in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business;

·	Lower interest expense of $6 million associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2007 compared to 2006;

·	Lower interest expense of $2.2 million due to the retirement of the 2.75% Senior Notes in August 2006;

·	Lower interest expense of $1.6 million associated with interest owed to Missouri Gas Energy’s ratepayers in connection with its purchased gas cost recovery mechanism primarily due to higher levels of overcollections in 2006;

·	Increased interest expense of $34.9 million related to the $600 million Junior Subordinated Notes issued in October 2006;

·	Increased interest expense of $20.6 million related to Panhandle debt primarily due to higher debt balances in 2007 versus 2006; and

·	Increased interest expense of $4.8 million under the 6.15% Senior Notes issued in August 2006.

Federal and State Income Taxes from Continuing Operations

Year ended December 31, 2008 versus the year ended December 31, 2007. The EITR from continuing operations for the years ended December 31, 2008 and 2007 was 26 percent and 29 percent, respectively. The decrease in the EITR from continuing operations was primarily due to:

Tax benefit of $22.1 million resulting from a reduction in the Company’s deferred income tax liability in the fourth quarter of 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus. Due to the anticipated increase in dividends from Citrus after the completion of the Phase VIII Expansion, the Company expects the entire deferred income tax liability related to its investment in Citrus will be realized at the Company’s statutory income tax rate less the dividends received deduction; and

Lower tax benefit of $5.2 million associated with the decrease in the dividends received deduction from the Company’s unconsolidated investment in Citrus. The dividends received deduction for dividends paid by Citrus prior to the aforementioned reduction in the Company’s deferred income tax liability was $23 million in 2008 versus $30.9 million in 2007. The dividends received deduction for Citrus’ unremitted earnings after such reduction in the Company’s deferred income tax liability was $2.7 million in 2008.

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Year ended December 31, 2007 versus the year ended December 31, 2006. The EITR from continuing operations for the years ended December 31, 2007 and 2006 was 29 percent and 33 percent, respectively. The decrease in the EITR from continuing operations was primarily due to:

·	Tax benefits of $30.9 million in 2007 versus $11.5 million in 2006 associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus;

·	Reduced tax expense of $523,000 in 2007 versus $5.4 million in 2006 associated with the decrease in nondeductible executive compensation; and

·	Partially offset by the release of $9.4 million of tax reserves in 2006 for uncertain tax positions established in prior years due to the completion of the IRS audit for the fiscal year ended June 30, 2003 and expiring state statutes.

IRS Audit.

In November 2006, the IRS completed its examination of the Company’s federal income tax return for the fiscal year ended June 30, 2003. The Company realized a favorable settlement regarding the like-kind exchange structure under Section 1031 of the Internal Revenue Code related to the sale of the assets of its Southern Union Gas natural gas operating division and related assets to ONEOK Inc. for approximately $437 million in January 2003 and the acquisition of Panhandle in June 2003.

The Company was successful in sustaining all but $26.3 million of the original estimated $90 million of income tax deferral associated with the like-kind structure. However, the Company’s net tax due to the IRS was reduced to $11.6 million, plus interest, primarily due to alternative minimum tax credits and other favorable audit results. As a result of the IRS examination, the Company paid $12.6 million of income tax to the IRS in November 2006, received a refund of $1 million from the IRS and paid $1.4 million to state and local jurisdictions in 2007. The Company also paid $2.4 million ($1.5 million, net of tax) in 2007 representing interest payable to the IRS and state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003. No penalties were assessed against the Company in this IRS examination.

The Company will be entitled to recover a corresponding $26.3 million of future income tax benefit over time from additional depreciation deductions in respect of the Panhandle assets due to the higher tax basis in such assets as a result of the reduction of income tax benefits from the like-kind exchange.

Preferred Stock Dividends and Loss on Extinguishment of Preferred Stock

Year ended December 31, 2008 versus the year ended December 31, 2007. The $1.6 million improvement to Net earnings available for common stockholders for the years ended December 31, 2008 and 2007 was due to the Company’s 2008 purchase of 4,599,987 depository shares representing 459,999 shares of its 7.55% Noncumulative Preferrerd Stock, Series A (Liquidation Preference $250 per share) (Preferred Stock), resulting in lower dividends of $5.1 million in 2008, partially offset by net non-cash charges of $3.5 million related to the write-off of issuance costs. See Item 8. Financial Statements and Supplementary Data, Note 12 – Preferred Securities for additional related information.

Net Earnings from Discontinued Operations

Earnings (loss) from discontinued operations included in the 2006 period are associated with the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division, which were sold in August 2006. See Item 8. Financial Statements and Supplementary Data, Note 19 – Discontinued Operations for additional information.

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LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity. The Company’s working capital deficit at December 31, 2008 is $319.5 million. This includes $60.6 million of long-term debt maturing in July 2009 and $150 million of short-term debt due in August 2009. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings, debt capital markets and bank financings, and proceeds from asset dispositions. The availability and terms relating to such liquidity will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure and conditions in the financial markets at the time of such offerings.

Financial Sector Exposure

Recent events in the global financial markets have caused the Company to place increased scrutiny on its liquidity position and the financial condition of its critical third-party business partners, including the Company’s short-term debt and revolving credit facilities, future capital needs (including long-term borrowing needs and potential refinancing plans) and its joint ventures, derivative counterparties and customer and other contractual relationships. The Company uses publicly available information to assess the potential impact of the current credit markets and related liquidity issues on its business partners and to assess the associated business risks to the Company.

The Company notes that while there is no way to predict the extent or duration of any negative impact that the current credit disruptions in the economy will have on its liquidity position, there is no current expectation that the impact on the Company would be significant. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Financing Activities – Retirement of Debt Obligations for information related to management’s intent with respect to retirement of its 2009 debt obligations.

Sources (Uses) of Cash

	Years ended December 31,
	2008			2007			2006
				(In thousands)
Cash flows provided by (used in):
Operating activities	$	486,827		$	470,408		$	458,805
Investing activities		(568,952	)		(666,604	)		(806,804	)
Financing activities		80,753			196,135			336,812
Increase (decrease) in cash and cash equivalents	$	(1,372	)	$	(61	)	$	(11,187	)

Operating Activities

Year ended December 31, 2008 versus the year ended December 31, 2007. Cash provided by operating activities increased by $16.4 million in the 2008 period versus the same period in 2007. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2008 period were $551.8 million compared with $516.6 million for the 2007 period, an increase of $35.2 million primarily resulting from higher net earnings and depreciation and amortization offset by unrealized gains on derivatives. Changes in operating assets and liabilities used cash of $65 million in 2008 and $46.2 million in 2007, resulting in a decrease in cash from changes in operating assets and liabilities of $18.8 million in 2008 compared to 2007. The $18.8 million decrease is primarily due to $77.1 million of increased cash requirements for Distribution segment inventories due to higher market-driven gas prices during 2008 and $12.3 million of higher inventory in the Gathering and Processing segment primarily due to a build up of NGL inventory when its third party NGL fractionator was unavailable to provide fractionation services for approximately four weeks during the fourth quarter of 2008 due to a scheduled maintenance outage. These increased cash requirements were partially offset by the impact of $79.1 million of lower receivables primarily in the Gathering and Processing segment due to lower product prices at 2008 year end compared to 2007. During the years ended December 31, 2008 and 2007, the Company received cash distributions of $77.2 million and $103.6 million, respectively, from Citrus. Given significant capital expenditure requirements associated with Florida Gas’ Phase VIII Expansion, the Company does not anticipate receiving cash distributions from Citrus in 2009 or 2010. See Item 1. Business – Our Business – Business Segments – Transportation and Storage Segment – Recent System Enhancements Completed or Under Construction for additional information related to the Phase VIII Expansion project.

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Year ended December 31, 2007 versus the year ended December 31, 2006. Cash flows provided by operating activities were $470.4 million for the year ended December 31, 2007 compared with cash flows provided by operating activities of $458.8 million for the same period in 2006. Cash flows provided by operating activities before changes in operating assets and liabilities for 2007 were $516.6 million compared with $393.6 million for 2006. Changes in operating assets and liabilities used cash of $46.2 million in 2007 and provided cash of $65.2 million in 2006, resulting in a decrease in cash of $111.4 million in 2007 compared to 2006. The $111.4 million decrease in cash is primarily due to the impact of $91.8 million of lower receivables from the Distribution segment attributable to higher December 2005 balances realized from the colder related winter period versus the subsequent winter periods and the receipt of $38.8 million less from cash settlements of put options in the Gathering and Processing segment in the 2007 period versus the 2006 period.

Investing Activities

Summary

The Company’s business strategy includes making prudent capital expenditures across its base of gathering, processing, transmission, storage and distribution assets and growing the businesses through the selective acquisition of assets in order to position itself favorably in the evolving North American natural gas markets.

Cash flows used in investing activities in the years ended December 31, 2008 and 2007 were $569 million and $666.6 million, respectively. The $97.7 million reduction in invested cash outflows is primarily due to the impact of $49.3 million in working capital adjustment payments made in the 2007 period related to the 2006 sales of certain distribution assets and a $47.7 million decrease in capital expenditures in the Transportation and Storage segment in the 2008 period.

Cash flows used in investing activities in the years ended December 31, 2007 and 2006 were $666.6 million and $806.8 million, respectively. The $140.2 million decrease in invested cash is primarily due to the $1.54 billion (net of $53.7 million cash received) acquisition of the Sid Richardson Energy Services business completed on March 1, 2006, offset by the effect of the $1.08 billion disposition in August 2006 of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division. This decrease is partially offset by increased capital expenditures of $269 million for the same periods, primarily due to increased capital spending in the Transportation and Storage segment.

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The following table presents a summary of additions to property, plant and equipment in continuing operations by segment, including additions related to major projects for the periods presented.

	Years ended December 31,
Property, Plant and Equipment Additions	2008		2007		2006
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	157,325	$	133,469	$	57,045
Trunkline Field Zone Expansion		72,276		185,180		12,314
East End Enhancement		35,062		80,249		52,102
Compression Modernization		56,288		81,687		11,642
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and hurricane expenditures		113,053		110,568		111,718
Total		434,004		591,153		244,821

Gathering and Processing Segment		67,317		48,633		35,101	(1)

Distribution Segment
Missouri Safety Program		14,124		11,405		11,592
Other, primarily system replacement
and expansion		27,001		33,364		36,362

Total		41,125		44,769		47,954

Corporate and other		9,345		4,173		4,798

Total (2)	$	551,791	$	688,728	$	332,674

____________________

(1) Reflects expenditures for the period subsequent to the March 1, 2006 acquisition of Sid Richardson Energy Services.

(2) Includes net period changes in capital accruals totaling $(21.9) million, $71.8 million and $14.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Principal Capital Expenditure Projects

See Item 1. Business – Business Segments – Transportation and Storage Segment – Recent System Enhancements – Completed or Under Construction for a summary of the Company’s major 2008 and ongoing capital expenditure projects within its Transportation and Storage segment.

2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Damage from the hurricanes has affected both the Company’s Transportation and Storage and Gathering and Processing segments. Offshore transportation facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and are continuing to experience reduced volumes.

With respect to the Company’s damage assessments associated with Hurricane Gustav, the Company believes the capital expenditure impact related to the hurricane was insignificant. As the total capital expenditure amount and the related recorded expense estimate of approximately $3 million is expected to be below the Company’s $10 million property insurance deductible, the Company does not expect any of the repair and replacement costs associated with Hurricane Gustav will be reimbursed by its property insurance carrier.

With respect to the Company’s ongoing damage assessments associated with Hurricane Ike, the Company currently estimates that capital expenditures relating to the hurricane will total approximately $125 million in the period 2008 through 2010. This estimate is subject to further revision as the assessment of the damage to the Company’s facilities is ongoing. Of this amount, approximately $23 million was incurred as of December 31, 2008. The Company anticipates reimbursement from its property insurance carrier 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. The Company’s insurance provider has announced that it expects to reach the $750 million aggregate

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exposure limit and currently estimates the payout amount will not exceed 84 percent based on estimated claim information it has received. The final amount of any applicable pro rata reduction cannot be determined until the Company’s insurance provider has received and assessed all claims.

Potential Sea Robin Impairment. Sea Robin, comprised primarily of offshore facilities, suffered damage related to several platforms from Hurricane Ike. The Company currently estimates $80 million of the total estimated capital expenditures of $125 million to replace property and equipment damaged by Hurricane Ike are related to Sea Robin. This estimate is subject to further revision as the damage assessment is ongoing. The Company anticipates 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 18 – Commitments and Contingencies – 2008 Hurricane Damage for additional related information. To the extent the Company’s capital expenditures are not recovered through insurance proceeds, 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. If the amount of Sea Robin’s insurance reimbursements are significantly reduced from the currently estimated maximum 84 percent payout limit amount or it 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 pursuant to FASB Statement No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets” (Statement No. 144). See related information regarding the Company’s evaluation of assets for impairment in the Critical Accounting Policies discussion below.

2005 Hurricane Damage. Late in the third quarter of 2005, Hurricane Rita came ashore along the Upper Gulf Coast. Hurricane Rita caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG. The Company has filed approximately $34 million of eligible damage claims related to Hurricane Rita, primarily amounts for repairs, replacement or abandonment of damaged property and equipment at Sea Robin and Trunkline. The Company’s property insurance carrier has accepted these claims and the Company has received a significant portion of the damages in excess of the $5 million deductible in effect in 2005. The ultimate reimbursement is currently estimated by the Company’s property insurance carrier to ultimately be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, based on a pro rata reduction to the extent accepted claims exceeded the carrier’s $1 billion aggregate exposure limit. As of December 31, 2008, the Company has received payments of $14.8 million from its insurance carrier, representing a 55 percent payout of the maximum 70 percent payout ultimately expected to be received on eligible claims after application of the $5 million deductible. No additional receivables due from the insurance carrier have been recorded as of December 31, 2008 relating to claims for Hurricane Rita.

Missouri Safety Program. Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas safety program in its service territories (Missouri Safety Program). This program includes replacement of Company and customer-owned gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains. In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period. On August 28, 2003, the State of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects. The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures. The Company incurred capital expenditures of $14.1 million in 2008 related to this program and estimates incurring approximately $126.4 million over the next 11 years, after which all service lines, representing about 30 percent of the annual safety program investment, will have been replaced.

For additional information related to the Company’s strategy regarding other growth opportunities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Strategy.

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Financing Activities

Summary

The Company continues to pursue opportunities to enhance its credit profile. The issuance of common stock, equity units, preferred stock and asset sales and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with past acquisitions is continued evidence of the Company’s commitment to strengthen its balance sheet and solidify its current investment grade status.

Cash flows provided by financing activities were $80.8 million and $196.1 million for the years ended December 31, 2008 and 2007, respectively. The $115.4 million decrease in net financing cash inflows was primarily due to the $115.2 million extinguishment of preferred stock and lower net debt issuances of $317.9 million in 2008, partially offset by $100 million of cash received by the Company from the issuances of common stock in 2008 and an increase in borrowings of $255.5 million under the Company’s revolving credit facilities in 2008 compared to 2007.

Cash flows provided by financing activities were $196.1 million and $336.8 million for the years ended December 31, 2007 and 2006, respectively. Financing activity cash flow changes were primarily due to the net impact of higher issuances of debt, partially offset by higher payments on the revolving credit facilities in the 2006 period versus the 2007 period and the issuance of common stock in 2006.

Common Stock and Equity Units Issuances

On February 8, 2008, the Company remarketed its 4.375% Senior Notes, which yielded no cash proceeds for the Company. The interest rate on the Senior Notes was reset to 6.089 percent per annum effective on and after February 19, 2008. The 6.089% Senior Notes will mature on February 16, 2010. On February 19, 2008, the Company issued 3,693,240 shares of common stock for $100 million in cash proceeds in conjunction with the remarketing of the 4.375% Senior Notes.

On August 16, 2006, the Company remarketed the 2.75% Senior Notes. The interest rate on the Senior Notes was reset to 6.15 percent per annum effective on and after August 16, 2006. On August 16, 2006, the Company issued 7,413,074 shares of common stock for $125 million in cash proceeds in conjunction with the remarketing of its 2.75% Senior Notes. The $125 million 6.15% Senior Notes were retired on August 16, 2008.

For additional information related to the Company’s remarketed debt obligations, see Item 8. Financial Statements and Supplementary Data, Note 13 – Debt Obligations – Long-Term Debt – Remarketing Obligation.

Debt Refinancing, Repayment and Issuance Activity

7.00% due 2018. In June 2008, PEPL 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, PEPL incurred underwriting and discount costs totaling approximately $4.1 million, resulting in approximately $395.9 million in proceeds to PEPL. These proceeds were advanced to Southern Union and used to repay borrowings under its credit facilities. Southern Union repaid PEPL a portion of the advance to retire the $300 million 4.80% Senior Notes in August 2008.

6.20% Senior Notes. On October 26, 2007, PEPL issued $300 million in senior notes due November 1, 2017 with an interest rate of 6.20 percent (6.20% Senior Notes). In connection with the issuance of the 6.20% Senior Notes, PEPL incurred underwriting and discount costs of approximately $2.7 million. The debt was priced to the public at 99.741 percent, resulting in $297.3 million in proceeds to PEPL. The proceeds were initially advanced to Southern Union and used to repay approximately $246 million outstanding under credit facilities. The remaining proceeds of $51.3 million were invested by Southern Union and subsequently utilized to fund working capital obligations of PEPL.

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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 fixed 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, 2008 and 2007, respectively. See Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps on the 2012 Term Loan.

In connection with the December 1, 2006 closing of the Redemption Agreement, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into the $465 million 2006 Term Loan due April 4, 2008. 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 $412.2 million at effective interest rates of 1.02 percent and 5.37 percent at December 31, 2008 and 2007, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 24, 2009 was $360.4 million and 0.96 percent, respectively.

Junior Subordinated Notes. On October 23, 2006, the Company issued $600 million in Junior Subordinated Notes due November 1, 2066 with an initial fixed interest rate of 7.20 percent. In connection with the issuance of the Junior Subordinated Notes, the Company incurred underwriting and discount costs of approximately $9 million. The debt was priced to the public at 99.844 percent, resulting in $590.1 million in proceeds to the Company, which were used to retire debt associated with the acquisition of the Sid Richardson Energy Services business and to pay down a portion of the Company’s credit facilities. See related information in Item 8. Financial Statements and Supplementary Data, Note 13 – Debt Obligations – Long-Term Debt – Junior Subordinated Notes.

Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt.

Credit Facilities. The Company’s $400 million Fifth Amended and Restated Revolving Credit Agreement (Revolver) is a committed credit facility that matures on May 28, 2010. Borrowings under the Revolver are available for Southern Union’s working capital and letter of credit requirements and other general corporate purposes. The interest rate for the Revolver is based on LIBOR plus 62.5 basis points. The Revolver is subject to a commitment fee based on the rating of the Company’s senior unsecured notes. As of December 31, 2008, the commitment fees were an annualized 0.15 percent.

On July 23, 2008, the Company entered into a short-term committed credit facility with one of its existing lenders in the amount of $20 million. The facility will mature on July 22, 2009 and replaces a $15 million uncommitted facility that the Company had in place with that same lender.

Balances of $251.5 million and $123 million were outstanding under the Company’s credit facilities at effective interest rates of 1.16 percent and 5.82 percent at December 31, 2008 and 2007, respectively. The Company classifies its borrowings under the credit facilities as short-term debt, as the individual borrowings are generally for periods of 15 to 180 days. At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days. As of February 24, 2009, there was a balance of $170 million outstanding under the Company’s credit facilities at an average effective interest rate of 1.05 percent.

Short-Term Facility. On August 11, 2008, Southern Union entered into a short-term Credit Agreement in the amount of $150 million (Short-Term Facility). The Short-Term Facility is a 364-day term loan facility and will be due in its entirety on August 10, 2009. The interest rate associated with the Short-Term Facility is based, at the Company’s option, upon either LIBOR plus 125 basis points or the prime lending rate. Borrowings under the Short-Term Facility are available for general corporate purposes. On October 1, 2008, Southern Union borrowed the $150 million and used the proceeds to reduce the amounts outstanding under other credit facilities. As of December 31, 2008 and February 24, 2009, there was a balance of $150 million outstanding under the Short-Term Facility, with an effective interest rate of 3.54 percent and 1.70 percent, respectively.

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Sid Richardson Bridge Loan. On March 1, 2006, Southern Union acquired SUGS for $1.6 billion in cash. The acquisition was funded by a bridge loan facility in the amount of $1.6 billion that was entered into on March 1, 2006 between the Company and a group of banks as lenders. On August 24, 2006, the Company applied approximately $1.1 billion in net proceeds from the sales of the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division to repayment of the Sid Richardson Bridge Loan. On October 23, 2006, the Company retired the remainder of the Sid Richardson Bridge Loan using a portion of the $590.1 million in proceeds received from the $600 million Junior Subordinated Notes offering discussed above.

Retirement of Debt Obligations

The Company plans to repay the $60.6 million 6.50% Senior Notes maturing in July 2009 and expects to arrange to refinance its $150 million Short-Term Facility due in August 2009. Alternatively, should the Company not be successful in its refinancing efforts, the Company may choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, draw downs under existing credit facilities, and altering the timing of controllable expenditures, among other things. The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets, current economic and capital market conditions and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity. There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings.

Credit Ratings. As of December 31, 2008, both Southern Union’s and Panhandle’s debt were rated Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. Fitch Ratings has rated Southern Union’s debt BBB- and Panhandle’s debt is rated BBB. The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements. However, if its current credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

Dividend Restrictions. Under the terms of the indenture governing its senior unsecured notes (Senior Notes), Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied. Currently, the Company is in compliance with these requirements and, therefore, the Senior Notes indenture does not prohibit the Company from paying cash dividends.

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OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2008:

	Contractual Obligations (In thousands)
													2014 and
	Total		2009		2010		2011		2012		2013		thereafter

Long-term debt (1), (2)	$	3,315,904	$	60,623	$	141,678	$	991	$	816,355	$	250,687	$	2,045,570
Short-term borrowing,
including credit facilities (1)		401,459		401,459		-		-		-		-		-
Gas purchases (3)		343,643		144,926		132,351		2,607		2,580		2,551		58,628
Missouri Gas Energy Safety Program		126,372		11,662		12,887		10,869		10,977		11,087		68,890
Transportation contracts		432,299		78,691		78,256		77,522		72,822		46,517		78,491
Storage contracts (4)		235,890		37,310		34,221		32,262		23,266		20,673		88,158
Operating lease payments		127,732		21,354		16,275		16,525		14,164		14,130		45,284
Interest payments on debt (5)		4,193,527		205,797		197,141		192,426		170,202		163,266		3,264,695
Benefit plan contributions		11,463		11,463		-		-		-		-		-
Fractionation contract		136,820		-		13,682		13,682		13,682		13,682		82,092
Other (6)		17,753		9,572		911		900		802		397		5,171
Total contractual cash obligations	$	9,342,862	$	982,857	$	627,402	$	347,784	$	1,124,850	$	522,990	$	5,736,979

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(1)

The Company is party to debt agreements containing certain covenants that, if not satisfied, would give rise to an event of default that would cause such debt to become immediately due and payable. Such covenants require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios, and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. At December 31, 2008, the Company was in compliance with all of its covenants. See Item 8. Financial Statements and Supplementary Data, Note 13 – Debt Obligations.

(2)	The long-term debt principal payment obligations exclude $2.2 million of unamortized debt premium as of December 31, 2008.

(3)	The Company has purchase gas tariffs in effect for all its utility service areas that provide for recovery of its purchased gas costs under defined methodologies.

(4)	Represents charges for third party storage capacity.

(5)	Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2008. Includes approximately $2.5 billion of interest payments associated with the $600 million Junior Subordinated Notes due November 1, 2066.

(6)	Includes FIN No. 48 unrecognized tax benefits and various other contractual obligations.

Contingencies

See Item 8. Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies.

Inflation

The Company believes that inflation has caused, and will continue to cause, increases in certain operating expenses, and will continue to require higher capital replacement and construction costs. In the Transportation and Storage and Distribution segments, the Company continually reviews the adequacy of its rates in relation to the impact of market conditions, the increasing cost of providing services and the inherent regulatory lag experienced in adjusting those rates.

Regulatory

See Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

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Critical Accounting Policies

Summary

The Company’s consolidated financial statements have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and assumptions about future events and their effects cannot be determined with certainty. On an ongoing basis, the Company evaluates its estimates based on historical experience, current market conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Nevertheless, actual results may differ from these estimates under different assumptions or conditions.

In preparing the consolidated financial statements and related disclosure, the following are examples of certain areas that require significant management judgment in establishing related estimates and assumptions:

·	the economic lives of plant, property and equipment;

·	the fair values used to allocate purchase price and to determine possible asset impairment charges;

·	reserves for environmental claims, legal fees and other litigation or contingent liabilities;

·	provisions for income taxes and establishment of tax valuation reserves, including the interpretation of complex tax laws;

·	provisions for uncollectible receivables;

·	exposures under contractual indemnification;

·	pension and other postretirement benefit plan liabilities;

·	the fair values associated with derivative financial instruments; and

·	unbilled revenues.

The following is a summary of the Company’s most critical accounting policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a summary of all of the Company’s significant accounting policies, see Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters.

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Effects of Regulation

The Company is subject to regulation by certain state and federal authorities in each of its reportable segments and for certain of its operations reported in 2006 as discontinued operations. Missouri Gas Energy, New England Gas Company and Florida Gas have accounting policies that conform to FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement No. 71), and which are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities. The application of these accounting policies allows the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company. These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $69.6 million and $64.2 million at December 31, 2008 and 2007, respectively. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $6.6 million and $6.5 million at December 31, 2008 and 2007, respectively. For a summary of regulatory matters applicable to the Company, see Item 8. Financial Statements and Supplementary Data, Note 16 – Regulation and Rates. Panhandle and SUGS do not currently apply Statement No. 71.

Evaluation of Assets for Impairment

Long-lived assets, primarily consisting of property, plant and equipment, goodwill and equity method investments, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates about the carrying value of certain of these assets, including amounts to be capitalized, depreciation methods and useful lives. The Company also reviews these assets for impairment on a periodic basis or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable or such carrying amounts are in excess of the asset’s fair value. The Company primarily uses an income approach to estimate the recoverability or fair value of its assets, which requires it to make long-term forecasts of future net cash flows related to the assets. The process of estimating net cash flow forecasts is inherently subjective. Some of the key assumptions or estimates utilized by the Company in its cash flow forecast projections are:

·	Future demand for services provided by the Company;

·	Impact of future market conditions on customer and vendor pricing;

·	Regulatory developments;

·	Inflationary trends;

·	Estimated useful lives of assets and ongoing capital requirements;

·	Discount rates used; and

·	Terminal asset values using EBITDA-based market multiples.

Significant changes to these assumptions or estimates could require a provision for impairment in a future period.

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Long-Lived Assets Impairment Evaluation. The Company applies the provisions of FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No.144), to account for impairments on long-lived assets or asset groups used in operations that represent the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. Statement No. 144 requires a two-step test for impairment when circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. Step one determines if the carrying amount ascribed to a long-lived asset or asset group is recoverable based on undiscounted cash flows. If the asset or asset group fails the step one recoverability test (i.e. related carrying amount is in excess of the undiscounted cash flows), then, as a second step, the fair value of the asset or asset group is compared to the related carrying amount to determine the amount of impairment loss to be charged to earnings. The fair value in the second test is determined based upon discounted cash flows associated with the asset or asset group.

The long-lived assets of Sea Robin were evaluated as of December 31, 2008 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricanes Gustav and Ike. See related information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Investing Activities – Principal Capital Expenditure Projects – 2008 Hurricane Damage and Potential Sea Robin Impairment. Additionally, the long-lived assets of SUGS were evaluated as of December 31, 2008 because indicators of potential impairment were evident due to the onset of significant market-driven commodity price reductions in late 2008. The analyses indicated no recoverability issues were evident in the step one test described above.

Goodwill Impairment Evaluation. At December 31, 2008, the Company had goodwill balances in its Distribution segment of $44.4 million and $44.8 million applicable to the regulated operations of the Missouri Gas Energy and New England Gas Company reporting units, respectively. The Company assesses goodwill of each reporting unit for impairment at least annually as of November 30 based on FASB Statement 142, “Goodwill and Other Intangible Assets” (Statement No. 142), and updates the annual test on an interim basis if events or circumstances occur that would more likely than not reduce the fair value of the applicable reporting unit below its book carrying amount. A two-step impairment test is performed to identify a potential impairment and measure an impairment loss, if any, to be charged to earnings. In the first step, the fair value of the reporting unit, which is determined based on discounted cash flows, is compared to the reporting unit’s carrying amount, including goodwill. If the carrying amount of the reporting unit is greater than its fair value, the reporting unit’s goodwill may be impaired and step two must be completed. In the second step, the carrying amount of the reporting unit’s goodwill is compared with the implied fair value of such goodwill. If the carrying amount of the reporting unit’s goodwill is greater than its implied fair value, an impairment loss must be charged to earnings for the excess (i.e. recorded goodwill must be written down to implied fair value of the reporting unit’s goodwill). Because the fair value of goodwill can be measured only as a residual amount and cannot be determined directly, the implied fair value of a reporting unit’s goodwill is calculated in the same manner as the amount of goodwill that is recognized in a purchase business combination. This process involves measuring the fair value of the reporting unit’s assets and liabilities (both recognized and unrecognized) at the time of the impairment test by performing a hypothetical purchase price allocation. The difference between the reporting unit’s fair value and the fair values assigned to the reporting unit’s individual assets and liabilities (both recognized and unrecognized), is the implied fair value of the reporting unit’s goodwill.

The Company evaluated goodwill for potential impairment for the years ended December 31, 2008, 2007 and 2006, and no impairment was indicated in the step one test.

Equity method Investments. The Company applies the provisions of Accounting Principles Board Opinion 18, “The Equity Method of Accounting for Investments in Common Stock” (APB 18), to account for impairments of investments accounted for under the equity method of accounting. APB 18 requires that a loss in value of an investment, other than a temporary decline, should be recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments.

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Purchase Accounting

The Company’s March 1, 2006 acquisition of the Sid Richardson Energy Services business was accounted for using the purchase method of accounting in accordance with FASB Statement No. 141, “Business Combinations”. CCE Holdings, a joint venture in which the Company owned a 50 percent equity interest until it became a wholly-owned subsidiary on December 1, 2006 in conjunction with the closing of the Redemption Agreement, also applied the purchase method of accounting for its acquisition of CrossCountry Energy on November 17, 2004. Under this statement, the purchase price paid by the acquirer, including transaction costs, is allocated to the net assets acquired as of the acquisition date based on their fair value. Determining the fair value of certain assets acquired and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.

The Company effectively acquired an additional 25 percent interest in Citrus on December 1, 2006 as a result of the transactions described in Item 8. Financial Statements and Supplementary Data, Note 3 – Acquisitions and Sales – CCE Holdings Transactions. The purchase price allocation associated with this incremental equity investment in Citrus is accounted for under APB 18. For additional information, see Item 8. Financial Statements and Supplementary Data, Note 9 – Unconsolidated Investments – CCE Holdings Goodwill.

Pensions and Other Postretirement Benefits

The Company accounts for the measurement of its defined benefit postretirement plans under Statement No. 87, “Employers’ Accounting for Pensions” (Statement No. 87), as amended, and Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (Statement No. 106), as amended. Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements Nos. 87, 88, 106 and 132(R)” (Statement No. 158). Statement No. 158 does not amend the expense recognition provisions of Statements No. 87, 88 and 106, but requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity. Effective December 31, 2008, the Company adopted the measurement date provisions of Statement No. 158, which requires plan assets and benefit obligations to be measured as of its fiscal year-end balance sheet date.

Prior to the adoption of the recognition and disclosure provisions of Statement No. 158, Statement No. 87 required that a liability (minimum pension liability) be recorded when the accumulated benefit obligation liability exceeded the fair value of plan assets. Any adjustment was recorded as a non-cash charge to Accumulated other comprehensive loss. Statement No. 106 had no minimum liability provision. Under both Statements Nos. 87 and 106, changes in the funded status were not immediately recognized but rather were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its defined benefit postretirement plans through Accumulated other comprehensive loss.

The calculation of the Company’s pension expense and projected benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Company believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The Company establishes the discount rate using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Pension expense and projected benefit obligation (PBO) increases and equity decreases as the discount rate is reduced. Lowering the discount rate assumption by 0.5 percent would increase the Company’s 2008 pension expense and PBO at the end of 2008 by $500,000 and $9.8 million, respectively, and would decrease equity at the end of 2008 by $6.1 million.

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The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Pension expense increases as the expected rate of return on plan assets is reduced. Lowering the expected rate of return on plan assets assumption by 0.5 percent would increase the Company’s 2008 pension expense by $700,000.

See Item 8. Financial Statements and Supplementary Data, Note 14 – Benefits for additional related information.

Derivatives and Hedging Activities

The Company follows FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, to account for derivative and hedging activities. All derivatives are recognized on the 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 (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 (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 loss 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 the Fair Value Measurement discussion below for additional information related to the framework used by the Company to measure the fair value of its derivative financial instruments.

The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in the fair value or cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. The Company discontinues hedge accounting when: (i) it determines that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (ii) the derivative expires or is sold, terminated, or exercised; (iii) it is no longer probable that the forecasted transaction will occur; or (iv) management determines that designating the derivative as a hedging instrument is no longer appropriate. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Company will carry the derivative at its fair value on the balance sheet, recognizing changes in the fair value in current-period earnings. See Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities.

Fair Value Measurement. FASB Statement No. 157, “Fair Value Measurement” (Statement No. 157), provides a framework for measuring fair value. As defined in Statement No. 157, 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. Statement No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value as follows:

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

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

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

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

The Company’s Level 3 instruments include commodity derivative instruments, such as fixed-price forward sales contracts and certain natural gas basis swaps, and interest-rate swap derivatives that are valued using an income approach where at least one significant assumption or input to the underlying pricing model, discounted cash flow methodology or similar technique is unobservable – i.e. fixed-price forward sales contracts and natural gas swap valuations include basis adjustments to NYMEX forward curves obtained from third-party pricing services and interest rate swap valuations include composite yield curves provided by the bank counterparty. The financial assets and liabilities that the Company has categorized in Level 3 may later be reclassified to Level 2 when the Company is able to obtain additional observable market data to corroborate the unobservable inputs to models used to measure the fair value of these assets and liabilities. The Company’s Level 2 instruments include natural gas and NGL processing spread swap derivatives that are valued based on pricing models where significant inputs are observable. The Company’s Level 1 instruments consist of money market mutual funds and trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.

See Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – Fair Value Measurement and Note 25 – Fair Value Measurement for additional related information.

Income Taxes

Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, “Accounting for Income Taxes”. 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 bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the 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. Effective January 1, 2007, with the adoption of FIN No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48), the Company began evaluating its tax reserves under the recognition, measurement and derecognition thresholds as prescribed by FIN No. 48. See Item 8. Financial Statements and Supplementary Data, Note 15 – Taxes on Income for additional related information.

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Commitments and Contingencies

The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters. Accounting for contingencies requires significant judgments by management regarding the estimated probabilities and ranges of exposure to potential liability. For further discussion of the Company’s commitments and contingencies, see Item 8. Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies.

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 Risk.

The Company had approximately $964,000 and $43.5 million of fair value assets and liabilities, respectively, at December 31, 2008 that were measured using significant unobservable inputs (i.e. Statement No. 157 level 3 assets and liabilities). Although the Company does not have sufficient corroborative market evidence to support classifying certain level 3 assets and liabilities within level 2, the Company does not utilize significant unobservable inputs that are based on its own internal assumptions within these level 3 assets and liabilities. Rather, the Company utilizes non-binding broker quotes or third-party pricing services in determining their period-end fair value.

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, 2008, the interest rate on 89 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2008, $43.6 million is included in Deferred Credits in the Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012.

At December 31, 2008, a 100 basis point move in the annual interest rate on all outstanding floating-rate long- and short-term debt would increase the Company’s interest payments by approximately $500,000 for each month during which such increase 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, 2008 is not material to the Company.

See Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities and Note 13 - Debt Obligations.

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Commodity Price Risk

Gathering and Processing Segment. The Company markets natural gas and NGL in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments. These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts, but also the risks associated with unmatched positions and market fluctuations. The Company is required to record its commodity derivative financial instruments at fair value, which is affected by commodity exchange prices, over-the-counter quotes, volatility, time value, credit and counterparty credit risk and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e. receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps, and exchange-traded futures and options. These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are highly effective in offsetting changes in physical market commodity prices and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.

The Company realizes NGL and/or natural gas volumes from the contractual arrangements associated with the gas processing services it provides. Expected NGL and/or natural gas volumes compared to the actual volumes sold and the effectiveness of the associated economic hedges utilized by the Company can be unfavorably impacted by:

·	Processing plant outages;

·	Higher than anticipated fuel, flare and unaccounted-for natural gas levels;

·	Impact of commodity prices in general;

·	Decline in drilling and/or connections of new supply;

·	Reduction in available NGL take-away capacity;

·	Reduction in NGL available from wellhead supply;

·	Lower than expected recovery of NGL from the inlet gas stream; and

·	Lower than expected receipt of natural gas volumes to be processed.

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The following table summarizes SUGS' principal commodity derivative instruments as of December 31, 2008 (all instruments are settled monthly), which were developed based upon operating conditions and expected equity (Company-owned) natural gas and NGL sales volumes.

Instrument Type	Index	Average Fixed Price (per MMBtu)		Volumes (MMBtu/d) (3)		Fair Value of Assets
						(In thousands)
Natural Gas - Cash Flow Hedges (1)
Fixed-rate swap	Gas Daily - Waha	$	9.49		11,050	$	16,991
Fixed-rate swap	Gas Daily - El Paso Permian	$	9.49		8,950		13,762
		Total			20,000	$	30,753

Processing Spread - Economic Hedges (2)
Fixed-rate swap	Gas Daily - Waha (natural gas)	$	7.40		16,575	$	32,988
	OPIS - Mt. Belvieu (NGL)
Fixed-rate swap	Gas Daily - El Paso Permian (natural gas)	$	7.40		13,425		26,718
	OPIS - Mt. Belvieu (NGL)
		Total			30,000	$	59,706

__________________

(1)

The Company’s natural gas swap arrangements have been designated as cash flow hedges. The effective portion of changes in the fair value of the cash flow hedges is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings.

(2)

The Company’s processing spread swap arrangements, which hedge the pricing differential between NGL volumes and natural gas volumes, are treated as economic hedges. The ratio of NGL product sold per MMBtu is approximately: 33 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 16 percent natural gasoline. The change in fair value is reported in current-period earnings.

(3)	All volumes are applicable to the period January 1, 2009 to December 31, 2009.

There were no up-front costs associated with the derivative instruments entered into in 2008.

At December 31, 2008, excluding the effects of hedging and assuming normal operating conditions, the Company estimates that a change in price of $0.01 per gallon of NGL and $0.10 per MMBtu of natural gas would impact gross margin by approximately $1.7 million and $250,000, respectively. Such commodity price risk estimates do not include any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause some ethane to be sold in the natural gas stream, impacting gathering and processing margins, natural gas deliveries and NGL volumes shipped.

Transportation and Storage Segment. 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 operating compression to move the customers’ 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 amounts 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, 2008, there were no hedges in place in respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment Economic Hedging Activities. The Company has entered into natural gas commodity fixed-rate (i.e., pay fixed price) swaps to mitigate price volatility of purchased natural gas passed through to customers in the Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the Consolidated Balance Sheet. As of December 31, 2008, the fair values of the contracts, which expire at various times through October 2010, are included in the Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of gas of $92.7 million.

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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

Southern Union 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 Company’s CEO 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 CEO and CFO, and with the participation of personnel from its Legal, Internal Audit, Risk Management 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, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2008.

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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.

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, 2008.

The Company’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Southern Union Company

February 26, 2009

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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ITEM 9B. Other Information.

All information required to be reported on Form 8-K for the quarter ended December 31, 2008 was appropriately reported.

On February 24, 2009, the Company’s Board of Directors, upon recommendation of the Company’s Corporate Governance Committee, approved individual Indemnification Agreements (“Indemnification Agreements”) between the Company and each of the Company’s directors and certain senior executive officers. The senior executive officers receiving Indemnification Agreements are Eric D. Herschmann, the Company's President and Chief Operating Officer, Robert O. Bond, the Company's Senior Vice President - Pipeline Operations and President and Chief Operating Officer of PEPL, Richard N. Marshall, the Company's Senior Vice President and Chief Financial Officer, and Monica M. Gaudiosi, the Company's Senior Vice President and General Counsel. George L. Lindemann also received an Indemnification Agreement by virtue of his status as Chairman of the Board and as the Company’s Chief Executive Officer.

The Indemnification Agreements are designed to ensure that the rights to indemnification and advancement of expenses to which the directors and the senior executive officers are currently entitled under the Company’s Bylaws will not be eliminated, diminished or otherwise adversely affected without the consent of the individual director or senior executive.

The foregoing description does not purport to be a complete summary of the Indemnification Agreements and is qualified in its entirety by reference to the full text of the form of Indemnification Agreement attached as Exhibit 10(g) hereto.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance.

There is incorporated in this Item 10 by reference the information that will appear in the Company’s definitive proxy statement for the 2009 Annual Meeting of Stockholders under the captions Meetings and Committees of the Board – Board of Directors, 2008 Executive Compensation – Named Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance – Code of Ethics, Meetings and Committees of the Board – Board Committees – Corporate Governance Committee and – Audit Committee.

The CEO Certification and Annual Written Affirmation required by the NYSE Listing Standards, Section 303A.12(a), relating to the Company’s compliance with the NYSE Corporate Governance Listing Standards, was submitted to the NYSE on June 10, 2008.

ITEM 11. Executive Compensation.

There is incorporated in this Item 11 by reference the information that will appear in the Company’s definitive proxy statement for the 2009 Annual Meeting of Stockholders under the captions Compensation Discussion and Analysis, 2008 Executive Compensation, 2008 Director Compensation, and Meetings and Committees of the Board – Board Committees – Compensation Committee.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

There is incorporated in this Item 12 by reference the information that will appear in the Company’s definitive proxy statement for the 2009 Annual Meeting of Stockholders under the caption Security Ownership of Certain Beneficial Owners and Management.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence.

There is incorporated in this Item 13 by reference the information that will appear in the Company’s definitive proxy statement for the 2009 Annual Meeting of Stockholders under the caption Corporate Governance – Transactions with Related Persons and – Review, Approval or Ratification of Transactions with Related Persons, and Corporate Governance – Director Independence and – Lead Independent Director.

ITEM 14. Principal Accountant Fees and Services.

There is incorporated in this Item 14 by reference the information that will appear in the Company’s definitive proxy statement for the 2009 Annual Meeting of Stockholders under the caption Meetings and Committees of the Board – Board Committees – Audit Committee.

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PART IV

ITEM 15. Exhibits, Financial Statement Schedules.

(a)(1) and (2)

Financial Statements and Financial Statement Schedules.

(a)(3)

Exhibits.

Exhibit No. Description

2(a)

Purchase and Sale Agreement by and among SRCG, Ltd. and SRG Genpar, L.P., as Sellers and Southern Union Panhandle LLC and Southern Union Gathering Company LLC, as Buyers, dated as of December 15, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 16, 2005 and incorporated herein by reference.)

2(b)

Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)

2(c)

First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(d)

Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)

2(e)

Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(f)

First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(g)

Redemption Agreement by and between CCE Holdings, LLC and Energy Transfer Partners, L.P., dated as of September 18, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on September 18, 2006 and incorporated herein by reference.)

2(h)

Letter Agreement by and between Southern Union Company and Energy Transfer Partners, L.P., dated as of September 14, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on September 18, 2006 and incorporated herein by reference)

3(a)

Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)

3(b)

By-Laws of Southern Union Company, as amended through January 3, 2007. (Filed as Exhibit 3.1 to Southern Union’s Current Report on Form 8-K filed on January 3, 2007 and incorporated herein by reference.)

3(c)

Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 and incorporated herein by reference.)

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4(a)

Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)

4(b)

Indenture between The Bank of New York Trust Company, N.A., as successor to Chase Manhattan Bank, N.A., as trustee, and Southern Union Company dated January 31, 1994. (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)

4(c)

Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024. (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)

4(d)

Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029. (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)

4(e)

Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank (formerly the Chase Manhattan Bank, National Association). (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)

4(f)

Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank, N.A. (f/n/a JP Morgan Chase Bank). (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

4(g)

Subordinated Debt Securities Indenture between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank (as successor to The Chase Manhattan Bank, N.A.), as Trustee. (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(h)

Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., successor to JP Morgan Chase Bank, N.A., formerly known as JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank (National Association). (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)

4(i)

2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006 (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

4(j)

Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

4(k)	Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union. Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.

10(a)

First Amendment to Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of August 6, 2008. (Filed as Exhibit 10(a) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

10(b)

Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)

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10(c)

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(d) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

10(d)

Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline 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 Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)

10(e)

Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)

10(f)

Fifth Amended and Restated Revolving Credit Agreement, dated as of June 20, 2008, among the Company, as borrower, and the lenders party thereto. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on June 25, 2008 and incorporated herein by reference.)

10(g)

Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company and certain senior executive officers.

10(h)

Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.) *

10(i)

Southern Union Company Director's Deferred Compensation Plan. (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)

10(j)

First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference.)

10(k)

Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments. (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.) *

10(l)

Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.) *

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10(m)

Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.) *

10(n)

Employment Agreement between Southern Union Company and George L. Lindemann, dated as of August 28, 2008. (Filed as Exhibit 10(f) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(o)

Employment Agreement between Southern Union Company and Eric D. Herschmann, dated as of August 28, 2008. (Filed as Exhibit 10(g) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(p)

Employment Agreement between Southern Union Company and Robert O. Bond, dated as of August 28, 2008. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(q)

Employment Agreement between Southern Union Company and Monica M. Gaudiosi, dated as of August 28, 2008. (Filed as Exhibit 10(i) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(r)

Employment Agreement between Southern Union Company and Richard N. Marshall, dated as of August 28, 2008. (Filed as Exhibit 10(j) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(s)

Form of Change in Control Severance Agreement, between Southern Union Company and certain Executives (filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 28, 2008 and incorporated herein by reference.) *

10(t)

Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp.

10(u)

Certificate of Incorporation of Citrus Corp. (Filed as Exhibit 10(q) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

10(v)

By-Laws of Citrus Corp., filed herewith. (Filed as Exhibit 10(r) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

Ratio of earnings to fixed charges.

Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)

Subsidiaries of the Registrant.

23.1

Consent of Independent Registered Public Accounting Firm for Southern Union Company.

23.2	Consent of Independent Registered Public Accounting Firm for Citrus Corp.

Power of Attorney.

31.1

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

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31.2

Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 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 Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 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 Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 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.

____________

* Management contract or compensation plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Union has duly caused this report to be signed by the undersigned, thereunto duly authorized, on February 26, 2009.

	SOUTHERN UNION COMPANY

	By: /s/ George L. Lindemann
	George L. Lindemann
	Chairman of the Board and
	Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Southern Union and in the capacities indicated as of February 26, 2009.

Signature/Name	Title
/s/ George L. Lindemann* George L. Lindemann	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)
/s/ Richard N. Marshall Richard N. Marshall	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ George E. Aldrich George E. Aldrich	Senior Vice President and Controller (Chief Accounting Officer)
/s/ Michal Barzuza* Michal Barzuza /s/ David Brodsky* David Brodsky	Director Director
/s/ Frank W. Denius* Frank W. Denius	Director
/s/ Kurt A. Gitter, M.D.* Kurt A. Gitter, M.D	Director
/s/ Herbert H. Jacobi* Herbert H. Jacobi	Director
/s/ Adam M. Lindemann* Adam M. Lindemann	Director
/s/ Thomas N. McCarter, III* Thomas N. McCarter, III	Director
/s/ George Rountree, III* George Rountree, III	Director
/s/ Allan D. Scherer* Allan Scherer	Director

*By: /s/ RICHARD N. MARSHALL	*By: /s/ ROBERT M. KERRIGAN, III
Richard N. Marshall	Robert M. Kerrigan, III
Senior Vice President and Chief Financial Officer	Vice President, Assistant General Counsel and
Attorney-in-fact	Secretary
	Attorney-in-fact

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:	Page(s):
Consolidated Statement of Operations	F-2
Consolidated Balance Sheet	F-3 - F-4
Consolidated Statement of Cash Flows	F-5
Consolidated Statement of Stockholders’ Equity and Comprehensive Income	F-6 - F-7
Notes to Consolidated Financial Statements	F-8
Report of Independent Registered Public Accounting Firm	F-71

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

	Years Ended December 31,
	2008			2007			2006
	(In thousands, except per share amounts)
Operating revenues (Note 21):
Gas distribution	$	821,673		$	732,109		$	668,721
Gas transportation and storage		721,640			658,446			577,182
Gas gathering and processing		1,521,041			1,221,747			1,090,216
Other		5,800			4,363			4,025
Total operating revenues		3,070,154			2,616,665			2,340,144

Operating expenses:
Cost of gas and other energy		1,774,682			1,483,715			1,377,147
Revenue-related taxes		44,259			38,584			35,281
Operating, maintenance and general		473,614			444,408			381,844
Depreciation and amortization		199,249			177,999			152,103
Taxes, other than on income and revenues		48,371			44,874			38,684
Total operating expenses		2,540,175			2,189,580			1,985,059

Operating income		529,979			427,085			355,085

Other income (expenses):
Interest expense		(207,408	)		(203,146	)		(210,043	)
Earnings from unconsolidated investments		75,030			100,914			141,370
Other, net (Note 4)		2,325			(883	)		39,918
Total other expenses, net		(130,053	)		(103,115	)		(28,755	)

Earnings from continuing operations before income taxes		399,926			323,970			326,330

Federal and state income taxes (Note 15)		104,775			95,259			109,247

Earnings from continuing operations		295,151			228,711			217,083

Discontinued operations (Note 19):
Loss from discontinued operations before
income taxes		-			-			(2,369	)
Federal and state income taxes		-			-			150,583
Loss from discontinued operations		-			-			(152,952	)

Net earnings		295,151			228,711			64,131

Preferred stock dividends		(12,212	)		(17,365	)		(17,365	)
Loss on extinguishment of preferred stock		(3,527	)		-			-

Net earnings available for common stockholders	$	279,412		$	211,346		$	46,766

Net earnings available for common stockholders
from continuing operations per share (Note 5):
Basic	$	2.26		$	1.76		$	1.74
Diluted	$	2.26		$	1.75		$	1.70

Net earnings available for common stockholders per
share (Note 5):
Basic	$	2.26		$	1.76		$	0.41
Diluted	$	2.26		$	1.75		$	0.40
Cash dividends declared on common stock per share:	$	0.60		$	0.45		$	0.40

Weighted average shares outstanding (Note 5):
Basic		123,446			119,930			114,787
Diluted		123,644			120,674			117,344

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

ASSETS

	December 31,
	2008			2007
	(In thousands)
Current assets:
Cash and cash equivalents	$	4,318		$	5,690
Accounts receivable, billed and unbilled,
net of allowances of $6,003 and $4,144, respectively		327,358			358,521
Accounts receivable – affiliates		14,743			29,943
Inventories		337,858			263,618
Deferred gas purchase costs		64,330			3,496
Gas imbalances - receivable		174,100			105,371
Derivative financial instruments (Note 25)		91,423			6,999
Prepayments and other assets		18,226			34,686
Total current assets		1,032,356			808,324

Property, plant and equipment (Note 6):
Plant in service		5,980,297			5,509,992
Construction work in progress		451,359			377,918
		6,431,656			5,887,910
Less accumulated depreciation and amortization		(974,651	)		(785,623	)
Net property, plant and equipment		5,457,005			5,102,287

Deferred charges:
Regulatory assets (Note 8)		69,554			64,193
Deferred charges		59,958			60,468
Total deferred charges		129,512			124,661

Unconsolidated investments (Note 9)		1,259,270			1,240,420

Goodwill (Note 7)		89,227			89,227

Other		30,537			32,994


Total assets	$	7,997,907		$	7,397,913

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,
	2008			2007
	(In thousands)
Stockholders’ equity (Note 10):
Common stock, $1 par value; 200,000 shares authorized;
125,122 and 121,102 shares issued at December 31, 2008 and 2007	$	125,122		$	121,102
Preferred stock, no par value; 6,000 shares authorized;
460 and 920 shares issued at December 31, 2008 and 2007 (Note 12)		115,000			230,000
Premium on capital stock		1,893,975			1,784,223
Less treasury stock: 1,120 and 1,063
shares, respectively, at cost		(28,004	)		(27,839	)
Less common stock held in trust: 663
and 783 shares, respectively		(11,908	)		(15,085	)
Deferred compensation plans		11,908			15,148
Accumulated other comprehensive loss		(51,423	)		(11,594	)
Retained earnings		313,282			109,851
Total stockholders' equity		2,367,952			2,205,806

Long-term debt obligations (Note 13)		3,257,434			2,960,326

Total capitalization		5,625,386			5,166,132

Current liabilities:
Long-term debt due within one year (Note 13)		60,623			434,680
Notes payable (Note 13)		401,459			123,000
Accounts payable and accrued liabilities		246,884			335,253
Federal, state and local taxes payable		54,027			35,461
Accrued interest		41,141			45,911
Gas imbalances - payable		341,987			272,850
Derivative financial instruments (Note 25)		77,554			-
Other		128,190			76,558
Total current liabilities		1,351,865			1,323,713

Derivative financial instruments (Note 25)		59,768			39,469

Deferred credits		238,338			175,594

Accumulated deferred income taxes (Note 15)		722,550			693,005

Commitments and contingencies (Note 18)

Total stockholders' equity and liabilities	$	7,997,907		$	7,397,913

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	295,151		$	228,711		$	64,131
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		199,249			177,999			154,601
Amortization of debt expense, net		965			743			12,130
Deferred income taxes		83,066			71,147			225,843
Provision for bad debts		12,338			11,391			20,151
Provision for impairment of other assets		-			7,660			6,500
Unrealized (gain) loss on derivative		(57,821	)		9			(55,146	)
Loss on sale of subsidiaries and other assets		-			-			56,815
Non-cash stock compensation		6,468			3,345			6,804
Earnings from unconsolidated investments, adjusted for cash distributions		2,120			2,636			(92,607	)
Other		10,283			12,999			(5,643	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable, billed and unbilled		6,168			(76,778	)		147,450
Accounts payable and accrued liabilities		(48,416	)		(22,788	)		(67,021	)
Deferred gas purchase costs		9,501			(19,047	)		(35,906	)
Inventories		(67,786	)		41,113			(14,369	)
Deferred charges and credits		(16,806	)		(3,443	)		(37,459	)
Prepaids and other assets		16,755			47,700			104,889
Taxes and other liabilities		35,592			(12,989	)		(32,358	)
Net cash flows provided by operating activities		486,827			470,408			458,805
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(588,611	)		(616,883	)		(347,896	)
Acquisitions of operations, net of cash received		-			-			(1,537,627	)
Proceeds (payments) from sale of subsidiaries		-			(49,304	)		1,076,714
Plant retirements and other		19,659			(417	)		2,005
Net cash flows used in investing activities		(568,952	)		(666,604	)		(806,804	)
Cash flows provided by (used in) financing activities:
Decrease in book overdraft		(19,932	)		(7,738	)		(4,941	)
Issuance of long-term debt		403,820			755,000			1,065,000
Issuance costs of debt and equity		(4,073	)		(5,794	)		(10,590	)
Issuance of common stock and equity units		100,000			-			125,000
Issuance of Bridge Loan		-			-			1,600,000
Repayment of Bridge Loan		-			-			(1,600,000	)
Dividends paid on common and preferred stock		(88,164	)		(65,295	)		(51,695	)
Extinguishment of preferred stock		(115,232	)		-			-
Repayment of debt obligations		(476,829	)		(508,406	)		(470,365	)
Net (payments) borrowings under revolving credit facilities		278,459			23,000			(320,000	)
Proceeds from exercise of stock options		4,009			3,718			9,216
Other		(1,305	)		1,650			(4,813	)
Net cash flows provided by financing activities		80,753			196,135			336,812
Change in cash and cash equivalents		(1,372	)		(61	)		(11,187	)
Cash and cash equivalents at beginning of period		5,690			5,751			16,938
Cash and cash equivalents at end of period	$	4,318		$	5,690		$	5,751


Cash paid for interest, net of amounts capitalized	$	221,152		$	213,656		$	204,573
Cash paid for income taxes, net of refunds		(4,001	)		13,979			50,750

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Common	Preferred	Premium		Common	Deferred	Accumulated		Total
	Stock,	Stock,	on	Treasury	Stock	Compen-	Other	Retained	Stock-
	$1 Par	No Par	Capital	Stock,	Held	sation	Comprehensive	Earnings	holders'
	Value	Value	Stock	at cost	In Trust	Plans	Income (Loss)	(Deficit)	Equity
	(In thousands)

Balance December 31, 2005	$ 112,530	$ 230,000	$1,681,167	$ (27,566)	$ (12,910)	$ 10,173	$ (56,272)	$ (83,053)	$ 1,854,069


Comprehensive income (loss):
Net earnings	-	-	-	-	-	-	-	64,131	64,131
Net change in other
comprehensive loss (Note 22),	-	-	-	-	-	-	39,328	-	39,328
Comprehensive income									103,459
Adjustment to initially apply FASB
Statement No. 158	-	-	-	-	-	-	16,043	-	16,043
Preferred stock dividends	-	-	(8,683)	-	-	-	-	(8,682)	(17,365)
Cash dividends declared	-	-	(26,366)	-	-	-	-	(19,923)	(46,289)
Share-based compensation	-	-	6,804	-	-	-	-	-	6,804
Implementation of FAS 123R	-	-	(2,800)	-	-	2,800	-	-	-
Restricted stock awards	146	-	(146)	(142)	-	-	-	-	(142)
Exercise of stock options	629	-	9,544	-	-	-	-	-	10,173
Contributions to Trust	-	-	-	-	(3,079)	3,079	-	-	-
Disbursements from Trust	-	-	-	-	1,361	(1,361)	-	-	-
Equity Units Conversion	7,413	-	116,243	-	-	-	-	-	123,656
Balance December 31, 2006	$ 120,718	$ 230,000	$1,775,763	$ (27,708)	$ (14,628)	$ 14,691	$ (901)	$ (47,527)	$ 2,050,408
Comprehensive income (loss):
Net earnings	-	-	-	-	-	-	-	228,711	228,711
Net change in other
comprehensive loss (Note 22),	-	-	-	-	-	-	(10,693)	-	(10,693)
Comprehensive income	-	-	-	-	-	-	-	-	218,018
Preferred stock dividends	-	-	-	-	-	-	-	(17,365)	(17,365)
Cash dividends declared	-	-	-	-	-	-	-	(53,968)	(53,968)
Share-based compensation	-	-	3,345	-	-	-	-	-	3,345
Restricted stock issuances	111	-	(111)	(131)	-	-	-	-	(131)
Exercise of stock options	273	-	5,226	-	-	-	-	-	5,499
Contributions to Trust	-	-	-	-	(769)	769	-	-	-
Disbursements from Trust	-	-	-	-	312	(312)	-	-	-
Balance December 31, 2007	$ 121,102	$ 230,000	$ 1,784,223	$ (27,839)	$ (15,085)	$ 15,148	$ (11,594)	$ 109,851	$ 2,205,806

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)

	Common	Preferred	Premium		Common	Deferred	Accumulated		Total
	Stock,	Stock,	on	Treasury	Stock	Compen-	Other		Stock-
	$1 Par	No Par	Capital	Stock,	Held	sation	Comprehensive	Retained	holders'
	Value	Value	Stock	at cost	In Trust	Plans	Income (Loss)	Earnings	Equity
	(In thousands)

Balance December 31, 2007	$ 121,102	$ 230,000	$ 1,784,223	$ (27,839)	$ (15,085)	$ 15,148	$ (11,594)	$ 109,851	$ 2,205,806
Comprehensive income (loss):
Net earnings	-	-	-	-	-	-	-	295,151	295,151
Net change in other
comprehensive loss (Note 22),	-	-	-	-	-	-	(40,920)	-	(40,920)
Comprehensive income	-	-	-	-	-	-	-	-	254,231
Effect of changing plan meas-
urement date pursuant to
Adoption of FASB Statement
No. 158 Measurement Date
Provisions (Note 14)	-	-	-	-	-	-	1,091	(1,597)	(506)
Preferred stock dividends	-	-	-	-	-	-	-	(12,212)	(12,212)
Cash dividends declared	-	-	-	-	-	-	-	(74,384)	(74,384)
Issuance of common stock -
remarketing obligation
(Note 13)	3,693	-	96,307	-	-	-	-	-	100,000
Share-based compensation	-	-	6,468	-	-	-	-	-	6,468
Restricted stock issuances	90	-	(90)	(165)	-	-	-	-	(165)
Exercise of stock options	237	-	3,772	-	-	-	-	-	4,009
Extinguishment of preferred
stock (Note 12)	-	(115,000)	3,295	-	-	-	-	(3,527)	(115,232)
Contributions to Trust	-	-	-	-	(1,096)	1,096	-	-	-
Disbursements from Trust	-	-	-	-	4,273	(4,336)	-	-	(63)
Balance December 31, 2008	$ 125,122	$ 115,000	$ 1,893,975	$ (28,004)	$ (11,908)	$ 11,908	$ (51,423)	$ 313,282	$ 2,367,952

The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 par value, is equivalent to the change in the number of shares of common stock issued.

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Structure

Operations. The Company was incorporated under the laws of the State of Delaware in 1932. The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States. Through Panhandle, the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.5 Bcf/d of 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 regions. Panhandle also owns and operates a LNG import terminal located on Louisiana’s Gulf Coast. Through its investment in Citrus, the Company has an interest in and operates Florida Gas, an interstate pipeline company that transports natural gas from producing areas in South Texas through the Gulf Coast region to Florida. See the related discussion of the change in ownership interests of CCE Holdings on December 1, 2006 applicable to Florida Gas and Transwestern in Note 3 – Acquisitions and Sales – CCE Holdings Transactions. Through SUGS, the Company owns approximately 4,900 miles of natural gas and NGL pipelines, four cryogenic plants with a combined capacity of 415 MMcf/d and five natural gas treating plants with combined capacities of 640 MMcf/d. SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are located in West Texas and Southeast New Mexico. Through Southern Union’s regulated utility operations, Missouri Gas Energy and the Massachusetts operations of New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively. The Company’s discontinued operations relate to its PG Energy natural gas distribution division in Pennsylvania and the Rhode Island operations of its New England Gas Company natural gas distribution division, which were sold on August 24, 2006. See Note 19 – Discontinued Operations for information related to the Company’s discontinued operations and Note 21 – Reportable Segments for information related to the Company’s reportable segments.

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.

Principles of Consolidation. The consolidated financial statements include the accounts of Southern Union and its wholly-owned subsidiaries. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method. All significant intercompany accounts and transactions are eliminated in consolidation. Certain reclassifications have been made to prior years' 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.

Purchase Accounting. The Company’s March 1, 2006 acquisition of the Sid Richardson Energy Services business was accounted for using the purchase method of accounting in accordance with FASB Statement No. 141, “Business Combinations”. Under this statement, the purchase price paid by the acquirer, including transaction costs, is allocated to the assets and liabilities acquired as of the acquisition date based on their fair values. Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions. See Note 3 – Acquisitions and Sales – Acquisition of Sid Richardson Energy Services.

Southern Union effectively acquired an additional 25 percent interest in Citrus on December 1, 2006 as a result of the transactions described in Note 3 – Acquisitions and Sales – CCE Holdings Transactions. The allocation of fair value associated with this incremental equity investment in Citrus is accounted for under Accounting Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock (APB 18). For additional information, see Note 9 – Unconsolidated Investments – CCE Holdings Goodwill Evaluation.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 renewals 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.

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. Depreciation rates for the utility plants are approved by the applicable regulatory commissions.

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.

For additional information, see Note 6 – Property, Plant and Equipment.

Asset Impairment. The Company applies the provisions of FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No.144), to account for impairments on long-lived assets. Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the asset group’s carrying value. The amount of impairment is measured by comparing the fair value of the asset group to its carrying amount. The long-lived assets of Sea Robin were evaluated as of December 31, 2008 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricanes Gustav and Ike. Additionally, the long-lived assets of SUGS were evaluated as of December 31, 2008 because indicators of potential impairment were evident due to the onset of significant market-driven commodity price reductions in late 2008. The analyses indicated no recoverability issues were evident.

Goodwill. The Company accounts for its goodwill and other intangible assets in accordance with FASB Statement No. 142, “Accounting for Goodwill and Other Intangible Assets”. Goodwill acquired in a purchase business combination and determined to have an indefinite useful life is not amortized, but instead is tested for impairment at a reporting unit level at least annually by applying a fair-value based test. The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value. The Company’s goodwill is related to its Distribution segment. See Note 7 – Goodwill.

Cash and Cash Equivalents. The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Short-term investments are highly liquid investments with maturities of more than three months when purchased, and are carried at cost, which approximates market. The Company places its temporary cash investments with a high credit quality financial institution that, in turn, invests the temporary funds in a variety of high-quality short-term financial securities.

Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the Consolidated Balance Sheet. At December 31, 2008 and 2007, such book overdraft balances classified in accounts payable were approximately $17.6 million and $37.5 million, respectively.

Segment Reporting. FASB Statement No. 131, “Disclosures about Segments of an Enterprise and Related Information”, requires disclosure of segment data based on how management makes decisions about allocating resources to segments and measuring performance. The Company is principally engaged in the transportation and storage, gathering and processing and distribution of natural gas in the United States, and reports these operations under three reportable segments: the Transportation and Storage segment, the Gathering and Processing segment and the Distribution segment. See Note 21 – Reportable Segments for additional related information.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transportation and Storage Revenues. In the Transportation and Storage segment, revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered to customers, depending on the tariff of that particular entity, with any differences in received and delivered volumes resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of PEPL’s subsidiary, 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.

Gathering and Processing Revenues and Cost of Sales Recognition. The business operations of the Gathering and Processing segment consist of connecting wells of natural gas producers to the Company’s gathering system, treating natural gas to remove impurities, processing natural gas for the removal of NGL and then redelivering or marketing the treated natural gas and/or processed NGL to third parties. The terms and conditions of purchase arrangements with producers, including those limited arrangements with the same counterparty, offer various alternatives with respect to taking title to the purchased natural gas and/or NGL. These arrangements include (i) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing in the Company’s plant facilities and (ii) making other direct purchase of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. Cost of sales primarily includes the cost of purchased natural gas and/or NGL to which the Company has taken title. Operating revenues are derived from the sale of natural gas and/or NGL in the period in which the physical product is delivered to the customer and title is transferred. Pursuant to the guidance in Emerging Issues Task Force Issue No. 99-19, “Reporting Revenue Gross as a Principal Versus Net as an Agent”, operating revenues and cost of sales within the Gathering and Processing segment are reported on a gross basis.

Gas Distribution Revenues and Gas Purchase Costs. In the Distribution segment, gas utility customers are billed on a monthly-cycle basis. The related cost of gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction. Revenues from gas delivered but not yet billed are accrued, along with the related gas purchase costs and revenue-related taxes. Unbilled receivables related to the Distribution segment recorded in Accounts receivable in the Consolidated Balance Sheet at December 31, 2008 and 2007 were $60.4 million and $56.8 million, respectively.

Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. In the Transportation and Storage and Gathering and Processing segments, 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. In the Distribution segment, concentrations of credit risk in trade receivables are limited due to the large customer base with relatively small individual account balances. Additionally, the Company requires a deposit from customers in the Distribution segment who lack a credit history or whose credit rating is substandard. 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Beginning balance	$	4,144		$	4,830		$	15,893
Additions: charged to cost and expenses (1)		12,338			11,391			9,646
Deductions: write-off of uncollectible accounts		(10,560	)		(12,657	)		(9,756	)
Balance related to discontinued operations (2)		-			-			(10,968	)
Other		81			580			15
Ending balance	$	6,003		$	4,144		$	4,830

_________________

(1) Additions charged to cost and expenses applicable to continuing operations for the years ended December 31, 2008, 2007 and 2006 were $12.3 million, $11.4 million and $9.6 million, respectively.

(2)	Represents elimination of the allowance for doubtful accounts balance resulting from the Company’s August 24, 2006 sale of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.

Earnings Per Share. The Company’s earnings per share presentation conforms to FASB Statement No. 128, “Earnings per Share”. Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, increased by the assumed conversion of equity units, the assumed exercises of stock options and SARs, and the assumed vesting of restricted stock. See Note 10 – Stockholders’ Equity – Dividends.

Stock-Based Compensation. The Company follows FASB Statement No. 123(R), “Accounting for Stock-Based Compensation” (Statement No. 123R), to account for stock-based employee compensation. The Company adopted Statement No. 123R effective January 1, 2006, using the modified prospective method. The statement requires the Company to measure all employee stock-based compensation using a fair value method and record such expense in its Consolidated Statement of Operations. For more information, see Note 24 – Stock-Based Compensation.

Accumulated Other Comprehensive Loss. The Company reports comprehensive income (loss) and its components in accordance with FASB Statement No. 130, “Reporting Comprehensive Income”. The main components of comprehensive income (loss) that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss) and prior service credits (cost) on pension and other postretirement plans. For more information, see Note 22 – Accumulated Other Comprehensive Loss.

Inventories. In the Transportation and Storage segment, inventories consist of natural gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while gas received from or owed back to customers is valued at market. The 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.

In the Gathering and Processing segment, inventories consist of non-fractionated Y-grade NGL and materials and supplies, both of which are stated at the lower of weighted average cost or market. Materials and supplies are primarily comprised of compressor components and parts. The Company recorded a charge to earnings of $1.8 million in 2008 to reduce the Y-grade NGL inventory carrying value to market value as of December 31, 2008.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies. The natural gas in underground storage inventory carrying value is stated at weighted average cost and is not adjusted to a lower market value because, pursuant to purchased natural gas adjustment clauses, actual natural gas costs are recovered in customers’ rates. Materials and supplies inventory is also stated at weighted average cost.

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The components of inventory at the dates indicated are as follows:

	Transportation & Storage		Gathering & Processing		Distribution		Total
At December 31, 2008	(In thousands)
Current
Natural gas held for operations (1)	$	182,547	$	-	$	-	$	182,547
Materials and Supplies		14,056		9,278		4,488		27,822
NGL (2)		-		8,521		-		8,521
Natural gas in underground storage (3)		-		-		118,968		118,968
Total Current		196,603		17,799		123,456		337,858

Non-Current
Natural gas held for operations (1)		17,687		-		-		17,687

	$	214,290	$	17,799	$	123,456	$	355,545


At December 31, 2007
Current
Natural gas held for operations (1)	$	168,010	$	-	$	-	$	168,010
Materials and Supplies		12,791		6,176		3,822		22,789
Natural gas in underground storage (3)		-		-		72,819		72,819
Total Current		180,801		6,176		76,641		263,618

Non-Current
Natural gas held for operations (1)		18,947		-		-		18,947

	$	199,748	$	6,176	$	76,641	$	282,565

____________________

(1)	Natural gas volumes held for operations at December 31, 2008 and December 31, 2007 were 31,751,000 MMBtu and 26,001,000 MMBtu, respectively.

(2)	NGL at December 31, 2008 and December 31, 2007 was 20,453,000 gallons and nil, respectively.

(3)	Natural gas volumes in underground storage at December 31, 2008 and December 31, 2007 were 12,702,000 MMBtu and 11,823,000 MMBtu, respectively.

Unconsolidated Investments. Investments in affiliates over which the Company may exercise significant influence, generally 20 percent to 50 percent ownership interests, are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. The Company applies the provisions of Accounting Principles Board Opinion 18, “The Equity Method of Accounting for Investments in Common Stock” (APB 18), to account for impairments of investments accounted for under the equity method of accounting. APB 18 requires that a loss in value of an investment, other than a temporary decline, should be recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments. See Note 9 – Unconsolidated Investments.

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Regulatory Assets and Liabilities. The Company is subject to regulation by certain state and federal authorities. In its Distribution segment, the Company has accounting policies that conform to FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement No. 71), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company. These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. See Note 8 – Regulatory Assets.

Fair Value Measurement. Issued by the FASB in September 2006, FASB Statement No. 157 “Fair Value Measurement” (Statement No. 157), defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB released a FASB Staff Position, FSP FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which delays the effective date of this Statement for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008. The Company’s major categories of non-financial assets and non-financial liabilities that are recognized or disclosed at fair value for which, in accordance with FSP FAS 157-2, the Company has not applied the provisions of Statement No. 157 as of January 1, 2008 are (i) fair value calculations associated with annual or periodic impairment tests, and (ii) asset retirement obligations measured at fair value upon initial recognition or upon certain remeasurement events under FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” The partial adoption on January 1, 2008 of Statement No. 157 for financial assets and liabilities did not have a material impact on the Company’s consolidated financial statements. See Note 25 – Fair Value Measurement for additional related information. In October 2008, the FASB issued FASB Staff Position FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active” (FSP FAS 157-3). FSP FAS 157-3 provides clarifying guidance with respect to the application of Statement No. 157 in determining the fair value of a financial asset when the market for that asset is not active. FSP FAS 157-3 was effective upon its issuance. The application of FSP FAS 157-3 did not have a material impact on the Company’s consolidated financial statements.

As defined in Statement No. 157, 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. Statement No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value as follows:

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

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Table of Contents

See Note 25 – Fair Value Measurement for additional related information.

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

In the Gathering and Processing segment, the Company records gas imbalances at the lower of cost or market. Imbalances due to a pipeline are recorded at market and imbalances due from a pipeline are recorded at the lower of cost or market. Market prices are based upon Gas Daily indexes.

Fuel Tracker. The fuel tracker applicable to the Company’s Transportation and Storage segment 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 tariffs of Trunkline Gas and Southwest Gas contain explicit language which, 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 customers which 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.

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Interest Cost Capitalized. The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use in accordance with FASB Statement No. 34, “Capitalization of Interest Cost”. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets. Capitalized interest for the years ended December 31, 2008, 2007 and 2006 was $19 million, $14.7 million and $5.4 million, respectively.

Derivative Instruments and Hedging Activities. The Company follows FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (Statement No. 133), to account for derivative 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 loss until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use. See Note 11 – Derivative Instruments and Hedging Activities and Note 25 – Fair Value Measurement for additional related information.

Asset Retirement Obligations. The Company accounts for its asset retirement obligations in accordance with FASB Statement No. 143, “Accounting for Asset Retirement Obligations (ARO)” (Statement No. 143) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47). These accounting principles require legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. In certain rate jurisdictions, the Company is permitted to include annual charges for cost of removal in its regulated cost of service rates charged to customers.

For more information, see Note 20 – Asset Retirement Obligations.

Income Taxes. Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, “Accounting for Income Taxes”. 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.

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Pensions and Other Postretirement Benefit Plans. The Company accounts for the measurement of its defined benefit postretirement plans under Statement No. 87, “Employers’ Accounting for Pensions” (Statement No. 87), as amended, and Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (Statement No. 106), as amended. Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements Nos. 87, 88, 106 and 132(R)” (Statement No. 158). Statement No. 158 does not amend the expense recognition provisions of Statements No. 87, 88 and 106, but requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity. Effective December 31, 2008, the Company adopted the measurement date provisions of Statement No. 158, which requires plan assets and benefit obligations to be measured as of its fiscal year-end balance sheet date.

Prior to the adoption of the recognition and disclosure provisions of Statement No. 158, Statement No. 87 required that a liability (minimum pension liability) be recorded when the accumulated benefit obligation liability exceeded the fair value of plan assets. Any adjustment was recorded as a non-cash charge to Accumulated other comprehensive loss. Statement No. 106 had no minimum liability provisions. Under both Statements Nos. 87 and 106, changes in the funded status were not immediately recognized, rather they were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its defined benefit postretirement plans through Accumulated other comprehensive loss.

See Note 14 – Benefits for additional information.

Commitments and Contingencies. The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters. Accounting for contingencies requires significant judgments by management regarding the estimated probabilities and ranges of exposure to potential liability. For further discussion of the Company’s commitments and contingencies, see Note 18 – Commitments and Contingencies.

New Accounting Principles

Accounting Principles Recently Adopted.

Statement No. 157: See Note 2 – Summary of Significant Account Policies and Other Matters – Fair Value Measurement for information related to this Statement, which was partially adopted during 2008.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”: Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financial statements.

Staff Accounting Bulletin No. 110 (SAB 110): Issued by the SEC in December 2007, SAB 110 expresses the views of the SEC staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with Statement No. 123R, “Accounting for Stock-Based Compensation”. The SEC staff indicated in SAB No. 107 that it would accept a company’s election to use the simplified method, regardless of whether the company has sufficient information to make more refined estimates of expected term, for options granted prior to December 31, 2007. In SAB 110, the SEC staff states that it will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. Pursuant to the guidance provided in SAB 110, the Company has elected to continue utilizing the simplified method in developing the estimate of the expected term for its share options.

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FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1): Issued by the FASB in April 2007, FSP FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions by allowing net derivative positions to be offset in the financial statements against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral or the obligation to return cash collateral under those arrangements. In accordance with FASB Interpretation No. 39, the Company has historically offset the fair value amounts for derivative instruments executed with the same counterparty where a right of setoff existed, which included derivative instruments subject to master netting arrangements at December 31, 2007. In accordance with FSP FIN 39-1, the Company elects to offset the fair value amounts for derivative instruments, including cash collateral, executed with the same counterparty under a master netting arrangement. The impact of FSP FIN 39-1 was not material to the Company’s consolidated financial statements.

Accounting Principles Not Yet Adopted.

FASB Statement No. 141 (revised), “Business Combinations”. Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration of a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition-related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”. Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements, including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited. The Company has determined this Statement will not materially impact its consolidated financial statements.

FASB Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”. Issued by the FASB in March 2008, this Statement requires disclosure of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Statement is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1)”. Issued by the FASB in December 2008, FSP FAS 132(R)-1 provides guidance on an employer’s disclosure about assets of a defined benefit pension or other postretirement plan. The disclosure provisions of FSP FAS 132(R)-1 are effective for fiscal years ending after December 15, 2009. The Company is currently evaluating the impact of this statement of position on its consolidated financial statements.

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3. Acquisitions and Sales

Acquisition of Sid Richardson Energy Services. On March 1, 2006, Southern Union acquired 100 percent of the partnership interests in the Sid Richardson Energy Services business for approximately $1.6 billion in cash. The acquisition was undertaken by the Company to increase its investment in higher growth businesses. The acquisition was funded under a short-term bridge loan facility in the amount of $1.6 billion (Sid Richardson Bridge Loan). See Note 13 – Debt Obligations – Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt for additional information related to the bridge loan facility.

The principal assets of the acquired Sid Richardson Energy Services business, now known as SUGS, are located in the Permian Basin of Texas and New Mexico and include approximately 4,900 miles of natural gas and NGL pipelines, four cryogenic plants and five natural gas treating plants. SUGS’ operations are located in West Texas and Southeast New Mexico. SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering or marketing the treated natural gas and/or processed NGL to a variety of markets. SUGS’ primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States. SUGS receives hydrocarbons for purchase or transportation to market from over 250 producers and suppliers. SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline, El Paso Natural Gas Company, Energy Transfer Fuel, LP, DCP Guadalupe Pipeline, LP, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, LP, ONEOK Wes Tex Transmission, LP, Public Service Company of New Mexico and Transwestern, a former affiliate of the Company (see Note 9 – Unconsolidated Investments). Its major NGL pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

The acquisition was accounted for using the purchase method of accounting, with the purchase price paid by the Company allocated to SUGS’ net assets as of the acquisition date based on their fair values. SUGS’ assets acquired and liabilities assumed have been recorded in the Consolidated Balance Sheet beginning March 1, 2006 at their estimated fair values. SUGS’ results of operations have been included in the Consolidated Statement of Operations since March 1, 2006. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition are not comparable to the same periods in prior years.

Sale of PG Energy. On August 24, 2006, the Company completed the sale of the assets of its PG Energy natural gas distribution division to UGI Corporation for approximately $580 million in cash, excluding certain working capital adjustment reductions of approximately $24.4 million, which were paid in the first quarter of 2007. Proceeds from the sale were used to retire a portion of the acquisition debt incurred in connection with Southern Union’s $1.6 billion purchase of the Sid Richardson Energy Services business.

Sale of the Rhode Island Operations of New England Gas Company. On August 24, 2006, the Company completed the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA for $575 million in cash, less the assumption of approximately $77 million of debt and excluding certain working capital adjustment reductions of approximately $24.9 million, which were paid in the first quarter of 2007. Proceeds from the sale were used to retire a portion of the acquisition debt incurred in connection with Southern Union’s $1.6 billion purchase of the Sid Richardson Energy Services business.

See Note 7 – Goodwill and Note 19 – Discontinued Operations for additional information, including loss on sales amounts, related to the sales of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas distribution division.

CCE Holdings Transactions.

On December 1, 2006, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Citrus from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern. On September 14, 2006, Energy Transfer Partners, LP (Energy Transfer) entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings held by GE Financial Services and other investors. At the same time, Energy Transfer and CCE Holdings entered into a definitive redemption agreement, pursuant to which Energy Transfer’s 50 percent ownership interest in CCE Holdings would be redeemed in exchange for 100 percent of the equity interests in Transwestern (Redemption Agreement). Upon

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the closing of the transactions under the Redemption Agreement on December 1, 2006, the Company became the sole owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus which, in turn, owns 100 percent of Florida Gas. This resulted in the elimination of the Company’s prior equity investment in CCE Holdings of $680.9 million from its Consolidated Balance Sheet as of December 1, 2006, and the separate inclusion of Citrus as an equity investment with a balance of $1.23 billion in the Company’s Consolidated Balance Sheet. Prior to December 1, 2006, Citrus was a 50 percent equity investment of CCE Holdings and was included within the Company’s 50 percent equity interest in CCE Holdings. The resulting increase in the Company’s equity investment from CCE Holdings to Citrus is primarily attributable to the Company becoming obligated to retire $455 million of debt held by CCE Holdings and recognition of a pre-tax $74.8 million gain associated with the transaction. The debt was simultaneously paid off using the proceeds of the $465 million LNG Holdings 2006 Term Loan more fully described in Note 13 – Debt Obligations.

Florida Gas is an open-access interstate pipeline system extending approximately 4,900 miles with a capacity of 2.1 Bcf/d from south Texas through the Gulf Coast region of the United States to south Florida. Florida Gas’ pipeline system primarily receives natural gas from natural gas producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico. Florida Gas is the principal transporter of natural gas to the Florida energy market, delivering over 68 percent of the natural gas consumed in the state. In addition, Florida Gas’ pipeline system operates and maintains 60 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to diverse natural gas producing regions.

At December 1, 2006, Transwestern was an open-access natural gas interstate pipeline extending approximately 2,500 miles with a capacity of 2.1 Bcf/d from the gas producing regions of west Texas, Oklahoma, eastern and northwest New Mexico and southern Colorado primarily to pipeline interconnects off the east end of its system and to the California market. Transwestern has access to three significant gas basins: the Permian Basin in west Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle.

4. Other Income and Expense Items

Operating, maintenance and general expense for the year ended December 31, 2007 includes a $6.9 million impairment of the Company’s former corporate office building due to a change in the Company’s expected proceeds from the sale of the building.

Other, net income of $39.9 million for the year ended December 31, 2006 primarily includes $37.2 million of pre-acquisition mark-to-market gains on put options associated with the acquisition of the Sid Richardson Energy Services business and $3.2 million in gains on sales of certain assets. See Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment for more information related to the gain on put options mentioned above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Earnings Per Share

The following table summarizes the Company’s basic and diluted earnings EPS calculations for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008			2007			2006
	(In thousands, except per share amounts)

Net earnings from continuing operations	$	295,151		$	228,711		$	217,083
Loss from discontinued operations		-			-			(152,952	)
Preferred stock dividends		(12,212	)		(17,365	)		(17,365	)
Loss on extinguishment of preferred stock		(3,527	)		-			-
Net earnings available for common stockholders	$	279,412		$	211,346		$	46,766

Weighted average shares outstanding - Basic		123,446			119,930			114,787
Weighted average shares outstanding - Diluted		123,644			120,674			117,344

Basic earnings per share:
Net earnings available for common stockholders
from continuing operations	$	2.26		$	1.76		$	1.74
Loss from discontinued operations		-			-			(1.33	)
Net earnings available for common stockholders	$	2.26		$	1.76		$	0.41

Diluted earnings per share:
Net earnings available for common
stockholders from continuing operations	$	2.26		$	1.75		$	1.70
Loss from discontinued operations		-			-			(1.30	)
Net earnings available for common stockholders	$	2.26		$	1.75		$	0.40

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A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table.

	Years Ended December 31,
	2008		2007		2006
	(In thousands)

Weighted average shares outstanding - Basic		123,446		119,930		114,787
Add assumed vesting of restricted stock		10		35		35
Add assumed conversion of equity units		-		248		2,021
Add assumed exercise of stock options
and SARs		188		461		501
Weighted average shares outstanding - Diluted		123,644		120,674		117,344

For the years ended December 31, 2008, 2007 and 2006, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.

Except for the Company’s purchase of common stock used to pay employee federal and state income tax obligations associated with vested restricted stock awards, the Company did not purchase any shares of its common stock outstanding during the years ended December 31, 2008, 2007 and 2006, respectively.

The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company’s common shares.

	December 31,
	2008		2007		2006
	(In thousands, except per share amounts)

Options excluded		1,127		-		-
Exercise price ranges of options excluded		$23.62 - $28.48		N/A		N/A
SARs excluded		416		-		-
Exercise price ranges of SARs excluded		$28.07 - $28.48		N/A		N/A
Year-to-date weighted-average market price		$22.85		$30.58		$25.99

At December 31, 2008, 663,080 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans. From time to time, the Company’s benefit plans may purchase shares of Southern Union common stock subject to certain restrictions.

See Note 10 – Stockholders’ Equity – 2008 Equity Issuances and 2006 Equity Issuances for information related to the 5% and 5.75% Equity Units issued on February 11, 2005 and June 11, 2003, respectively, which had a dilutive effect on EPS for applicable periods outstanding during the years 2006 through 2008.

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6. Property, Plant and Equipment

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


			December 31,
Property, Plant and Equipment	Lives in Years (1)		2008 (2)		2007 (2)
			(In thousands)
Regulated Operations:
Distribution plant		25-60	$	945,132	$	912,519
Gathering and processing plant		26		110,246		111,542
Transmission plant		36-46		2,088,018		1,770,742
General - LNG		20-40		624,883		624,250
Underground storage plant		36-46		307,401		290,753
General plant and other		1-50		257,456		201,387
Construction work in progress				409,973		359,867
				4,743,109		4,271,060
Less accumulated depreciation and amortization				803,091		673,952
				3,940,018		3,597,108

Non-regulated Operations:
Distribution plant		25-75		17,846		17,830
Gathering and processing plant		1-50		1,617,734		1,567,411
General plant and other		3-15		11,581		13,558
Construction work in progress				41,386		18,051
				1,688,547		1,616,850
Less accumulated depreciation and amortization				171,560		111,671
				1,516,987		1,505,179

Net property, plant and equipment			$	5,457,005	$	5,102,287

________________

(1)	The composite weighted-average depreciation rates for the years ended December 31, 2008, 2007 and 2006 were 3.5 percent, 3.4 percent and 3.0 percent, respectively.

(2)	Includes capitalized computerized software cost totaling:

Unamortized computer software cost	$	116,010	$	109,167
Less accumulated amortization		57,020		45,824
Net capitalized computer software costs	$	58,990	$	63,343

Amortization expense of capitalized computer software costs for the years ended December 31, 2008, 2007 and 2006 was $12.1 million, $10.6 million and $9.8 million, respectively. Computer software costs are amortized between four and fifteen years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Goodwill

The following table displays changes in the carrying amount of goodwill, which relates solely to the Distribution segment:

Goodwill Analysis	Amounts
	(In thousands)

Balance as of December 31, 2005	$	465,547
Impairment losses		-
Write-off associated with sales		(376,320	)
Balance as of December 31, 2006		89,227
Impairment losses		-
Balance as of December 31, 2007		89,227
Impairment losses		-
Balance as of December 31, 2008	$	89,227

Goodwill of $376.3 million was written off on August 24, 2006 upon the completion of the sale of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas distribution division. See Note 19 – Discontinued Operations for related information. All goodwill reflected in the Company’s Consolidated Balance Sheet is applicable to the Missouri Gas Energy natural gas distribution division and the Massachusetts operations of the New England Gas Company natural gas distribution division reporting units. The Company evaluated goodwill of these reporting units for potential impairment for the years ended December 31, 2008, 2007 and 2006, and no impairment was indicated.

8. Regulatory Assets

The Company records regulatory assets and liabilities with respect to its Distribution segment operations in accordance with Statement No. 71. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply Statement No. 71 in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of Statement No. 71 primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

The following table provides a summary of regulatory assets at the dates indicated:

	December 31,
Regulatory Assets	2008		2007
	(In thousands)

Pension and Postretirement Benefits	$	27,496	$	32,889
Environmental		34,971		21,782
Missouri Safety Program		3,309		5,546
Other		3,778		3,976
	$	69,554	$	64,193

The Company’s regulatory assets at December 31, 2008 relating to Distribution segment operations that are being recovered through current rates totaled $43.5 million. The remaining recovery period associated with these assets ranged from 15 months to 93 months. The Company expects that the $26.1 million of regulatory assets at December 31, 2008 not currently in rates will be included in its rates as rate cases occur in the future. The Company’s regulatory assets at December 31, 2007 relating to Distribution segment operations that are being recovered through current rates totaled $44.8 million. The remaining recovery period associated with these assets ranged from 7 months to 93 months.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Unconsolidated Investments

A summary of the Company’s unconsolidated equity investments at the dates indicated is as follows:

	December 31,
Unconsolidated Investments	2008		2007
	(In thousands)
Equity investments:
Citrus	$	1,238,198	$	1,219,009
Other		21,072		21,411
	$	1,259,270	$	1,240,420

Equity Investments. Unconsolidated investments at December 31, 2008 and 2007 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch, Lee 8 Partnership and PEI Power II, respectively. The Company accounts for these investments using the equity method. The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Summarized financial information for the Company’s equity investments is as follows:

	At December 31,
	2008				2007
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Balance Sheet Data:
Current assets	$	78,624	$	7,813	$	59,644	$	7,324
Non-current assets		3,459,281		43,525		3,049,214		38,008
Current liabilities		162,342		7,716		208,508		1,040
Non-current liabilities		2,154,550		272		1,697,218		1,792

		Years Ended December 31,
		2008				2007				2006
				Other Equity				Other Equity		CCE						Other Equity
		Citrus		Investments		Citrus		Investments		Holdings (1)				Citrus (4)		Investments
	(In thousands)
Statement of Operations Data:
Revenues		$	504,819	$	14,291	$	495,513	$	13,061	$	-			$	37,598	$	5,386
Operating income (loss)			275,245		3,019		283,203		4,424		(5,729)				21,201		1,157
Equity earnings			-		-		-		-		70,086	(2	)		-		-
Interest expense			82,830		67		73,871		127		25,445				7,109		146
Earnings from
discontinued operations			-		-		-		-		156,612	(3	)		-		-
Net earnings			126,942		1,850		157,092		5,256		196,857				9,579		1,005

______________________

(1) The statement of operations information of CCE Holdings is through the period ended December 1, 2006. See

Note 3 - Acquisitions and Sales - CCE Holdings Transactions for a description of the transactions

that led to the Company's consolidation of CCE Holdings as of December 1, 2006.

(2) Represents equity earnings of CCE Holdings in Citrus through the period ending December 1, 2006.

(3) Earnings from discontinued operations for CCE Holdings relates primarily to the eleven months of operations of

Transwestern and to the closing of the transactions on December 1, 2006 included in the Redemption Agreement,

resulting in Energy Transfer’s interest in CCE Holdings being exchanged for CCE Holdings’ interest in Transwestern.

The year ended December 31, 2006 includes a pre-tax gain of $74.8 million related to the closing of the transactions

included in the Redemption Agreement. See Note 3 - Acquisitions and Sales - CCE Holdings Transactions for

a description of the transaction.

(4) Includes Citrus results for the post-Redemption Agreement period of December 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Citrus.

Dividends. During the years ended December 31, 2008 and 2007, Citrus paid to the Company dividends of $77.2 million and $103.6 million, respectively. At December 31, 2007, Accounts receivable – affiliates includes $21.3 million related to declared Citrus dividends, which were paid in January 2008.

For the eleven months ended November 30, 2006, prior to becoming a wholly-owned subsidiary of the Company on December 1, 2006, CCE Holdings paid the Company distributions totaling $48.8 million.

Citrus and CCE Holdings. On December 1, 2006, as more fully described in Note 3 – Acquisitions and Sales – CCE Holdings Transactions, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Florida Gas from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern. Upon closing of the transactions under the Redemption Agreement on December 1, 2006, the Company became the sole owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus. This resulted in the elimination of the Company’s equity investment in CCE Holdings as of December 1, 2006 and the separate presentation of Citrus as an equity investment. Prior to December 1, 2006, Citrus was a 50 percent equity investment of CCE Holdings and included within the Company’s 50 percent equity interest in CCE Holdings.

The Company’s equity investment balances, assessed under APB 18, include amounts in excess of the Company’s share of the underlying equity of the investee of $629 million and $617.4 million as of December 31, 2008 and 2007, respectively. These amounts relate to the Company’s 50 percent equity ownership interest in Citrus. The equity goodwill includes an allocation of $208.4 million of excess purchase cost associated with the increased interest in Citrus effectively acquired on December 1, 2006. The combined fair value of the excess net investment of the Company’s 50 percent share of the underlying Citrus equity as of December 31, 2008 was as follows:

	Excess Purchase Costs			Amortization Period
	(In thousands)

Property, plant and equipment	$	2,885		40 years
Capitalized software		1,478		5 years
Long-term debt (1)		(80,204	)	4-20 years
Deferred taxes (1)		(6,883	)	40 years
Other net liabilities		(541	)	N/A
Goodwill (2)		664,609		N/A
Sub-total		581,344
Accumulated, net accretion to equity earnings		47,672
Net investment in excess of underlying equity	$	629,016

____________________

(1)	Accretion of this amount increases equity earnings and accumulated net accretion.

(2)	The Company’s tax basis in the investment in Citrus includes equity goodwill. See “CCE Holdings’ Goodwill” discussion for additional related information.

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Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus.

On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Construction Loan Agreement) with a wholly-owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus will primarily invest the proceeds of this loan into Florida Gas in order to finance a portion of the Phase VIII Expansion. On August 6, 2008, the parties amended the Construction Loan Agreement to accelerate the funding date to October 1, 2008. On October 1, 2008, Citrus borrowed the full $500 million available under the Construction Loan Agreement. At December 31, 2008, the effective interest rate applicable to the construction loan was 8.77 percent, which was comprised of LIBOR of 3.42 percent plus a margin of 5.35 percent.

On or before the Phase VIII Expansion in-service date, the Construction Loan Agreement will convert to an amortizing 20-year term loan with a $300 million balloon payment at maturity. The loan requires semi-annual payments of principal beginning five years and six months after the conversion to a term loan. The Construction Loan Agreement provides for interest on the outstanding principal amount at the rate of three-month LIBOR plus 535 basis points prior to conversion to a term loan and at the twenty-year treasury rate plus 535 basis points after conversion to a term loan. The loan is not guaranteed by Florida Gas and does not include a prepayment option. The Construction Loan Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas. The Construction Loan Agreement requires any dividends paid by Citrus after October 1, 2008 and prior to the Phase VIII Expansion in-service date to be re-contributed by the partners within twelve months of any such dividends.

Environmental Matters. Florida Gas is responsible for environmental remediation of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its natural gas transmission systems. Florida Gas is implementing a program to remediate such contamination. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. 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.

SPCC Rules. In October 2007, the U.S. EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. In December 2008, the EPA again extended the SPCC rule compliance dates until November 20, 2009, permitting owners and operators of facilities to prepare or amend and implement SPCC plans in accordance with previously enacted modifications to the regulations. Florida Gas has reviewed the impact of the modified regulations on its operations and estimates the cost associated with the new regulatory requirements will not exceed $100,000.

CCE Holdings’ Goodwill. CCE Holdings applied the purchase method of accounting for its acquisition of CrossCountry Energy on November 17, 2004. Goodwill associated with CCE Holdings’ equity investment in Citrus accounted for under APB 18 was approximately $664.6 million at December 31, 2008 and 2007. The amounts recorded at December 31, 2007 included final purchase price allocations related to the December 1, 2006 redemption of Transwestern and the resulting increase in Southern Union’s equity interest in Citrus. See Note 3 – Acquisitions and Sales – CCE Holdings Transactions.

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Regulatory Assets and Liabilities. Florida Gas is subject to regulation by certain state and federal authorities. Florida Gas has accounting policies that conform to Statement No. 71 and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. Management’s assessment for Florida Gas of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from its consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings. Florida Gas’ regulatory asset and liability balances at December 31, 2008 were $22.2 million and $9.2 million, respectively.

Federal Pipeline Integrity Rules. 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 high consequence areas (HCAs). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to have identified HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004. Operators must have ranked the risk of their pipeline segments containing HCAs and completed assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments are generally conducted on the higher risk segments first, with the balance being completed by December 2012. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2008 and 2007, Florida Gas had completed 83 percent and 80 percent of the required risk assessments, respectively. All systems operated by Florida Gas will be compliant with the rule; however, while identification and location of all 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 $20 million to $28 million per year through 2012.

Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike widening projects that have or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new rights-of-way needed for relocation of the pipelines and Florida Gas to pay for rearrangement or relocation costs. Under certain other conditions, Florida Gas may be entitled to reimbursement for the costs associated with relocation, including construction and rights-of-way costs.

On October 20, 2005, Florida Gas filed an application with FERC for a State Road 91 Relocation Project. The first phase of the turnpike project included replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE rights-of-way in Broward County, Florida to accommodate the widening of State Road 91 by the FDOT/FTE. The FERC issued an order approving the project on May 3, 2006, and Florida Gas notified the FERC that construction commenced on April 25, 2007. Florida Gas received authorization from the FERC to place the facilities in service on March 20, 2008 and the State Road 91 Relocation facilities were placed in service on the same day. In an order issued October 10, 2008, FERC denied a certificate amendment filed by Florida Gas seeking to hold in abeyance the abandonment authorization of the 18- and 24- inch pipelines and ordered Florida Gas to remove the 18- and 24-inch pipelines from service in accordance with a prior order. Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’ 18- and 24-inch pipelines within FDOT/FTE rights-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or rights-of-way costs, cannot be determined at this time.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to workspace and uniform minimum area with respect to its pipelines. On February 14, 2008 the case was transferred to the Broward County Complex Business Civil Division 07. On April 14, 2008, the FDOT/FTE amended its counterclaim, alleging Florida Gas committed fraud in the inducement by not removing its previously existing pipelines, seeking to place a constructive trust over any revenues associated with the previously existing and newly constructed pipelines, seeking a declaratory order from the Court that Florida Gas has abandoned its previously existing pipelines and seeking a temporary and permanent injunction forcing Florida Gas to remove such pipelines. On July 21, 2008, the Court allowed the FDOT/FTE to further amend its counterclaim to include counts of fraud and trespass but reserved ruling on permitting a demand for punitive damages on those counts. On October 6, 2008, the FDOT/FTE filed a supplemental motion for temporary injunction and a motion for partial summary judgment against Florida Gas on the extent of the rights Florida Gas claims under the easements at issue, the breach of the easements by the FDOT/FTE for failing to provide adequate rights-of-way, the failure of the FDOT/FTE to reimburse Florida Gas for the costs of relocation, and inverse condemnation by the FDOT/FTE as a result of the breach of the easements. Trial is scheduled for August 2009. A 2007 action brought by the FDOT/FTE against Florida Gas in Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with FDOT/FTE projects, has been stayed pending resolution of the Broward County, Florida action.

Should Florida Gas be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the FDOT/FTE to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of reimbursement will fully compensate Florida Gas for its costs.

Litigation.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Florida Gas, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. For additional information related to these filed actions, see Note 18 – Commitments and Contingencies – Litigation.

Other Equity Investments.

The Company’s investments in Grey Ranch, the Lee 8 partnership and PEI Power are accounted for under the equity method. Grey Ranch operates a 200 MMcf/d carbon dioxide treatment facility. The Lee 8 partnership operates a 3.0 Bcf natural gas storage facility in Michigan. PEI Power II owns a 45-megawatt, natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Stockholders’ Equity

Dividends. The table below presents the amount of cash dividends declared and paid in the respective periods:

Shareholder	Date	Amount		Amount
Record Date	Paid	Per Share		Paid
				(In thousands)

December 26, 2008	January 9, 2009	$	0.15	$	18,600
September 26, 2008	October 10, 2008		0.15		18,597
June 27, 2008	July 11, 2008		0.15		18,595
March 28, 2008	April 11, 2008		0.15		18,592

December 28, 2007	January 11, 2008	$	0.15	$	17,999
September 28, 2007	October 12, 2007		0.10		11,997
June 29, 2007	July 13, 2007		0.10		11,995
March 30, 2007	April 13, 2007		0.10		11,977

December 29, 2006	January 12, 2007	$	0.10	$	11,961
September 29, 2006	October 13, 2006		0.10		11,956
June 30, 2006	July 14, 2006		0.10		11,197
March 31, 2006	April 14, 2006		0.10		11,175

For the year ended December 31, 2006, the Company reduced Retained earnings (deficit) and Premium on capital stock in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income by $19.9 million (to the extent that retained earnings were available) and $26.4 million, respectively.

Under the terms of the indenture governing its senior unsecured notes (Senior Notes), Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied. Currently, the Company is in compliance with these requirements and, therefore, the Senior Note indenture does not prohibit the Company from paying cash dividends.

Stock Award Plans. The Second Amended 2003 Plan 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 Second Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries. Under the Second Amended 2003 Plan: (i) no participant may receive in 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.

The Company maintains its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees. Options granted under the 1992 Plan are exercisable for ten years from the date of grant or such lesser period as may be designated for particular options, and become exercisable after a specified period of time from the date of grant in cumulative annual installments. As of December 31, 2006, there were no shares available for future option grants under the 1992 Plan.

For more information on share-based awards, see Note 24 – Stock-Based Compensation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2008 Equity Issuance. On February 19, 2008, the Company received $100 million from the issuance of 3,693,240 shares of common stock in conjunction with the remarketing of its 4.375% Senior Notes and the consummation of the forward stock purchase contracts that were issued with the 4.375% Senior Notes as part of the February 2005 5% Equity Units issuance. See Note 13 – Debt Obligations – Long-Term Debt – Remarketing Obligation for additional related information.

2006 Equity Issuance. On August 16, 2006, the Company received $125 million from the issuance of 7,413,074 shares of common stock in conjunction with the remarketing of its 2.75% Senior Notes and the consummation of the forward stock purchase contracts that were issued with the 2.75% Senior Notes as part of the June 2003 5.75% Equity Units issuance. See Note 13 – Debt Obligations – Long-Term Debt – Remarketing Obligation for additional related information.

11. Derivative Instruments and Hedging Activities

Interest Rate Swaps. The Company has used interest rate swaps to reduce interest rate risks and to manage interest expense. By entering into these agreements, the Company converts floating-rate debt into fixed-rate debt, or alternatively converts fixed-rate debt to floating-rate debt. Interest differentials paid or received under the swap agreements are reflected as an adjustment to interest expense. These interest rate swaps are financial derivative instruments that qualify for hedge treatment. The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates. For the years ended December 31, 2008, 2007 and 2006, there was no swap ineffectiveness. As of December 31, 2008, approximately $10.1 million of net after-tax losses in Accumulated other comprehensive loss related to the swap agreements will be amortized into interest expense during the next twelve months. Current market pricing models were used to estimate fair values of interest rate swap agreements.

Treasury Rate Locks. The Company has entered into treasury rate locks from time to time to hedge the changes in cash flows of anticipated interest payments from changes in treasury rates prior to the issuance of new debt instruments. 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. As of December 31, 2008, approximately $1.3 million 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.

Distribution Segment

Economic Hedging Activities. During 2008, 2007 and 2006, the Company entered into natural gas commodity swaps and collars to mitigate price volatility of natural gas passed through to utility customers in the Distribution Segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the natural gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the Consolidated Balance Sheet. As of December 31, 2008 and 2007, the fair values of the contracts, which expire at various times through October 2010, are included in the Consolidated Balance Sheet as liabilities and assets, respectively, with matching adjustments to deferred cost of natural gas of $92.7 million and $22.3 million, respectively.

Gathering and Processing Segment

The Company markets natural gas and NGL in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments. These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts, but also the risks associated with unmatched positions and market fluctuations. The Company is required to record derivative financial instruments at fair value, which is affected by commodity exchange prices, over-the-counter quotes, volatility, time value, credit and counterparty credit risk and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Economic Hedging Derivatives. To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e., receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps, and exchange-traded futures and options. These economic hedge derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are effective in offsetting changes in physical market commodity prices and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations. For the years ended December 31, 2008 and 2007, and ten-month period ended December 31, 2006, gains of $50.2 million, $1.2 million and $1.2 million, respectively, were recorded in Operating revenues for the economic hedging activities.

The Company realizes NGL and/or natural gas volumes from the contractual arrangements associated with gas processing services it provides. Expected NGL and/or natural gas volumes compared to the actual volumes sold and the effectiveness of the associated economic hedges utilized by the Company can be unfavorably impacted by:

·	Processing plant outages;

·	Higher than anticipated fuel, flare and unaccounted-for natural gas levels;

·	Impact of commodity prices in general;

·	Decline in drilling and/or connections of new supply;

·	Reduction in available NGL take-away capacity;

·	Reduction in NGL available from wellhead supply;

·	Lower than expected recovery of NGL from the inlet gas stream; and

·	Lower than expected receipt of natural gas volumes to be processed.

Accounting Hedges Designated as Cash Flow Hedges. In accordance with Statement No. 133, the Company has designated its natural gas swaps and propane and ethane put options as accounting (cash flow) hedges. The Company has used such accounting hedges to manage its commodity price risk and reduce fluctuations in operating cash flows.

The table below summarizes the financial statement impact of natural gas swaps and put options related to natural gas and NGL that the Company had designated as accounting hedges during the respective periods.

	Years Ended December 31,
	2008		2007			2006
	(In thousands)

Change in fair value of commodity hedges - (increase)
decrease in Accumulated other comprehensive loss,
excluding tax expense effect of $13,549, $(775) and $7,556, respectively	$	37,594	$	(2,054	)	$	19,826
Reclassification of unrealized gain on
commodity hedges - increase of Operating revenues,
excluding tax expense effect of $2,466, $2,425 and $4,266, respectively		6,841		6,422			11,350
Loss realized upon cash settlement - decrease of Operating
revenues		-		718			45
Loss on ineffectiveness of commodity hedges		-		-			1,634
Cash realized on settlement of commodity hedges		6,841		35,374			74,214

All of the deferred gains included in Accumulated other comprehensive loss as of December 31, 2008 will be reclassified into earnings during 2009.

See Note 22 – Accumulated Other Comprehensive Loss for additional related information. See Note 25 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments and a summary of derivative instruments outstanding as of December 31, 2008.

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12. Preferred Securities

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) (Preferred Stock), at the public offering price of $25 per share, or $230 million in the aggregate. The total net proceeds were used to repay debt under the Company’s revolving credit facilities.

On May 22, 2008, the Company announced that the Finance Committee of its Board of Directors had authorized a program to repurchase a portion of the depositary shares representing ownership of its Preferred Stock at the Company’s discretion in the open market and/or through privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors. During the year ended December 31, 2008, the Company paid $115.2 million to repurchase 4,599,987 depository shares representing 459,999 shares of Preferred Stock, resulting in a $3.5 million non-cash charge loss adjustment charged to Retained earnings related to the write-off of issuance costs which reduced Net earnings available for common stockholders. Effective October 8, 2008, the Company has the right to redeem all of the outstanding Preferred Stock at par upon applicable notice.

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13. Debt Obligations

The following table sets forth the debt obligations of Southern Union and applicable units of Panhandle under their respective notes, debentures and bonds at the dates indicated:

	December 31, 2008				December 31, 2007
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Long-Term Debt Obligations:

Southern Union
7.60% Senior Notes due 2024	$	359,765	$	272,165	$	359,765	$	378,473
8.25% Senior Notes due 2029		300,000		229,470		300,000		336,090
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		16,248		19,500		19,500
4.375% Senior Notes due 2008		-		-		100,000		100,000
6.15% Senior Notes due 2008		-		-		125,000		124,538
6.089% Senior Notes due 2010		100,000		92,701		-		-
7.20% Junior Subordinated Notes due 2066		600,000		215,999		600,000		590,280
Note Payable		3,820		3,820		-		-
		1,383,085		830,403		1,504,265		1,548,881

Panhandle
4.80% Senior Notes due 2008		-		-		300,000		298,140
6.05% Senior Notes due 2013		250,000		211,646		250,000		252,650
6.20% Senior Notes due 2017		300,000		230,956		300,000		297,240
6.50% Senior Notes due 2009		60,623		59,604		60,623		62,132
8.25% Senior Notes due 2010		40,500		39,668		40,500		43,396
7.00% Senior Notes due 2029		66,305		46,158		66,305		65,198
7.00% Senior Notes due 2018		400,000		318,033		-		-
Term Loans due 2012		815,391		753,262		867,220		867,220
Net premiums on long-term debt		2,153		2,153		6,093		6,093
		1,934,972		1,661,480		1,890,741		1,892,069

Total Long-Term Debt Obligations		3,318,057		2,491,883		3,395,006		3,440,950

Credit Facilities		251,459		243,205		123,000		123,000
Short-Term Facility		150,000		148,496		-		-

Total consolidated debt obligations		3,719,516	$	2,883,584		3,518,006	$	3,563,950
Less current portion of long-term debt		60,623				434,680
Less short-term debt		401,459				123,000
Total long-term debt	$	3,257,434			$	2,960,326

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Long-Term Debt.

Southern Union has $3.32 billion of long-term debt, including net premiums of $2.2 million, recorded at December 31, 2008, of which $60.6 million is current. Debt of $2.96 billion is at fixed rates ranging from 5.60 percent to 9.44 percent. Southern Union also has floating rate debt totaling $360.4 million, bearing an interest rate of 1.02 percent as of December 31, 2008.

As of December 31, 2008, the Company has scheduled long-term debt payments, excluding credit facility payments and net premiums on debt, as follows:

											2014 and
	2009		2010		2011		2012		2013		thereafter
	(In thousands)

Southern Union Company	$	-	$	101,178	$	991	$	964	$	687	$	1,279,265
Panhandle		60,623		40,500		-		815,391		250,000		766,305

Total	$	60,623	$	141,678	$	991	$	816,355	$	250,687	$	2,045,570

Each note, debenture or bond is an obligation of Southern Union or a unit of Panhandle, as noted above. Panhandle’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union are direct obligations of Southern Union. None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.

7.00% Senior Notes due 2018. In June 2008, PEPL 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, PEPL incurred underwriting and discount costs totaling approximately $4.1 million, resulting in approximately $395.9 million in proceeds to PEPL. These proceeds were advanced to Southern Union and used to repay borrowings under its credit facilities. Southern Union repaid PEPL a portion of the advance to retire the $300 million 4.80% Senior Notes in August 2008.

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 a LIBOR rate or 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 fixed 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, 2008 and 2007, respectively. See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.

In connection with the December 1, 2006 closing of the Redemption Agreement, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into a $465 million unsecured term loan facility due April 4, 2008 (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 2006 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 $412.2 million at effective interest rates of 1.02 percent

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and 5.37 percent at December 31, 2008 and 2007, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 24, 2009 was $360.4 million and 0.96 percent, respectively.

Junior Subordinated Notes. On October 23, 2006, the Company issued $600 million in junior subordinated notes due November 1, 2066 with an initial fixed interest rate of 7.20 percent (Junior Subordinated Notes). In connection with the issuance of the Junior Subordinated Notes, the Company incurred underwriting and discount costs of approximately $9 million. The debt was priced to the public at 99.844 percent, resulting in $590.1 million in proceeds to the Company, which were used to retire debt associated with the acquisition of the Sid Richardson Energy Services business and to pay down a portion of the Company’s credit facilities.

Pursuant to the terms of the Junior Subordinated Notes, the Company may at its discretion defer interest payments for up to ten consecutive years at a time. The Company may make such election on more than one occasion, provided that payment of all previously deferred interest has been made and the deferral period does not extend beyond the November 1, 2066 maturity date, at which time all deferred interest would become due and payable.

The Company has entered into a covenant agreement for the benefit of holders of a designated series of indebtedness, other than the Junior Subordinated Notes, that it will not redeem or repurchase the Junior Subordinated Notes, in whole or in part, on or before October 31, 2036, unless, subject to certain limitations, during the 180 days prior to the date of that redemption or repurchase, the Company has received an equal or greater amount of net cash proceeds from the sale of common stock or other qualifying securities.

Remarketing Obligation. In February 2005, the Company issued $100 million aggregate principal amount of 4.375% Senior Notes due in February 2008 in conjunction with the issuance of its 5% Equity Units. Each equity unit was comprised of a senior note in the principal amount of $50 and a forward purchase contract under which the equity unit holder agreed to purchase shares of Southern Union common stock in February 2008 at a price based on the preceding 20-day average closing price subject to a minimum conversion price per share of $22.74 and a maximum conversion price per share of $28.42. On February 8, 2008, the Company remarketed the 4.375% Senior Notes, which yielded no cash proceeds for the Company. The interest rate on the Senior Notes was reset to 6.089 percent per annum from and after February 19, 2008. See Note 10 – Stockholders’ Equity – 2008 Equity Issuance for additional related information. The 6.089% Senior Notes will mature on February 16, 2010.

In June 2003, the Company issued $125 million aggregate principal amount of 2.75% Senior Notes due in August, 2006 in conjunction with the issuance of its 5.75% Equity Units. Each equity unit was comprised of a senior note in the principal amount of $50 and a forward purchase contract under which the equity unit holder agreed to purchase shares of Southern Union common stock in August, 2006 at a price based on the preceding 20-day average closing price subject to a minimum conversion price per share of $13.82 and a maximum conversion price of $16.86. On August 16, 2006, the Company remarketed the 2.75% Senior Notes, which were retired on August 16, 2008.

Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt.

Credit Facilities. The Company’s $400 million Fifth Amended and Restated Revolving Credit Agreement (Revolver) is a committed credit facility that matures on May 28, 2010. Borrowings under the Revolver are available for Southern Union’s working capital and letter of credit requirements and for other general corporate purposes. The interest rate for the Revolver is based on LIBOR, plus 62.5 basis points. The Revolver is also subject to a commitment fee based on the rating of the Company’s unsecured senior notes. As of December 31, 2008, the commitment fees were an annualized 0.15 percent.

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periods of 15 to 180 days. At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days. As of February 24, 2009, there was a balance of $170 million outstanding under the Company’s credit facilities at an average effective interest rate of 1.05 percent.

Sid Richardson Bridge Loan. On March 1, 2006, Southern Union acquired the Sid Richardson Energy Services business for approximately $1.6 billion in cash. The acquisition was funded under a bridge loan facility in the amount of $1.6 billion that was entered into on March 1, 2006 between the Company and a group of banks as lenders. On August 24, 2006, the Company applied approximately $1.1 billion in net proceeds from the sales of the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division to repayment of the Sid Richardson Bridge Loan. See Note 19 – Discontinued Operations for related information. On October 23, 2006, the Company retired the remainder of the Sid Richardson Bridge Loan using a portion of the proceeds received from the Company’s issuance of $600 million in Junior Subordinated Notes.

Restrictive Covenants. The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements. Covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:

	(a)	Under the Company’s Revolver, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent;
	(b)	Under the Company’s Revolver, the Company must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;
	(c)	Under the Company’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, the Company’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70 percent at the end of any calendar quarter; and
	(d)	All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $2 million of principal.

In addition to the above restrictions and default provisions, the Company and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in the Company’s cash management program; and limitations on the Company’s ability to prepay debt.

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Retirement of Debt Obligations

In August 2008, the Company repaid and retired its $300 million 4.80% Senior Notes and $125 million 6.15% Senior Notes using the remaining proceeds from the 7.00% Senior Notes issued in June 2008 and draw downs of its credit facilities.

14. Benefits

Pension and Other Postretirement Benefit Plans. The Company has funded non-contributory defined benefit pension plans (pension plans) which cover substantially all Distribution segment employees. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

The Company has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all Distribution and Transportation and Storage segment employees and, effective January 1, 2008, all Corporate employees. The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles, coinsurance and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

The following table summarizes the impact of the adoption of the measurement date provisions of Statement No. 158, effective December 31, 2008 which requires plan assets and benefit obligations to be measured as of the Company’s fiscal year-end balance sheet date. Accordingly, the Company recorded the below transition adjustments to reflect the net periodic benefit cost applicable to the fourth quarter of 2007 for those benefit plans previously measured as of September 30.

				Other
Balance Sheet Impact of FASB Statement No. 158	Pension			Postretirement
Measurement Date Provisions	Plans			Plans			Total
	(In thousands)

Decrease Retained earnings, net of tax of $799 and $88, respectively	$	1,323		$	274		$	1,597
(Decrease) increase Accumulated other comprehensive loss, net of tax
of $(698) and $22, respectively		(1,157	)		66			(1,091	)
Increase pension liabilities - noncurrent (included in Deferred credits)		(267	)		(450	)		(717	)
Decrease Accumulated deferred income taxes		101			110			211

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Obligations and Funded Status.

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

							Other
	Pension Benefits At						Postretirement Benefits At
	December 31,						December 31,
	2008			2007			2008			2007
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of period	$	162,824		$	162,955		$	76,273		$	74,082
Service cost		3,245			2,715			2,664			1,788
Interest cost		12,466			9,388			5,938			4,053
Benefits paid, net		(13,325	)		(9,900	)		(2,899	)		(2,893	)
Medicare Part D subsidy receipts		-			-			-			289
Actuarial (gain) loss and other		6,853			(3,512	)		(225	)		(3,780	)
Plan amendments		-			1,178			9,368			2,734
Benefit obligation at end of period (1)	$	172,063		$	162,824		$	91,119		$	76,273

Change in plan assets:
Fair value of plan assets at beginning of period	$	128,342		$	108,633		$	54,010		$	46,233
Return on plan assets and other		(30,983	)		12,796			(10,121	)		1,494
Employer contributions		18,361			16,813			10,040			9,176
Benefits paid, net		(13,325	)		(9,900	)		(2,899	)		(2,893	)
Fair value of plan assets at end of period (1), (2)	$	102,395		$	128,342		$	51,030		$	54,010

Amount underfunded at end of period (3)	$	(69,668	)	$	(30,457	)	$	(40,089	)	$	(21,823	)

Amounts recognized in the Consolidated
Balance Sheet consist of:
Noncurrent assets	$	-		$	-		$	-		$	1,418
Current liabilities		(13	)		(13	)		(140	)		(57	)
Noncurrent liabilities		(69,655	)		(30,444	)		(39,949	)		(23,184	)
	$	(69,668	)	$	(30,457	)	$	(40,089	)	$	(21,823	)

Amounts recognized in Accumulated other
comprehensive loss (pre-tax basis) consist of:
Net actuarial loss (gain)	$	68,005		$	24,376		$	1,785		$	(12,831	)
Prior service cost (credit)		3,655			4,353			(2,171	)		(12,892	)
	$	71,660		$	28,729		$	(386	)	$	(25,723	)

_____________________

(1)

Prior to 2008, the measurement date for the Company’s pension and other postretirement plans applicable to the Distribution segment was September 30 and the measurement date for the other postretirement plans applicable to the Transportation and Storage segment was December 31. Effective December 31, 2008, in accordance with the measurement provisions of Statement No. 158, all pension and other postretirement plans are measured as of December 31.

(2)	Plan assets are recorded at fair value versus a calculated value as of the respective measurement dates.

(3)	The funded status as of December 31, 2007 includes $4 million and $440,000 of contributions made during the fourth quarter of 2007 to the pension and other postretirement benefit plans, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information for plans with an accumulated benefit obligation in excess of plan assets.

					Other
	Pension Benefits				Postretirement Benefits
	December 31,				December 31,
	2008		2007		2008		2007
	(In thousands)

Projected benefit obligation	$	172,063	$	162,824		N/A		N/A
Accumulated benefit obligation		163,999		154,950	$	86,917	$	71,571
Fair value of plan assets		102,395		128,342		46,340		54,010

Net Periodic Benefit Cost.

Net periodic benefit cost for the years ended December 31, 2008, 2007 and 2006 includes the components noted in the table below. Effective August 24, 2006, the Company’s responsibility for benefit obligations associated with five pension plans was relieved upon the transfer of the plans to the buyers of the assets of PG Energy and the Rhode Island operations of New England Gas Company. Additionally, effective August 24, 2006, the Company’s responsibility for benefit obligations associated with two other postretirement benefit plans was relieved upon the transfer of the plans to the buyer of the Rhode Island operations of New England Gas Company. The table below has been reclassified for the 2006 period to present net periodic benefit cost included in operating expenses from continuing operations, and excludes the net periodic benefit cost of the Company’s discontinued operations. Net periodic pension cost for discontinued operations totaled $50.4 million for the year ended December 31, 2006. Net periodic other postretirement benefit costs for discontinued operations totaled $(13.8) million for the year ended December 31, 2006. See Note 19 – Discontinued Operations for additional related information.

	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,									Years Ended December 31,
	2008			2007			2006			2008			2007			2006
	(In thousands)
Net Periodic Benefit Cost:
Service cost	$	2,596		$	2,715		$	2,599		$	2,525		$	1,788		$	1,890
Interest cost		9,972			9,388			8,899			5,415			4,053			3,615
Expected return on plan assets		(11,501	)		(9,619	)		(8,909	)		(3,246	)		(2,858	)		(1,871	)
Prior service cost (credit) amortization		560			623			584			(1,521	)		(2,809	)		(3,011	)
Recognized actuarial (gain) loss amortization		6,867			8,029			7,236			(1,006	)		(768	)		(145	)
Transfer of assets in excess
of obligations		-			-			-			-			1,915			-
		8,494			11,136			10,409			2,167			1,321			478
Regulatory adjustment (1)		2,728			(1,578	)		(7,710	)		2,665			2,665			2,665
Net periodic benefit cost	$	11,222		$	9,558		$	2,699		$	4,832		$	3,986		$	3,143

___________________

(1)

In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these amounts and periodic benefit cost calculated pursuant to Statement Nos. 87 and 106 is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission .

The estimated net actuarial loss (gain) and prior service cost (credit) for pension plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2009 are $8.4 million and $552,000, respectively. The estimated net actuarial loss (gain) and prior service cost (credit) for other postretirement plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2009 are $(848,000) and $(1.3) million, respectively.

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Assumptions.

The weighted-average assumptions used in determining benefit obligations are shown in the table below.

		Pension Benefits			Other Postretirement Benefits
		Years Ended December 31,			Years Ended December 31,
		2008	2007	2006	2008	2007	2006

Discount rate		6.05%	6.24%	5.77%	6.05%	6.34%	5.78%
Rate of compensation increase
	(average)	3.24%	3.47%	3.24%	N/A	N/A	N/A

The weighted-average assumptions used in determining net periodic benefit cost are shown in the table below. The table has been reclassified for the 2006 period to present discount rate data for plans relating to continuing operations, and excludes the discount rate data of the plans that relate to the Company’s discontinued operations. See Note 19 – Discontinued Operations for additional related information.

	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,									Years Ended December 31,
	2008			2007			2006			2008			2007			2006

Discount rate		6.24	%		5.77	%		5.50	%		6.52	%		5.78	%		5.50	%
Expected return on assets:
Tax exempt accounts		8.75	%		8.75	%		8.75	%		7.00	%		7.00	%		7.00	%
Taxable accounts		N/A			N/A			N/A			5.00	%		5.00	%		5.00	%
Rate of compensation increase		3.47	%		3.24	%		3.24	%		N/A			N/A			N/A

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets, with proper consideration of 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 ensure reasonableness and appropriateness.

The assumed health care cost trend rates used for measurement purposes with respect to the Company’s other postretirement benefit plans are shown in the table below.

	December 31,
	2008			2007

Health care cost trend rate assumed for next year		9.00	%		10.00	%
Ultimate trend rate		4.85	%		5.13	%
Year that the rate reaches the ultimate trend rate	2017			2017

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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		$	816	$	(741	)
Effect on accumulated postretirement benefit obligation		$	8,486	$	(7,476	)

Plan Assets.

The assets of the pension plans are invested in accordance with several investment practices that emphasize long-term investment fundamentals with an investment objective of long-term growth, taking into consideration risk tolerance and asset allocation strategies.

The broad goal and objective of the investment of the pension plans’ assets is to ensure that future growth of the assets is sufficient to offset normal inflation plus liability requirements of the plans’ beneficiaries. Pension plan assets should be invested in such a manner to minimize the necessity of net contributions to the plans to meet the plans’ commitments. The contributions will also be affected by the applicable discount rate that is applied to future liabilities. The discount rate will affect the net present value of the future liability and, therefore, the funded status.

The assets of the other postretirement plans are invested in accordance with sound investment practices that emphasize long-term investment fundamentals. The Investment Committee of the Company’s Board of Directors has adopted an investment objective of income and growth for the other postretirement plans. This investment objective (i) is a risk-averse balanced approach that emphasizes a stable and substantial source of current income and some capital appreciation over the long-term; (ii) implies a willingness to risk some declines in value over the short-term, so long as the other postretirement plans are positioned to generate current income and exhibit some capital appreciation; (iii) is expected to earn long-term returns sufficient to keep pace with the rate of inflation over most market cycles (net of spending and investment and administrative expenses), but may lag inflation in some environments; (iv) diversifies the other postretirement plans in order to provide opportunities for long-term growth and to reduce the potential for large losses that could occur from holding concentrated positions; and (v) recognizes that investment results over the long-term may lag those of a typical balanced portfolio since a typical balanced portfolio tends to be more aggressively invested. Nevertheless, the other postretirement plans are expected to earn a long-term return that compares favorably to appropriate market indices.

It is expected that these objectives can be obtained through a well-diversified portfolio structured in a manner consistent with the investment policy.

The Company’s weighted average asset allocation by asset category for the measurement periods presented is as follows:

	Pension Benefits						Other Postretirement Benefits
	At December 31,						At December 31,
Asset Category	2008			2007			2008			2007

Equity securities		53	%		61	%		32	%		31	%
Debt securities		25	%		24	%		55	%		62	%
Other		22	%		15	%		13	%		7	%
Total		100	%		100	%		100	%		100	%

Based on the pension plan objectives, target asset allocations are as follows: equity of 50 percent to 80 percent, fixed income of 20 percent to 50 percent and cash and cash equivalents of 0 percent to 10 percent.

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Based on the other postretirement plan objectives, target asset allocations are as follows: 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.

The above referenced target asset allocations for pension and other postretirement benefits are based upon guidelines established by the Company’s Investment Policy and is monitored by the Investment Committee of the 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.

Contributions.

The Company expects to contribute approximately $1.5 million to its pension plans and approximately $10 million to its other postretirement plans in 2009. The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

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.

			Other		Other
			Postretirement		Postretirement
			Benefits		Benefits
	Pension		(Gross, Before		(Medicare Part D
Years	Benefits		Medicare Part D)		Subsidy Receipts)
	(In thousands)

2009	$	11,017	$	3,983	$	576
2010		11,046		4,249		648
2011		11,026		4,740		712
2012		12,207		5,372		804
2013		12,074		6,085		749
2014-2018		63,460		39,011		4,736

The Medicare Prescription Drug Act was signed into law December 8, 2003. This act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Defined Contribution Plan. The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. The Company provides maximum matching contributions based upon certain Savings Plan provisions ranging from 2 percent to 6.25 percent of the participant’s compensation paid into the Savings Plan. Company contributions are 100 percent vested after five years of continuous service for all plans other than Missouri Gas Energy union employees and employees of the Fall River operation, which are 100 percent vested after six years of continuous service. Company contributions to the Savings Plan during the years ended December 31, 2008, 2007 and 2006 were $5.2 million, $3.8 million and $5.1 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 and range from 3.5 percent to 12 percent. Company contributions to Retirement Power Accounts during the years ended December 31, 2008, 2007 and 2006 were $7.4 million, $6.6 million and $5.1 million, respectively.

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Common Stock Held in Trust. From time to time, Southern Union purchases outstanding shares of its common stock to fund certain Company employee stock-based compensation plans. At December 31, 2008 and 2007, 663,080 and 783,445 shares, respectively, of common stock were held by various rabbi trusts for certain of those Company’s benefit plans.

15. Taxes on Income

The following table provides a summary of the current and deferred components of income tax expense from continuing operations for the periods presented:

	Years Ended December 31,
Income Tax Expense	2008			2007			2006
	(In thousands)
Current:
Federal	$	22,267		$	18,458		$	19,798
State		(558	)		5,654			2,251
		21,709			24,112			22,049

Deferred:
Federal		68,370			62,502			74,563
State		14,696			8,645			12,635
		83,066			71,147			87,198

Total federal and state income tax
expense from continuing operations	$	104,775		$	95,259		$	109,247

Effective tax rate		26	%		29	%		34	%

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

	December 31,
Deferred Income Tax Analysis	2008			2007
	(In thousands)
Deferred income tax assets:
Alternative minimum tax credit	$	7,249		$	13,560
Post-retirement benefits		34,492			24,320
Pension benefits		25,470			6,579
Unconsolidated investments		5,448			5,443
Derivative financial instruments (interest rates)		19,578			8,856
Other		23,515			10,765
Total deferred income tax assets		115,752			69,523

Deferred income tax liabilities:
Property, plant and equipment		(770,761	)		(693,350	)
Unconsolidated Investments (Citrus)		(6,204	)		(34,113	)
Derivative financial instruments (commodities)		(33,233	)		-
Goodwill		(16,953	)		(15,665	)
Environmental reserve		(10,999	)		(6,637	)
Other		(22,807	)		(11,460	)
Total deferred income tax liabilities		(860,957	)		(761,225	)
Net deferred income tax liability		(745,205	)		(691,702	)
Less current income tax assets (liabilities)		(22,655	)		1,303
Accumulated deferred income taxes	$	(722,550	)	$	(693,005	)

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

	Years Ended December 31,
Effective Income Tax Rate Analysis	2008			2007			2006
	(In thousands)
Computed statutory income tax expense
from continuing operations at 35%	$	139,974		$	113,389		$	114,215
Changes in income taxes resulting from:
Dividend received deduction		(44,862	)		(28,994	)		(10,696	)
to deferred tax liability
Executive compensation, non deductible		78			491			5,063
State income taxes, net of federal income tax benefit		9,190			9,295			9,411
Analysis of deferred tax accounts		-			-			(7,490	)
Other		395			1,078			(1,256	)
Actual income tax expense from continuing operations	$	104,775		$	95,259		$	109,247

The 2008 dividends received deduction includes $20.7 million resulting from a reduction in the Company’s deferred income tax liability in the fourth quarter of 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus. Due to the anticipated increase in dividends from Citrus after the completion of the Phase VIII Expansion, the Company expects the entire deferred income tax liability related to its investment in Citrus will be realized at the Company’s statutory income tax rate less the dividends received deduction. The 2008 dividends received deduction also includes $21.6 million for dividends paid by Citrus prior to the aforementioned reduction in the Company’s deferred income tax liability and $2.5 million for Citrus’ unremitted earnings after the aforementioned reduction in the Company’s deferred income tax liability.

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The Company completed an analysis of its deferred tax accounts in 2005. As a result of the 2005 analysis and expiring statute of limitations in 2006, federal and state income tax expense for the year ending December 31, 2006 was decreased $8.4 million, primarily due to adjustments related to bad debt reserves and property, plant and equipment. The decrease in income tax expense for the year ended December 31, 2006 is comprised of federal income taxes of $7.5 million and state income taxes of $900,000.

Effective January 1, 2007, the Company evaluates its tax reserves (unrecognized tax benefits) under the recognition, measurement and derecognition thresholds as prescribed by FIN No. 48. The implementation of FIN No. 48 did not have a material impact on the consolidated financial statements and did not require an adjustment to Retained earnings (deficit). The amount of unrecognized tax benefits at January 1, 2007 was $570,000, all of which would impact the Company’s EITR if recognized.

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

	Years ended December 31,
	2008			2007
	(in thousands)

Beginning of the year	$	570		$	570

Additions:
Tax positions taken in prior years		4,427			-
Tax positions taken in current year		2,783			-

Reductions:
Lapse of statutue of limitations		(570	)		-

End of year	$	7,210		$	570

During 2008, the Company’s increase in the amount of its unrecognized tax benefits in prior years and current year were attributable to certain state filing positions of $4.4 million ($2.9 million, net of federal tax) and $2.8 million ($1.8 million, net of federal tax), respectively. The Company’s decrease in the amount of its unrecognized tax benefits was as a result of the lapse of statutes of limitations for federal tax positions for the tax periods ended June 30, 2004 and December 31, 2004.

As of December 31, 2008, the Company has $7.2 million ($4.7 million, net of federal tax) of unrecognized tax benefits, all of which would impact the Company’s EITR if recognized. The Company believes it is reasonably possible that its unrecognized tax benefits may be reduced by $1.1 million ($750,000, net of federal tax) within the next twelve months due to settlement of certain state filing positions.

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.

At January 1, 2007, the Company recorded a liability of $2.4 million ($1.5 million, net of tax) representing interest payable to the IRS, state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003. All of the interest liability was paid in 2007. There were no federal penalties assessed as a result of this examination and no significant state penalties associated with the amended tax return filings.

During 2008, the Company recognized interest and penalties of $310,000 ($200,000, net of federal tax). At December 31, 2008, the Company has interest and penalties accrued of $330,000 ($215,000, net of federal tax).

In November 2006, the IRS completed its examination of the Company’s federal income tax return for the fiscal year ended June 30, 2003. The Company reached a favorable settlement regarding the like-kind exchange structure under Section 1031 of the Internal Revenue Code related to the sale of the assets of its Southern Union Gas natural gas operating division and related assets to ONEOK Inc. for approximately $437 million in January 2003 and the acquisition of Panhandle in June 2003.

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$11.6 million, plus interest, primarily due to alternative minimum tax credits and other favorable audit results. As a result of the IRS examination, the Company paid $12.6 million of income tax to the IRS in November 2006, received a refund of $1 million from the IRS and paid $1.4 million to state and local jurisdictions in 2007. The Company also paid $2.4 million ($1.5 million, net of tax) in 2007 representing interest payable to the IRS, state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003. No penalties were assessed to the Company in this IRS examination.

The Company will be entitled to recover a corresponding $26.3 million of income tax benefit over time from additional depreciation deductions from the Panhandle assets due to higher tax basis in such assets as a result of the reduction of income tax benefits from the like-kind exchange.

The Company is no longer subject to U.S. federal, state or local examinations for the tax period ended December 31, 2004 and prior years, except for a few state and local jurisdictions for the tax year ended June 30, 2003. The Company settled the IRS examination of the year ended June 30, 2003 in November 2006. Generally, the state impact of the federal change remains subject to state and local examination for a period of up to one year after formal notification to the state and local jurisdictions. In 2007, the Company filed all required state amended returns as a result of the federal change. With a few exceptions, the state and local statutes expired in 2008 with respect to the tax year ended June 30, 2003.

16. Regulation and Rates

Panhandle. The Company commenced construction of an enhancement at its Trunkline LNG terminal in February 2007. This infrastructure enhancement project will increase send out flexibility at the terminal and lower fuel costs. Recent cost projections indicate the construction costs will be approximately $430 million, plus capitalized interest. The revised cost reflects increases in the quantities and cost of materials required, higher contract labor costs, including reduced productivity due to an August 2008 tropical storm and two September 2008 hurricanes, and an allowance for additional contingency funds, if needed. 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. The project is currently expected to be in operation in the third quarter of 2009. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement project contract, which runs 20 years from the in-service date. Approximately $351.3 million and $178.3 million of costs, including capitalized interest, are included in the line item Construction work-in-progress at December 31, 2008 and 2007, respectively.

The Company has received approval from FERC to modernize and replace various compression facilities on PEPL. Four stations have been completed as of December 31, 2008. Construction activities at two compressor stations are in progress and planned to be completed by the end of 2010, with the remaining cost for these stations estimated at approximately $43 million, plus capitalized interest. Approximately $19.7 million and $124.7 million of costs related to these projects are included in the line item Construction work-in-progress at December 31, 2008 and 2007, respectively.

Trunkline completed construction on its field zone expansion project with the majority of the project put into service in late December 2007 and the remainder placed in-service in February 2008. The expansion project included the north Texas expansion and creation of additional capacity on Trunkline’s pipeline system in Texas and Louisiana to increase deliveries to Henry Hub. Trunkline has increased the capacity along existing rights-of-way from Kountze, Texas to Longville, Louisiana by approximately 625 MMcf/d with the construction of approximately 45 miles of 36-inch diameter pipeline. The project included horsepower additions and modifications at existing compressor stations. Trunkline has also created additional capacity to Henry Hub with the construction of a 13.5 mile, 36-inch diameter pipeline loop from Kaplan, Louisiana directly into Henry Hub. The Henry Hub lateral provides capacity of 1 Bcf/d from Kaplan, Louisiana to Henry Hub. Approximately $99.4 million and $178.3 million of costs for this project were closed to Plant in service in 2008 and 2007, respectively.

FERC is responsible under the Natural Gas Act for assuring that rates charged by interstate pipelines are "just and reasonable." To enforce that requirement, FERC applies a ratemaking methodology that determines an allowed rate of return on common equity for the companies it regulates. On October 25, 2006, a group including producers and various trade associations filed a complaint under Section 5 of the Natural Gas Act against Southwest Gas requesting that FERC initiate an investigation into Southwest Gas’ rates, terms and conditions of

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service and grant immediate interim rate relief. FERC initiated a Section 5 proceeding on December 21, 2006, setting this issue for hearing. Pursuant to FERC order, Southwest Gas filed a cost and revenue study with FERC on February 20, 2007. On August 1, 2007, Southwest Gas filed a Section 4 rate case requesting an increase in rates. On August 31, 2007, the FERC accepted Southwest Gas’ rate increase to become effective on February 1, 2008, subject to refund. This order also consolidated the Section 5 proceeding with the Section 4 rate case. On November 28, 2007, Southwest Gas filed a settlement with FERC. The settlement was approved by FERC on February 12, 2008, which settlement resulted in Southwest Gas’ rates remaining substantially similar to its rates that were in effect prior to the Section 4 and Section 5 proceedings.

Sea Robin filed a rate case with FERC in June 2007, requesting an increase in its maximum rates. Several parties submitted protests to the rate increase filing with FERC. On July 30, 2007, FERC suspended the effectiveness of the filed rate increase until January 1, 2008. The filed rates were put into effect on January 1, 2008, subject to refund. On February 14, 2008, at the request of the participants in the proceeding, the procedural schedule was suspended to facilitate the filing of a settlement. On April 29, 2008, Sea Robin submitted to FERC a Stipulation and Agreement (Settlement) that would resolve all issues in the proceeding. The Administrative Law Judge certified the Settlement to FERC on June 3, 2008. The Settlement rates have been approved, effective December 1, 2008. Customer refund liability provisions of approximately $3.5 million, including interest, have been recorded as of December 31, 2008 and were refunded in the first quarter of 2009.

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 have identified HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004. Operators must have ranked the risk of their pipeline segments containing HCAs and completed assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments are generally conducted on the higher risk segments first, with the balance being completed by December 2012. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2008 and 2007, the Company had completed 83 percent and 80 percent of the required risk assessments, respectively. All systems operated by the Company will be compliant with the rule; however, while identification and location of all 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 $20 million to $28 million per year through 2012.

Missouri Gas Energy. On May 1, 2006, Missouri Gas Energy announced the filing of a proposal with the MPSC to increase annual revenues by approximately $41.7 million, or 6.8 percent. Following a hearing, the MPSC issued a Report and Order on March 22, 2007, authorizing an annual revenue increase of $27.2 million, or 4.5 percent. In its order, the MPSC calculated the revenue increase using a return on equity of 10.5 percent and set residential rates using a straight fixed-variable rate design, thereby eliminating the impact of weather and conservation on residential margin revenues and related earnings. The new rates went into effect on April 3, 2007. This rate order was appealed by Missouri Gas Energy and the Office of the Public Counsel, with Missouri Gas Energy challenging the adequacy of the overall rate increase awarded and the Office of the Public Counsel challenging the design of residential distribution rates that eliminates the impact of weather and conservation for residential margin revenues and related earnings. On July 1, 2008, the Circuit Court of Greene County, Missouri made a docket entry indicating that, following judicial review, it had affirmed the Report and Order issued by the MPSC resolving Missouri Gas Energy’s general rate increase that went into effect on April 3, 2007. While that judicial review proceeding has been appealed to the Southern District of the Missouri Court of Appeals by both Missouri Gas Energy and the Office of the Public Counsel, the Company does not believe the outcome of the judicial review will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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New England Gas Company. On July 17, 2008, New England Gas Company made a filing with the MDPU seeking to implement an annual base rate increase of approximately $5.6 million. The MDPU issued an order on February 2, 2009 granting an annual base rate increase of approximately $3.7 million, effective February 3, 2009.

On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent. This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007. On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments in its entirety. The Company appealed that decision to the Massachusetts Supreme Judicial Court on February 17, 2009.

17. Leases

The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases. The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2009—$21.4 million; 2010—$16.3 million; 2011— $16.5 million; 2012—$14.2 million; 2013— $14.1 million and $45.3 million in total thereafter. Rental expense was $19.2 million, $19.9 million and $18.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

18. Commitments and Contingencies

Environmental

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. The Company follows the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, “Environmental Remediation Liabilities”, for recognition, measurement, display and disclosure of environmental remediation liabilities.

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures will have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. The table below reflects the amount of accrued liabilities recorded in the Consolidated Balance Sheet at December 31, 2008 and 2007 to cover probable environmental response actions:

	December 31,
	2008		2007
	(In thousands)

Current	$	3,513	$	6,772
Noncurrent		15,626		15,209
Total Environmental Liabilities	$	19,139	$	21,981

During the years ended December 31, 2008, 2007 and 2006, the Company had $12 million, $9.3 million and $7 million of expenditures related to environmental cleanup programs, respectively.

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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. In December 2008, the EPA again extended the SPCC rule compliance dates until November 20, 2009, permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations. The Company is currently reviewing the impact of the modified regulations on operations in its Transportation and Storage and Gathering and Processing segments 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.

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems. Panhandle 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. Panhandle has developed and is implementing a program to remediate such contamination. Remediation and decontamination has been completed at each of the 35 compressor station sites where auxiliary buildings that house the air compressor equipment were impacted by the past use of lubricants containing PCBs. At some locations, PCBs have been identified in paint that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline system, PCBs were discovered on the painted surfaces of equipment in a building that is outside the scope of the compressed air system program and the existing PCB impacted paint program. Assessments indicated PCBs at regulated levels at a number of locations, which will require approximately $3.2 million to remediate, all of which was recorded in 2008.

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, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, such as the Pierce Waste Oil Sites described below, Panhandle may share liability associated with contamination with other PRPs. Panhandle 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.

PEPL and Trunkline, together with other non-affiliated parties, were identified as potentially liable for conditions at three former waste oil disposal sites in Illinois – the Pierce Oil Springfield site, the Dunavan Waste Oil site and the McCook site (collectively, the Pierce Waste Oil Sites). PEPL and Trunkline received notices of potential liability from the U.S. EPA for the Dunavan site by letters dated September 30, 2005. Although no formal notice has been received for the Pierce Oil Springfield site, special notice letters are anticipated and the process of listing the site on the National Priority List has begun. No formal notice has been received for the McCook site. 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.

On June 16, 2005, PEPL experienced a release of liquid hydrocarbons near Pleasant Hill, Illinois. The EPA took the lead role in overseeing the subsequent cleanup activities, which have been completed. PEPL has resolved claims of affected boat owners and the marina operator. PEPL received a violation notice from the IEPA alleging that PEPL was in apparent violation of several sections of the Illinois Environmental Protection Act by allowing the release. The violation notice did not propose a penalty. Responses to the violation notice were submitted and the responses were discussed with the agency. In December 2005, the IEPA notified PEPL that the matter might be considered for referral to the Office of the Attorney General, the State’s Attorney or the EPA for formal enforcement action and the imposition of penalties. The only contact from the IEPA on this matter has been three requests for information to which the Company responded in January 2007, April 2008 and August 2008. The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Air Quality Control. In early April 2007, the IEPA proposed a rule to the IPCB for adoption to control NOx emissions from reciprocating engines and turbines, including a provision applying the rule beyond issues addressed by federal provisions, pursuant to a blanket statewide application. After objections were filed with the IPCB, the IEPA filed an amended proposal withdrawing the statewide applicability provisions of the proposed rule and applying the rule requirements to non-attainment areas. The amended proposal was approved on January 10, 2008. No controls on PEPL and Trunkline stations are required under the most recent proposal. However, the IEPA indicated in earlier industry discussions that it was reserving the right to make future proposals for statewide controls. In the event the IEPA proposes a statewide rule again, preliminary estimates indicate the cost of compliance would require minimum capital expenditures of approximately $45 million for emission controls.

The KDHE has established certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area. These measures will be triggered if there are any new elevated ozone readings in the Kansas City area. One of the NOx emission sources that will be impacted is the PEPL Louisburg compressor station. In addition, the EPA has revised the ozone standard and the Kansas City area will likely be designated as a non-attainment area under the new and stricter standard. Issues associated with reducing emissions at the Louisburg compressor station are being discussed with the KDHE. In the event KDHE requires emission reductions, it is estimated that approximately $14 million in capital expenditures will be required.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems. SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. SUGS has a program to remediate such contamination. The 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 and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. 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.

Air Quality Control. On June 16, 2006, SUGS, as the facility operator and holder of a 50 percent interest in a partnership that leases the Grey Ranch facility, submitted information to the TCEQ in connection with a request to permit the Grey Ranch facility to continue its current level of emissions. The State of Texas required all previously grandfathered emission sources to obtain permits or shut down by March 1, 2008. By letter dated September 5, 2007, the TCEQ issued a permit extending current emission levels to March 1, 2009. Prior to the conclusion of the extension period, SUGS must obtain appropriate permits and implement an emission control strategy that achieves specific maximum allowable emissions rates. It is anticipated that the Company will not bear any of the costs associated with the emission controls. It is expected that Roc Gas Company, or one of its affiliates, which holds the other 50 percent interest in the partnership that leases the Grey Ranch facility (and also owns the site and facility), will bear all the costs necessary to construct control devices and/or modify its nearby compression facilities in order to meet maximum allowable emission limits.

On November 15, 2008, SUGS submitted a permit application to the TCEQ for the installation of control devices and approval of a long term emission control strategy that achieves specific emission rates as outlined in the current permit. The permit was issued on December 17, 2008. SandRidge, a Roc Gas affiliate, has also placed an order for two thermal oxidizers to meet the emission control strategy outlined in the permit application. The first thermal oxidizer is scheduled to be completed and operational prior to March 1, 2009.

Distribution Segment Environmental Matters.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas”. Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required. The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities

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vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. 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, and may also benefit from insurance policies or 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.

North Attleborough MGP Site in Massachusetts. In November 2003, the MDEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. The Company, working with the MDEP, is in the process of performing assessment work at these properties. In a September 2006 report filed with MDEP, the Company proposed a remedy for the upland portion of the site by means of an engineered barrier. Construction of this remedy was completed in October 2008. Assessment activities continue both on- and off-site to define the nature and extent of the impacts. It is estimated that the Company will spend approximately $7.1 million over the next several years to complete the investigation and remediation activities at this site, as well as maintain the engineered barrier. As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with this site have been included in Regulatory assets in the Consolidated Balance Sheet.

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 made accruals in accordance with FASB Statement No. 5, “Accounting for Contingencies”, 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.

Bay Street, Tiverton, Rhode Island Site. On March 17, 2003, RIDEM sent the Company’s New England Gas Company division a letter of responsibility pertaining to soils allegedly impacted by historic MGP residuals in a residential neighborhood in Tiverton, Rhode Island. Without admitting responsibility or accepting liability, New England Gas Company began assessment work in June 2003 and has continued to perform assessment field work since that time. On September 19, 2006, RIDEM filed an Amended Notice of Violation seeking an administrative penalty of $1,000/day, which as of the date of RIDEM’s filing totaled $258,000 and continues to accrue. In June 2007, the Rhode Island Legislature considered, but failed to adopt, legislation that would have increased the maximum administrative penalty under a Notice of Violation to $50,000/day on a prospective basis. Similar legislation was considered in June 2008 that would have increased the maximum administrative penalty under a Notice of Violation to $25,000/day on a prospective basis. That proposed legislation was not adopted. On April 19, 2007, the Company filed a complaint, and an accompanying preliminary injunction motion, against RIDEM in Rhode Island Superior Court, seeking, among other things, a declaratory judgment that RIDEM's Amended Notice of Violation is premised on an unlawful application of RIDEM's regulations and that RIDEM's pending administrative proceeding against the Company is invalid. On July 13, 2007, the Superior Court dismissed the Company’s suit, finding that RIDEM’s Administrative Adjudication Division (AAD) has original jurisdiction to determine “responsible party” status and finding premature the Company’s challenge to RIDEM’s unlawful application of its own regulations because the Company did not first seek a ruling on that issue from RIDEM’s AAD. The Company has appealed from part of the Superior Court’s ruling, and has also filed a motion for summary judgment in the AAD proceeding seeking dismissal thereof based on RIDEM’s unlawful application of its own regulations. Briefing on the summary judgment motion is now complete. The Hearing Officer in the AAD proceeding has not yet issued a ruling on that motion. In consideration of the ongoing settlement discussions described below, the AAD proceeding has been stayed. The Company will continue to vigorously defend itself in the AAD proceeding.

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During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood. These lawsuits were consolidated for trial. The plaintiffs seek to recover damages for the diminution in value of their property, lost use and enjoyment of their property and emotional distress in an unspecified amount. The Company removed the lawsuits to federal court and filed motions to dismiss. On November 3, 2006, the Court dismissed plaintiffs’ claims relating to gross negligence, private nuisance, infliction of emotional distress and violation of the Rhode Island Hazardous Waste Management Act. The Court denied the Company’s motion to dismiss as to claims relating to negligence, strict liability and public nuisance, as well as plaintiffs’ request for punitive damages. In September and October 2007, the court granted the Company’s motion to serve third-party complaints on a total of nine PRPs. Among the PRPs the Company impleaded is the Town of Tiverton, which asserted a counterclaim against the Company under the Comprehensive Environmental Response, Compensation, and Liability Act. On January 30, 2008, the Court denied the Company's motion for partial judgment on the pleadings seeking dismissal of plaintiffs' claims for remediation, finding, contrary to the Company's contention, that RIDEM does not have exclusive jurisdiction to determine the responsibility for and extent of remediation of plaintiffs' properties. On February 13, 2008, the Court entered a "Trial Order" superseding several prior orders, and directing that (1) on or about April 24, 2008, the Court will conduct a "Phase I" trial on claims asserted by plaintiffs and by Tiverton against the Company; (2) the Phase I trial will be bifurcated into a liability stage, and, if necessary, a damages stage, with both stages to be tried before the same jury; (3) the discovery cutoff date for the Phase I trial be extended from February 29 to March 21, 2008; (4) if necessary, a “Phase II” trial shall address the Company's third-party claims against the PRPs it has impleaded; and (5) the parties to the Phase II trial shall have 120 days after the Phase I trial to conduct discovery related thereto. The Court subsequently ruled that Tiverton’s claims against the Company will be tried in the Phase II trial. The Company filed a motion seeking extension of the discovery and trial date, which was denied in material part. The Phase I trial, which was scheduled to commence on April 28, 2008, was adjourned without date by the Court in consideration of the progress of settlement discussions between the Company and the plaintiffs. On November 18, 2008, the plaintiffs filed a motion to enforce a settlement they claim was reached with the Company in April 2008. Plaintiffs also filed a motion to seal the papers related to the motion to enforce. On December 2, 2008, the Company filed its opposition to the motion to enforce asserting that no settlement was reached. On December 2, 2008, the Company also filed a motion to recuse the Court from all further substantive proceedings in the case, and filed its own motion supporting the sealing of all papers on the motion to enforce. On December 16, 2008, the Court issued a memorandum and order (i) denying the motion to seal the papers related to the motion to enforce, which papers the Court then placed in the public file; and (ii) granting the motion to recuse the Court from all further substantive matters in the case. The case has now been assigned to another Judge who held an evidentiary hearing on February 6, 2009 on plaintiffs’ motion to enforce. The Court has directed plaintiffs, the Town of Tiverton and the Company to participate in a mediation on March 6, 2009. A new trial date has not been set. 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.

Mercury Release. In October 2004, New England Gas Company discovered that one of its facilities had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. On October 16, 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island alleging violation of permitting requirements under the federal RCRA and notification requirements under the federal Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. The Company entered a not guilty plea on October 29, 2007 and trial commenced on September 22, 2008. On October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts, and found the Company guilty on the other RCRA count. On December 1, 2008, the Company filed motions for acquittal and alternatively for a new trial with respect to the RCRA count on which the Company was found guilty. Briefing on such motions is now complete. In the event such motions are not granted, sentencing as regards the single RCRA count, is presently scheduled for May 7, 2009. The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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On January 20, 2006, a complaint was filed against the Company in the Superior Court in Providence, Rhode Island regarding the mercury release from the Pawtucket facility, asserting claims for personal injury and property damage as a result of the release. The suit was removed to Rhode Island federal court on January 27, 2006. A motion to remand the case to state court filed by plaintiffs was denied on April 16, 2007. The Company thereafter moved to dismiss plaintiffs’ amended complaint, which motion was granted in part, dismissing claims for public nuisance, private nuisance and violation of Rhode Island’s Hazardous Waste Management Act, leaving plaintiffs with claims for negligence and strict liability. The Court has set March 1, 2009 as the closure date for all discovery. On October 18, 2007, an attorney representing other Pawtucket residents filed suit against the Company in the Superior Court in Providence asserting claims similar to those pending in the above-described federal court suit for personal injury and property damage. An additional complaint alleging personal injury arising out of the mercury release was filed on behalf of three plaintiffs with the District Court for the Sixth District, Providence County, Rhode Island, on January 22, 2008. The Company will vigorously defend all such suits. 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.

Jack Grynberg. Jack Grynberg, an individual, filed actions for damages against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Among the defendants are Panhandle, Citrus, Florida Gas and certain of their affiliates (Company Defendants). On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the Company Defendants. Grynberg is appealing that action to the Tenth Circuit Court of Appeals. Grynberg’s opening brief was filed on July 31, 2007. Respondents filed their brief rebutting Grynberg’s arguments on November 21, 2007. A hearing before the Court of Appeals was held on September 25, 2008. The Court has not yet ruled on Grynberg’s appeal. A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle, in U.S. District Court for the District of Kansas. Panhandle is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action. Panhandle and the other Company Defendants believe that their measurement practices conformed to the terms of their FERC gas tariffs, which were filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle and the other Company Defendants complied with the terms of their tariffs) and will continue to vigorously defend against them, including any appeal from the dismissal of the Grynberg case. The Company does not believe the outcome of these cases will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Southwest Gas Litigation. During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire Southwest Gas Corporation. All of these actions eventually were transferred to the U.S. District Court for the District of Arizona (District Court). The trial of the Company’s claims against the sole remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to the Company of nearly $400,000 in actual damages and $60 million in punitive damages against former Commissioner Irvin. Following appeal to the Ninth Circuit Court of Appeals and remand to the District Court, the District Court reconsidered the punitive damages award and entered an order of remittitur on November 21, 2006, reducing the punitive damages amount to $4 million, plus interest. Irvin appealed that award to the Ninth Circuit Court of Appeals which ordered that the punitive damages award be further reduced to approximately $1.2 million, plus interest. A motion to reconsider that decision has been filed. The Company anticipates that the Court’s decision on rehearing will be issued in 2009. The Company intends to continue to vigorously pursue its case against former Commissioner Irvin, including seeking to collect all damages ultimately determined to lie against him. There can be no assurance, however, as to the amount of such damages, or as to the amount, if any, that the Company ultimately will collect.

GP II Energy Litigation. On October 23, 2006, landowners filed suit against the Company in the 109th District Court of Winkler County, Texas, seeking money damages, equitable relief and punitive damages alleging continuing pollution to underground aquifers underlying the plaintiffs’ approximately 16,000 acre property. SUGS operated the Halley Plant, a hydrocarbon processing facility, which is located on a limited portion of the plaintiff landowners’ ranch pursuant to a lease. On February 15, 2008, the Company learned that plaintiffs significantly revised their claims to include approximately $40 million in economic damages and approximately $85 million in punitive damages. On March 31, 2008, plaintiffs filed a third amended petition revising their claims to include

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approximately $96 million in economic damages and approximately $193 million in punitive damages. The parties finalized a settlement of the case in October 2008, pursuant to which SUGS paid $1.4 million to the plaintiffs and all claims were dismissed with prejudice.

East End Project. 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, multiple inspection contractors 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 underpayment of approximately $18 million. The matter is pending in state court in Harris County, Texas. Trial is set for February 2010. 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.

Other Commitments and Contingencies

With respect to the Company’s damage assessments associated with Hurricane Gustav, the Company recorded $3 million of estimated expense and believes the capital expenditure impact related to the hurricane was insignificant. As the total capital expenditure amount and the related expense is expected to be below the Company’s $10 million property insurance deductible, the Company does not expect any of the repair and replacement costs associated with Hurricane Gustav will be reimbursed by its property insurance carrier.

With respect to the Company’s ongoing damage assessments associated with Hurricane Ike, the Company currently estimates an expense impact of $11 million, which was recorded in 2008, and the capital expenditure estimate relating to the hurricane will total approximately $125 million in the period 2008 through 2010. These estimates are subject to further revision as the assessment of the damage to the Company’s facilities is ongoing. Approximately $23 million of the capital expenditures were incurred as of December 31, 2008. The Company anticipates reimbursement from its property insurance carrier 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. The Company’s insurance provider has announced that it expects to reach the $750 million aggregate exposure limit and currently estimates the payout amount will not exceed 84 percent based on estimated claim information it has received. The final amount of any applicable pro rata reduction cannot be determined until the Company’s insurance provider has received and assessed all claims.

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Panhandle Capital Expenditures. The Company estimates remaining capital expenditures associated with its LNG terminal enhancement and compressor modernization projects will be approximately $145 million, with approximately $115 million to be incurred in 2009, plus capitalized interest.

Purchase Commitments. At December 31, 2008, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable and market-based prices that have an aggregate value of approximately $1.01 billion. The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased. The Company has purchased gas tariffs in effect for all its utility service areas that provide for recovery of its purchase gas costs under defined methodologies and the Company believes that all costs incurred under such commitments will be recovered through its purchased gas tariffs.

Missouri Safety Program. Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in its service territories in the Missouri Safety Program. This program includes replacement of Company and customer-owned natural gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains. In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period. On August 28, 2003, the State of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects. The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures. The Company incurred capital expenditures of $14.1 million in 2008 related to this program and estimates incurring approximately $126.4 million over the next 11 years, after which all service lines, representing about 30 percent of the annual safety program investment, will have been replaced.

Other. The Company had standby letters of credit outstanding of $7 million and $18.5 million at December 31, 2008 and 2007, respectively, which guarantee payment of insurance claims and other various commitments.

19. Discontinued Operations

On August 24, 2006, the Company completed the sale of the assets of its PG Energy natural gas distribution division to UGI Corporation for $580 million in cash, excluding certain working capital adjustment reductions of approximately $24.4 million, which were paid in the first quarter of 2007. Additionally, on August 24, 2006, the Company completed the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA for $575 million in cash, less the assumption of approximately $77 million of debt and excluding certain working capital adjustment reductions of approximately $24.9 million, which were paid in the first quarter of 2007.

The results of operations of these divisions have been segregated and reported as Discontinued operations in the Consolidated Statement of Operations for all periods presented. The PG Energy natural gas distribution division and Rhode Island operations of the New England Gas Company natural gas distribution division were historically reported within the Distribution segment.

Loss from discontinued operations before income taxes in the Consolidated Statement of Operations includes a loss for 2006 of $56.8 million recorded by the Company upon the sale of the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division. Significant components contributing to the loss include $19.4 million of asset impairment charges related to increases in property, plant and equipment during 2006, selling costs of $4.7 million, and charges associated with pre-closing arrangements between the Company and the buyers, principally consisting of $15.1 million of pension funding requirements and $5.8 million of premiums related to the early retirement of debt. An additional factor related to higher property, plant and equipment balances is the cessation of recording depreciation expense subsequent to approval of the Company’s Board of Directors in January 2006 to dispose of the applicable assets.

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The Company incurred $142.4 million of income tax expense in 2006 resulting from $379.8 million of non-deductible goodwill that had no tax basis. Additionally, the Company incurred $17.6 million of income tax expense as a result of the write-off of a tax-related regulatory asset.

The following table summarizes the combined results of operations that have been segregated and reported as discontinued operations in the Consolidated Statement of Operations.


	Year Ended
	December 31, 2006 (2)
	(In thousands,except per share amounts)

Operating revenues	$	512,935
Operating income		54,662
Loss from discontinued operations (1)		(152,952	)
Net loss available from discontinued
operations per share:
Basic	$	(1.33	)
Diluted	$	(1.30	)

__________________

(1) Loss from discontinued operations does not include any allocation of corporate interest

expense or other corporate costs.

(2) Represents results of operations for January 1, 2006 through August 24, 2006.

20. Asset Retirement Obligations

Statement No. 143 requires an ARO to be recorded when a legal obligation to retire an asset exists. FIN No. 47 clarifies that an ARO should be recorded for all assets with legal retirement obligations, even if the enforcement of the obligation is contingent upon the occurrence of events beyond the company’s control (Conditional ARO). The fair values of the AROs were calculated using present value techniques. These techniques 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.

Although a number of other assets in the Company’s system are subject to agreements or regulations that give rise to an ARO or a Conditional ARO upon the Company’s discontinued use of these assets, AROs were not recorded for most of these assets because the fair values of these AROs were not reliably estimable. The principal reason the fair values of these AROs were not subject to reliable estimation was because the lives of the underlying assets are indeterminate. Management has concluded that the Panhandle pipeline system, as a whole, and the SUGS natural gas gathering and processing system, as a whole, have indeterminate lives. In reaching this conclusion, management considered its intent for operating the systems, the economic life of the underlying assets, its past practices and industry practice.

The Company intends to operate the pipeline and the natural gas gathering and processing systems indefinitely as a going concern. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems 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 and current estimates of recoverable reserves, management expects supply and demand to exist for the foreseeable future.

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The Company has in place a rigorous repair and maintenance program that keeps the pipeline and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets on the systems may be replaced, the pipeline and the natural gas gathering and processing systems themselves will remain intact indefinitely. AROs generally do not arise unless a pipeline or a facility (or portion thereof) is abandoned. The Company does not intend to make any such abandonments as long as supply and demand for natural gas remains relatively stable.

The following table is a general description of ARO and associated long-lived assets at December 31, 2008:

	In Service
ARO Description	Date	Long-Lived Assets	Amount
			(In thousands)
Retire offshore platforms and lateral lines	Various	Offshore lateral lines	$	6,574
Other	Various	Mainlines, compressors and gathering plants	$	1,269

As of December 31, 2008, no assets are 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,
	2008			2007			2006
	(In thousands)

Beginning balance	$	12,762		$	10,535		$	8,200
Addition from acquisition of the Sid
Richardson Energy Services business		-			-			885
Incurred		33,773			64			-
Revisions		6,379			2,250			1,189
Settled		(2,141	)		(907	)		(414	)
Accretion expense		868			820			675
Ending balance	$	51,641		$	12,762		$	10,535

The Company determined that certain of its offshore facilities damaged by Hurricane Ike will not be replaced. The Company is required by federal regulations to remove such facilities when they are no longer useful. This resulted in the establishment of an ARO of $33.8 million and recognition of expense in 2008 of $4 million. The amount expensed represents the ARO cost not previously accrued. For additional information related to the impact of the 2008 hurricanes, see Note 18 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage.

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21. Reportable Segments

The Company’s reportable business segments are organized based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses, as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus. The Company acquired the Sid Richardson Energy Services business on March 1, 2006, which represents the Gathering and Processing reportable segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. See Note 1 – Corporate Structure for additional information associated with the Company’s reportable segments.

Revenue included in the Corporate and other category is primarily attributable to PEI Power Corporation, which generates and sells electricity. PEI Power Corporation does not meet the quantitative threshold for segment reporting.

The Company evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:

·	items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;

·	income taxes;

interest;

·	dividends on preferred stock; and

·	loss on extinguishment of preferred stock.

The following tables set forth certain selected financial information for the Company’s segments for the years ended December 31, 2008, 2007 and 2006. Financial information for the Gathering and Processing segment reflects operations of SUGS beginning on its acquisition date of March 1, 2006. The Consolidated Statement of Operations segment information for all periods presented has been reclassified to distinguish between results of operations from continuing and discontinued operations.

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	Years Ended December 31,
Segment Data	2008			2007			2006
	(In thousands)
Operating revenues from external customers:
Transportation and Storage	$	721,640		$	658,446		$	577,182
Gathering and Processing		1,521,041			1,221,747			1,090,216
Distribution		821,673			732,109			668,721
Total segment operating revenues		3,064,354			2,612,302			2,336,119
Corporate and other		5,800			4,363			4,025
	$	3,070,154		$	2,616,665		$	2,340,144

Depreciation and amortization:
Transportation and Storage	$	103,807		$	85,641		$	72,724
Gathering and Processing		62,716			59,560			47,321
Distribution		30,530			30,251			30,353
Total segment depreciation and amortization		197,053			175,452			150,398
Corporate and other		2,196			2,547			1,705
	$	199,249		$	177,999		$	152,103

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	75,173		$	99,222		$	141,310
Gathering and Processing		(990	)		1,300			(188	)
Corporate and other		847			392			248
	$	75,030		$	100,914		$	141,370

Other income (expense), net:
Transportation and Storage	$	1,951		$	1,604		$	3,354
Gathering and Processing		104			140			1,571
Distribution		(1,830	)		(1,902	)		(2,130	)
Total segment other income (expense), net		225			(158	)		2,795
Corporate and other		2,100			(725	)		37,123
	$	2,325		$	(883	)	$	39,918

	Years Ended December 31,
Segment Data	2008			2007			2006
	(In thousands)

Segment performance:
Transportation and Storage EBIT (1)	$	404,834		$	407,459		$	431,959
Gathering and Processing EBIT		145,363			65,368			62,630
Distribution EBIT (1)		61,418			62,195			36,349
Total segment EBIT		611,615			535,022			530,938
Corporate and other (1)		(4,281	)		(7,906	)		5,435
Interest expense		207,408			203,146			210,043
Federal and state income taxes		104,775			95,259			109,247
Earnings from continuing operations		295,151			228,711			217,083
Loss from discontinued operations before
income taxes		-			-			(2,369	)
Federal and state income taxes		-			-			150,583
Loss from discontinued operations		-			-			(152,952	)
Net earnings		295,151			228,711			64,131
Preferred stock dividends		12,212			17,365			17,365
Loss on extinguishment of preferred stock		3,527			-			-
Net earnings available for common stockholders	$	279,412		$	211,346		$	46,766

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

__________________

(1)

					Recast Adjustments
	EBIT as Reported				Increase (Decrease)						Recast EBIT
Segment	2007		2006		2007			2006			2007			2006
	(In thousands)

Transportation and Storage	$	391,029	$	417,536	$	16,430		$	14,423		$	407,459		$	431,959
Distribution		70,568		41,883		(8,373	)		(5,534	)		62,195			36,349
Corporate and Other		151		14,324		(8,057	)		(8,889	)		(7,906	)		5,435

	December 31,
Segment Data	2008		2007
	(In thousands)
Total assets:
Transportation and Storage	$	4,969,336	$	4,550,822
Gathering and Processing		1,764,497		1,709,901
Distribution		1,177,124		1,020,460
Total segment assets		7,910,957		7,281,183
Corporate and other		86,950		116,730
Total consolidated assets	$	7,997,907	$	7,397,913

	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	434,004	$	591,153	$	244,821
Gathering and Processing		67,317		48,633		35,101
Distribution		41,125		44,769		47,954
Total segment expenditures for
long-lived assets		542,446		684,555		327,876
Corporate and other		9,345		4,173		4,798
Total consolidated expenditures for
long-lived assets (1)	$	551,791	$	688,728	$	332,674

_______________________

(1)	Includes net period changes in capital accruals totaling $(21.9) million, $71.8 million and $14.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Significant Customers and Credit Risk. The following tables provide summary information of significant customers for Panhandle and SUGS by applicable segment and on a consolidated basis for the periods presented. The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.

										Percent of Consolidated
	Percent of Transportation and									Company Total
	Storage Segment Revenues									Operating Revenues
	Years Ended December 31,									Years Ended December 31,
Customer	2008			2007			2006			2008			2007			2006

BG LNG Services		23	%		28	%		24	%		6	%		7	%		6	%
ProLiance		12			11			12			3			3			3
Ameren Corp		8			9			10			2			2			3
Other top 10 customers		18			17			19			5			4			5
Remaining customers		39			35			35			9			9			8
Total percentage		100	%		100	%		100	%		25	%		25	%		25	%

	Percent of Gathering and									Percent of Consolidated
	Processing Segment Revenues									Company Total Operating Revenues
	Years Ended December 31,									Years Ended December 31,
Customer	2008			2007			2006 (1)			2008			2007			2006 (1)

Louis Dreyfus Energy Services, LP		11	%		0	%		0	%		6	%		0	%		0	%
ConocoPhillips Company		8			16			22			4			8			10
BP Energy Company		8			6			11			4			3			5
Constellation Power Source		0			7			10			0			3			5
Other top 10 customers		33			34			22			16			16			10
Remaining customers		40			37			35			17			17			17
Total percentage		100	%		100	%		100	%		47	%		47	%		47	%

_______________________

(1)	Represents results from operations for the period subsequent to the March 1, 2006 acquisition.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

22. Accumulated Other Comprehensive Loss

The table below provides an overview of Comprehensive income (loss) for the periods indicated:

	Years Ended December 31,
Other Comprehensive Income (Loss)	2008			2007			2006
	(In thousands)
Net Earnings	$	295,151		$	228,711		$	64,131
Other Comprehensive Income (Loss) Adjustments:
Change in fair value of interest rate hedges, net of tax of $(7,816),
$(5,241) and $(745), respectively		(11,551	)		(10,041	)		(49	)
Reclassification of unrealized gain (loss) on interest rate hedges
into earnings, net of tax of $(2,287), $(13) and $608, respectively		(3,268	)		(4	)		967
Realized loss on interest rate hedges, net of tax of $(620),
$(1,488) and $0, respectively		(1,175	)		(2,366	)		-
Reversal of minimum pension liability related to disposition, net
of tax of $0, $0 and $16,004, respectively		-			-			26,331
Minimum pension liability adjustment, net of tax of $0, $0
and $4,128, respectively		-			-			6,803
Change in fair value of commodity hedges, net of tax of $13,549,
$(775) and $7,466, respectively		24,045			(1,279	)		12,360
Reclassification of unrealized gain on commodity hedges into
earnings, net of tax of $(2,466), $(2,425) and $(4,266), repectively		(4,375	)		(3,997	)		(7,084	)
Actuarial gain (loss) relating to pension and other postretirement benefits,
net of tax of $(23,763), $3,043 and $0, respectively		(41,784	)		5,521			-
Prior service cost relating to pension and other postretirement
benefit plan amendments, net of tax of $(3,691), $(1,987) and $0,
respectively		(5,677	)		(1,924	)		-
Reclassification of actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $2,034, $1,619 and $0, respectively		2,865			3,397			-
Total other comprehensive income (loss)		(40,920	)		(10,693	)		39,328
Total comprehensive income	$	254,231		$	218,018		$	103,459

The table below provides an overview of the components in Accumulated other comprehensive loss as of the periods indicated:

	December 31,
	2008			2007
	(In thousands)
Interest rate hedges, net	$	(30,717	)	$	(14,723	)
Commodity hedges, net		19,670			-
Benefit Plans:
Net actuarial loss and prior service costs, net - pensions		(44,664	)		(17,907	)
Net actuarial gain and prior service credit, net - other postretirement benefits		4,288			21,036
Total Accumulated other comprehensive loss, net of tax	$	(51,423	)	$	(11,594	)

See Note 14 – Benefits for a discussion related to the impact on Accumulated other comprehensive loss resulting from the adoption of the measurement provisions of Statement No. 158 effective December 31, 2008. Also see Note 14 – Benefits for information related to an amendment of Panhandle’s other postretirement benefit plans in March 2008, which resulted in a $6.6 million net of tax reduction in the net prior service credit included in Accumulated other comprehensive loss.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

23. Related Party Transactions

See Note 9 – Unconsolidated Investments – Dividends for information related to dividends received by the Company from its unconsolidated investments.

On November 5, 2004, SU Pipeline Management LP (Manager), a wholly-owned subsidiary of Southern Union, and PEPL entered into an Administrative Services Agreement (Management Agreement) with CCE Holdings. Pursuant to the Management Agreement, Manager provided administrative services to CCE Holdings and its subsidiaries from November 17, 2004 to December 1, 2006. The Management Agreement was terminated on December 1, 2006 following the redemption of Transwestern as more fully discussed in Note 3 – Acquisitions and Sales – CCE Holdings Transactions.

In 2006, Southern Union billed CCE Holdings $14 million for certain corporate costs provided under the Management Agreement prior to its termination on December 1, 2006 in conjunction with the transactions contemplated by the Redemption Agreement.

24. Stock-Based Compensation

Stock Options. Effective January 1, 2006, the Company adopted Statement No. 123R, using the modified prospective application method of transition, as defined in Statement No. 123R. Since the adoption of Statement No. 123R, the Company has recorded the grant date fair value of share-based payment arrangements, net of estimated forfeitures, as compensation expense using a straight-line basis over the awards’ requisite service period. Under the modified prospective application method, Statement No. 123R applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005. Compensation cost for the portion of awards for which the requisite service has not been rendered that are outstanding as of December 31, 2005 is recognized as the requisite service is rendered on or after January 1, 2006. Additionally, no transition adjustment is generally permitted for the deferred tax assets associated with outstanding equity instruments, as these deferred tax assets will be recorded as a credit to Premium on capital stock when realized. No cumulative effect of a change in accounting principle was recognized upon adoption of Statement No. 123R.

The Company previously disclosed the fair value of stock options granted and the assumptions used in determining fair value pursuant to Statement No. 123, “Accounting for Stock-Based Compensation”. The Company historically used a Black-Scholes valuation model to determine the fair value of stock options granted. Stock options (either incentive stock options or non-qualified options) and SARs generally vest over a three-, four- or five-year period from the date of grant and expire ten years after the date of grant. The adoption of Statement No. 123R in 2006 reduced Operating Income, Earnings from continuing operations before income taxes and Net earnings by $2.4 million, $2.4 million and $1.9 million, respectively, or $0.02 per basic share and $0.02 per diluted share for the year ended December 31, 2006.

The fair value of each option 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 the Company’s stock. To the extent that volatility of the Company’s stock price increases in the future, the estimates of the fair value of options 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 options 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 options granted in the future. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Years ended December 31,
	2008		2007		2006
Expected volatility		30.57%	30.11% to 32.12%			32.90%
Expected dividend yield		2.19%		2.10%		1.43%
Risk-free interest rate		1.71%	3.70% to 3.89%			4.69%
Expected life	6 years		6.00 to 7.50 years		6.00 years

The following table provides information on stock options granted, exercised, canceled, outstanding and exercisable under the Second Amended 2003 Plan and the 1992 Plan for the years ended December 31, 2008, 2007 and 2006:

	Second Amended 2003 Plan					1992 Plan
				Weighted					Weighted
	Shares			Average		Shares			Average
	Under			Exercise		Under			Exercise
	Option			Price		Option			Price

Outstanding December 31, 2005		1,289,510		$	20.62		1,259,624		$	13.15
Granted		-			-		-			-
Exercised		(121,137	)		17.31		(521,289	)		13.92
Forfeited		(157,894	)		18.23		(23,139	)		12.92
Outstanding December 31, 2006		1,010,479		$	21.39		715,196		$	12.60
Granted		717,098			28.48		-			-
Exercised		(98,027	)		19.32		(176,515	)		10.51
Forfeited		(97,875	)		22.95		(1,979	)		13.03
Outstanding December 31, 2007		1,531,675		$	24.74		536,702		$	13.28
Granted		792,934			12.55		-			-
Exercised		(12,725	)		16.83		(224,593	)		12.71
Forfeited		(773	)		16.83		-			-
Outstanding December 31, 2008		2,311,111		$	20.61		312,109		$	13.70

Exercisable December 31, 2006		533,363			22.38		715,196			12.60
Exercisable December 31, 2007		565,560			22.25		536,702			13.28
Exercisable December 31, 2008		769,216			22.66		312,109			13.70

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information on SARs granted, exercised, canceled, outstanding and exercisable under the Second Amended 2003 Plan for the years ended December 31, 2008, 2007 and 2006:

	Second Amended 2003 Plan
			Weighted Average
	SARs		Exercise Price

Outstanding December 31, 2005		-	$	-
Granted		133,610		28.07
Outstanding December 31, 2006		133,610	$	28.07
Granted		282,163		28.48
Outstanding December 31, 2007		415,773	$	28.35
Granted		784,779		12.55
Outstanding December 31, 2008		1,200,552	$	18.02

Exercisable December 31, 2006		-		-
Exercisable December 31, 2007		44,533		28.07
Exercisable December 31, 2008		183,115		28.28

No SARs were exercised or forfeited during the 2006 through 2008 annual periods.

The SARs vest in three equal increments annually on their grant date anniversary. 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 in excess of the exercise price for each SAR on the applicable vesting date.

The following table summarizes information about stock options outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2008:

	Options Outstanding					Options Exercisable
			Weighted Average	Weighted				Weighted
			Remaining	Average				Average
Range of Exercise Prices	Number of Options		Contractual Life	Exercise Price		Number of Options		Exercise Price

Second Amended 2003 Plan:
12.55 - 15.00		792,934	9.95 years	$	12.55		-	$	-
15.01 - 20.00		228,637	5.10 years		16.83		161,240		16.83
20.01 - 25.00		572,442	6.69 years		23.41		516,100		23.45
25.01 - 28.48		717,098	8.96 years		28.48		91,876		28.48
		2,311,111	8.36 years	$	20.61		769,216	$	22.66

1992 Plan:
13.50 - 14.66		312,109	1.18 years	$	13.70		312,109	$	13.70
		312,109	1.18 years	$	13.70		312,109	$	13.70

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about SARs outstanding under the Second Amended 2003 Plan at December 31, 2008:

	SARs Outstanding					SARs Exercisable
			Weighted Average	Weighted				Weighted
			Remaining	Average				Average
Range of Exercise Prices	Number of SARs		Contractual Life	Exercise Price		Number of SARs		Exercise Price

12.55 - 15.00		784,779	9.95 years	$	12.55		-	$	-
25.01 - 28.48		415,773	8.65 years		28.35		183,115		28.28
		1,200,552	9.50 years	$	18.02		183,115	$	28.28

The weighted average remaining contractual life of options and SARs outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2008 was 8.75 and 1.18 years, respectively. The weighted average remaining contractual life of options and SARs exercisable under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2008 was 6.98 and 1.18 years, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2008 was $773,000 and nil, respectively.

As of December 31, 2008, there was $12 million of total unrecognized compensation cost related to non-vested stock options and SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 2.8 years. The total fair value of options and SARs vested as of December 31, 2008 was $9.7 million. Compensation expense recognized related to stock options and SARs totaled $3.9 million ($2.7 million, net of tax), $1.5 million ($1.2 million, net of tax) and $2.4 million ($1.9 million, net of tax) for the years ended December 31, 2008, 2007 and 2006, respectively. Cash received from the exercise of stock options was $3.1 million for the year ended December 31, 2008.

The intrinsic value of options exercised during the year ended December 31, 2008 was approximately $2.4 million. The Company realized an additional tax benefit of approximately $941,000 for the excess amount of deductions related to stock options over the historical book compensation expense multiplied by the statutory tax rate in effect, which has been reported as an increase in financing cash flows in the Consolidated Statement of Cash Flows.

Restricted Stock. The Company’s Second Amended 2003 Plan also provides for grants of restricted stock equity units and restricted stock liability units. The Company settles restricted stock equity units with shares of its common stock and restricted stock liability units with cash. The restrictions associated with a grant of restricted stock equity units under the Second Amended 2003 Plan generally expire equally over a period of three years or in total after five years. Restrictions on certain grants made to non-employee directors and senior executives of the Company expire over a shorter time period, in certain cases less than one year, and may be subject to accelerated expiration over a shorter term if certain criteria are met. The restrictions associated with a grant of restricted stock liability units expire equally over a period of three years and are payable in cash at the vesting date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of the activity of non-vested restricted stock equity awards as of December 31, 2008 is presented below:

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

Nonvested restricted shares at December 31, 2005		209,903		$	24.15
Granted		137,036			26.50
Vested		(146,335	)		24.17
Forfeited		(31,820	)		24.44
Nonvested restricted shares at December 31, 2006		168,784		$	25.98
Granted		156,044			28.99
Vested		(111,322	)		26.67
Forfeited		(12,336	)		24.96
Nonvested restricted shares at December 31, 2007		201,170		$	28.00
Granted		252,066			14.99
Vested		(90,051	)		28.10
Forfeited		-			-
Nonvested restricted shares at December 31, 2008		363,185		$	18.94

A summary of the activity of nonvested restricted stock liability unit awards as of December 31, 2008 is presented below:

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

Nonvested restricted units at December 31, 2005		-		$	-
Granted		108,869			28.07
Vested		-			-
Forfeited		-			-
Nonvested restricted units at December 31, 2006		108,869		$	28.07
Granted		143,460			28.49
Vested		(36,283	)		28.07
Forfeited		(2,744	)		28.07
Nonvested restricted units at December 31, 2007		213,302		$	28.35
Granted		418,583			13.88
Vested		(82,431	)		28.31
Forfeited		(815	)		28.48
Nonvested restricted units at December 31, 2008		548,639		$	17.31

As of December 31, 2008, there was $12.1 million of total unrecognized compensation cost related to non-expired, restricted stock equity units and 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 2.8 years. The total fair value of restricted stock equity and liability units that vested during the year ended December 31, 2008 was $3.6 million. Compensation expense recognized related to restricted stock equity and liability units totaled $3.7 million ($2.3 million, net of tax) for the year ended December 31, 2008, $3 million ($1.9 million, net of tax) for the year ended December 31, 2007, and $4.3 million ($2.7 million, net of tax) for the year ended December 31, 2006, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company settled the restricted stock liability awards vesting in 2008 and 2007 with cash payments of $1.1 million and $1.1 million, respectively.

25. Fair Value Measurement

The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2008.

	Fair Value			Fair Value Measurements at December 31, 2008
	as of			Using Fair Value Hierarchy
	December 31, 2008			Level 1		Level 2		Level 3
	(In thousands)
Assets:
Cash equivalents (money
market investments)	$	590		$	590	$	-	$	-
Commodity derivatives		91,423	(1)		-		90,459		964
Long-term investments		729			729		-		-
Total	$	92,742		$	1,319	$	90,459	$	964

Liabilities:
Commodity derivatives	$	93,692		$	-	$	93,786	$	(94	)
Interest-rate derivatives		43,630			-		-		43,630
Total	$	137,322		$	-	$	93,786	$	43,536

___________________

(1)	The Company’s commodity derivative asset balance is primarily associated with two separate counterparties, each individually comprising $68.9 million and $20.1 million of the related fair value as of December 31, 2008.

The following table provides a reconciliation of the change in the Company’s Level 3 assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the periods indicated.

	Level 3 Financial Assets and Liabilities
	Assets			Liabilities
	Commodity			Commodity			Interest-rate
	Derivatives			Derivatives			Derivatives
	(In thousands)

Balance at January 1, 2008	$	1,320		$	(5,404	)	$	17,121
Reclassification between assets and liabilities		4,084			4,084			-
Total gains or losses (realized and unrealized):
Included in operating revenues (1)		52,108			683			-
Included in other comprehensive income		37,594			-			34,019
Purchases and settlements, net		(3,683	)		543			(7,510	)
Transfers out of Level 3 (2)		(90,459	)		-			-
Balance at December 31, 2008	$	964		$	(94	)	$	43,630

___________________

(1)

The amount included in operating revenues for the year ended December 31, 2008 that is attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities held at December 31, 2008 were gains of $52.1 million and $100,000, respectively.

(2)	Effective December 31, 2008, the fair value of the Company’s natural gas and NGL processing spread swap derivatives were determined using published NYMEX observable inputs, resulting in a transfer of these commodity derivatives to Level 2.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gathering and Processing Segment Derivative Financial Instruments. The following table summarizes SUGS' principal commodity derivative instruments as of December 31, 2008 (all instruments are settled monthly), which were developed based upon operating conditions and expected equity (Company-owned) natural gas and NGL sales volumes.

Instrument Type	Index	Average Fixed Price (per MMBtu)		Volumes (MMBtu/d) (3)		Fair Value of Assets
						(In thousands)
Natural Gas - Cash Flow Hedges (1)
Fixed-rate swap	Gas Daily - Waha	$	9.49		11,050	$	16,991
Fixed-rate swap	Gas Daily - El Paso Permian	$	9.49		8,950		13,762
		Total			20,000	$	30,753

Processing Spread - Economic Hedges (2)
Fixed-rate swap	Gas Daily - Waha (natural gas)	$	7.40		16,575	$	32,988
	OPIS - Mt. Belvieu (NGL)
Fixed-rate swap	Gas Daily - El Paso Permian (natural gas)	$	7.40		13,425		26,718
	OPIS - Mt. Belvieu (NGL)
		Total			30,000	$	59,706

__________________

(1)

(2)

The Company’s processing spread swap arrangements, which hedge the pricing differential between NGL volumes and natural gas volumes, are treated as economic hedges. The ratio of NGL product sold per MMBtu is approximately: 33 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and16 percent natural gasoline. The change in fair value is reported in current-period earnings.

(3)	All volumes are applicable to the period January 1, 2009 to December 31, 2009.

There were no up-front costs associated with the derivative instruments entered into in 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

26. Quarterly Operations (Unaudited)

The following table presents the operating results for each quarter of the year ended December 31, 2008:

	Quarters Ended
	March 31		June 30		September 30		December 31
	(In thousands, except per share amounts)

Operating revenues	$	952,698	$	733,055	$	657,283	$	727,118
Operating income		153,555		90,277		97,280		188,867
Earnings from continuing operations		82,908		42,910		46,776		122,557
Net earnings available for common
stockholders		78,567		37,479		42,476		120,890
Diluted net earnings per share
available for common stockholders:
Continuing operations	$	0.64	$	0.30	$	0.34	$	0.97
Available for common stockholders	$	0.64	$	0.30	$	0.34	$	0.97

The following table presents the operating results for each quarter of the year ended December 31, 2007:

	Quarters Ended
	March 31		June 30		September 30		December 31
	(In thousands, except per share amounts)

Operating revenues	$	780,232	$	588,049	$	525,473	$	722,911
Operating income		129,594		87,400		96,980		113,111
Earnings from continuing operations		78,721		50,975		45,283		53,732
Net earnings available for common
stockholders		74,380		46,634		40,941		49,391
Diluted net earnings per share
available for common stockholders:
Continuing operations	$	0.62	$	0.39	$	0.34	$	0.41
Available for common stockholders	$	0.62	$	0.39	$	0.34	$	0.41

The sum of EPS by quarter in the above tables may not equal the net earnings per common and common share equivalents for the applicable year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.

F - 70

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

of Southern Union Company:

In our opinion, the accompanying consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2009

F - 71

Citrus Corp. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2008, 2007 and 2006

with Report of Independent Registered Public Accounting Firm

Citrus Corp. and Subsidiaries
Consolidated Financial Statements

Years ended December 31, 2008, 2007 and 2006



TABLE OF CONTENTS

		Page

Report of Independent Registered Public Accounting Firm		2

Audited Consolidated Financial Statements
Consolidated Balance Sheets		3
Consolidated Statements of Income		4
Consolidated Statements of Shareholders' Equity		5
Consolidated Statements of Comprehensive Income		5
Consolidated Statements of Cash Flows		6
Notes to Consolidated Financial Statements		7 - 29

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the "Company") at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 26, 2009

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS




	December 31,			December 31,
	2008			2007

	(In thousands)
ASSETS

Current Assets
Cash and cash equivalents	$	20,032		$	3,572
Accounts receivable, billed and unbilled,
less allowances of $18 and $18, respectively		40,308			39,350
Materials and supplies		14,692			12,745
Exchange gas receivable		1,519			1,729
Other		2,073			2,248
Total Current Assets		78,624			59,644

Property, Plant and Equipment
Plant in service		4,499,383			4,265,844
Construction work in progress		405,585			150,742
		4,904,968			4,416,586
Less accumulated depreciation and amortization		1,478,890			1,401,638
Property, Plant and Equipment, Net		3,426,078			3,014,948

Other Assets
Unamortized debt expense		4,048			4,221
Regulatory assets		22,241			19,207
Other		6,914			10,838
Total Other Assets		33,203			34,266

Total Assets	$	3,537,905		$	3,108,858


LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities
Current portion of long-term debt	$	51,500		$	44,000
Accounts payable - trade and other		33,539			33,422
Accounts payable - affiliated companies		8,533			8,416
Accrued interest		20,918			14,251
Accrued income taxes		-			7,599
Accrued taxes, other than income		5,217			5,437
Exchange gas payable		20,752			22,547
Capital accruals		14,377			22,636
Dividends payable		-			42,600
Other		7,506			7,600
Total Current Liabilities		162,342			208,508

Deferred Credits
Deferred income taxes, net		802,006			763,364
Regulatory liabilities		9,206			14,842
Other		16,318			9,202
Total Deferred Credits		827,530			787,408

Long-Term Debt		1,327,020			909,810
Commitments and contingencies (Note 14)

Stockholders' Equity
Common stock, $1 par value; 1,000 shares authorized, issued and outstanding		1			1
Additional paid-in capital		634,271			634,271
Accumulated other comprehensive loss		(5,246	)		(7,885	)
Retained earnings		591,987			576,745
Total Stockholders' Equity		1,221,013			1,203,132

Total Liabilities and Stockholders' Equity	$	3,537,905		$	3,108,858

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

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME






	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
	(In thousands)


Operating Revenues
Transportation of natural gas	$	504,819		$	495,513		$	485,189

Total Operating Revenues		504,819			495,513			485,189

Operating Expenses
Operations and maintenance		89,314			82,058			77,941
Depreciation and amortization		105,849			100,634			98,653
Taxes, other than income taxes		34,411			29,618			34,765

Total Operating Expenses		229,574			212,310			211,359


Operating Income		275,245			283,203			273,830

Other Income (Expenses)
Interest expense and related charges, net		(82,830	)		(73,871	)		(76,428	)
Other, net		8,008			39,984			4,633

Total Other Income (Expenses), net		(74,822	)		(33,887	)		(71,795	)

Income Before Income Taxes		200,423			249,316			202,035

Federal and State Income Tax Expense		73,481			92,224			75,960

Net Income	$	126,942		$	157,092		$	126,075

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

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY



	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
	(In thousands)

Common Stock
Balance, beginning and end of period	$	1		$	1		$	1

Additional Paid-in Capital
Balance, beginning and end of period		634,271			634,271			634,271

Accumulated Other Comprehensive Loss
Balance, beginning of period		(7,885	)		(10,524	)		(13,162	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639			2,639			2,638
Balance, end of period		(5,246	)		(7,885	)		(10,524	)

Retained Earnings
Balance, beginning of period		576,745			669,353			668,678
Net income		126,942			157,092			126,075
Dividends		(111,700	)		(249,700	)		(125,400	)
Balance, end of period		591,987			576,745			669,353

Total Stockholders' Equity	$	1,221,013		$	1,203,132		$	1,293,101



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME




	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2008			2007			2006

	(In thousands)

Net income	$	126,942		$	157,092		$	126,075
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639			2,639			2,638
Total Comprehensive Income	$	129,581		$	159,731		$	128,713

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

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2008			2007			2006

	(In thousands)
Cash flows provided by operating activities
Net income	$	126,942		$	157,092		$	126,075
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		105,849			100,634			98,653
Deferred income taxes		37,772			(12,277	)		18,629
Allowance for funds used during construction		(7,093	)		(4,683	)		(1,630	)
Other		3,842			5,411			7,487
Changes in operating assets and liabilities:
Other current assets and liabilities		(5,051	)		13,375			15,067
Other long-term assets and liabilities		(680	)		74,668			(24,627	)
Net cash provided by operating activities		261,581			334,220			239,654

Cash flows used in investing activities
Capital expenditures		(521,435	)		(175,370	)		(106,023	)
Allowance for funds used during construction		7,093			4,683			1,630
Net cash used in investing activities		(514,342	)		(170,687	)		(104,393	)

Cash flows provided by (used in) financing activities
Dividends paid		(154,300	)		(207,100	)		(125,400	)
Net (payments) borrowings on the revolving credit facilities		(31,817	)		76,400			(2,000	)
Payments on long-term debt		(44,000	)		(44,000	)		(14,000	)
Issuance of long-term debt		500,000			-			-
Issuance costs of debt		(662	)		(528	)		-
Net cash provided by (used in) financing activities		269,221			(175,228	)		(141,400	)

Net increase (decrease) in cash and cash equivalents		16,460			(11,695	)		(6,139	)

Cash and cash equivalents, beginning of period		3,572			15,267			21,406

Cash and cash equivalents, end of period	$	20,032		$	3,572		$	15,267

Supplemental disclosure of cash flow information

Interest paid (net of amounts capitalized)	$	75,194		$	72,439		$	72,067
Income tax paid	$	43,570		$	103,589		$	56,814

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

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)	Corporate Structure

Citrus Corp. (Citrus), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2008, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry) an indirect subsidiary of Southern Union Company (Southern Union). In November 2007, Southern Natural Gas Company (Southern), whose parent is El Paso, distributed EPCH to El Paso. On March 3, 2008, Trading, which no longer had any ongoing activity, was authorized for dissolution.

Florida Gas, an interstate natural gas pipeline extending from South Texas to South Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

(2)	Significant Accounting Policies

Basis of Presentation – The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

Regulatory Accounting – Florida Gas’ accounting policies generally conform to Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Type of Regulation” (Statement No. 71) and FASB Statement No. 92 “Regulated Enterprises – Accounting for Phase-in Plans” (Statement No 92). Accordingly, under Statement No. 71, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities. Statement No. 71 was amended by FASB Statement No. 92 which prohibits certain allowable regulatory deferrals of phase-in costs under GAAP. As a consequence, certain phase-in costs of Florida Gas’ Phase III expansion are not deferred for GAAP, but are deferred for future recovery for ratemaking purposes.

Revenue Recognition – Revenues consist primarily of fees earned from gas transportation services. Reservation revenues are recognized monthly based on contracted rates and capacity reserved by the customers. For interruptible or volumetric based services, commodity revenues are recorded upon the delivery of natural gas to the agreed upon delivery point. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a rate specified in the contract.

Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order. Florida Gas establishes reserves for such potential refunds, as appropriate. There were no reserves for potential rate refund at December 31, 2008 and 2007, respectively.

Derivative Instruments and Hedging Activities – The Company follows FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (Statement No. 133), to account for derivative and hedging activities. All derivatives are recognized on the Consolidated Balance Sheets 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 Loss until the related hedge items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. Upon termination of a cash flow hedge, the resulting gain or loss is amortized to earnings through the maturity date of the hedged forecasted transactions. 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 mathematical models using current and historical data. As of December 31, 2008 and 2007, the Company does not have any hedges in place; it is only amortizing previously terminated cash flow hedges.

Property, Plant and Equipment – Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. Florida Gas capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and cost of funds, both interest and an equity return component (see third following paragraph). Costs of replacements and renewals of units of property are capitalized. The original cost of units of property retired are charged to accumulated depreciation, net of salvage and removal costs. Florida Gas charges to maintenance expense the costs of repairs and renewal of items determined to be less than units of property.

The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system.

Florida Gas has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.75 percent, 2.77 percent and 2.78 percent for the years ended December 31, 2008, 2007 and 2006, respectively.

The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of capital invested in construction work-in-progress. AFUDC has been segregated into two component parts – borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction, including related amounts to gross up equity AFUDC to a before tax basis, totaled $15.6 million, $10.3 million and $3.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. AFUDC-borrowed funds are included in Interest Expense (as a reduction in Interest Expense) and AFUDC-equity funds are included in Other Income in the accompanying statements of income.

Asset Retirement Obligations – The Company applies the provisions of FASB Statement No. 143, “Accounting for Asset Retirement Obligations (ARO)” (Statement No. 143) to record a liability for the estimated removal costs of assets where there is a legal obligation associated with removal. Under this standard, the liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates. An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) issued by the FASB in March 2005 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation (ARO) when incurred, if the fair value of the liability can be reasonably estimated. FIN No. 47 provides guidance for assessing whether sufficient information is available to record an estimate. This interpretation was effective for the Company beginning on December 31, 2005. Upon adoption of FIN No. 47, Florida Gas recorded an increase in plant in service and a liability for an ARO of $0.5 million. This new asset and liability related to obligations associated with the removal and disposal of asbestos and asbestos containing materials on Florida Gas’ pipeline system. In 2008 Florida Gas recorded a $1.3 million ARO liability for certain pipeline abandonment costs. At December 31, 2008, the ARO assets had a net book value of $1.8 million.

The table below provides a reconciliation of the carrying amount of the ARO liability for the period indicated:

	Year Ended December 31, 2008			Year Ended December 31, 2007			Year Ended December 31, 2006
	(In thousands)

Beginning balance	$	471		$	481		$	493
Incurred		1,358			-			-
Settled		(37	)		(37	)		(36	)
Accretion Expense		27			27			24
Ending balance (Note 11)	$	1,819		$	471		$	481

Asset Impairment – The Company applies the provisions of FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No. 144), to account for impairments on long-lived assets. Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying value. The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

Gas Imbalances – Gas imbalances occur as a result of differences in volumes of gas received and delivered by a pipeline system. These imbalances due to or from shippers and operators are valued at an appropriate index price. Imbalances are settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and generally do not impact earnings. Gas imbalance receivables from customers are recorded in Exchange gas receivable and imbalance payables are recorded in Exchange gas payable in the accompanying Consolidated Balance Sheets.

Environmental Expenditures (Note 12) – Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future 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 cost can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

Cash and Cash Equivalents – All liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

Materials and Supplies – Materials and supplies are valued at the lower of cost or market value. Materials transferred out of warehouses are priced at average cost. Materials and supplies include spare parts which are critical to the pipeline system operations and are valued at the lower of cost or market.

Fuel Tracker – A liability is recorded for net volumes of gas owed to customers collectively. Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions an asset is recorded. Gas owed to or from customers is valued at market. Changes in the balances have no effect on the consolidated income of the Company. Fuel due from customers is recorded as Regulatory assets and over-retained fuel due to customers is recorded in Regulatory liabilities in the accompanying Consolidated Balance Sheets.

Income Taxes (Note 4) – Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, “Accounting for Income Taxes” (Statement No. 109). 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 bases. 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 income 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.

Accounts Receivable – The Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability. Unrecovered accounts receivable charged against the allowance for doubtful accounts were nil, $0.3 million and nil in the years ended December 31, 2008, 2007 and 2006, respectively.

Other Postretirement Benefits – Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement No. 158). Statement No. 158 does not amend the expense recognition provisions of Statements No. 87, 88 and 106, but requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated Other Comprehensive Loss in stockholders’ equity.

The Company accounted for the measurement of its defined benefit postretirement plans under Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (Statement No. 106). Under Statement No. 106, changes in the funded status were not immediately recognized; but rather were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its defined postretirement benefit plan. The Company applied the provisions of Statement No. 71 and as such recognized net periodic benefit expense to the extent of amounts recorded in rates with any difference recorded as a regulatory asset or liability. Unrecognized prior service costs (benefits) and gain and/or loss are not recorded as change to Accumulated Other Comprehensive Loss, but rather as a regulatory asset or regulatory liability, reflecting amounts due from or to customers, respectively. See Note 5 – Benefits for additional information.

Fair Value Measurement - Issued by the FASB in September 2006, FASB Statement No. 157 “Fair Value Measurement” (Statement No. 157) defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB released a FASB Staff Position, FSP FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which delays the effective date of this Statement for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008. The Company’s major categories of non-financial assets and non-financial liabilities that are recognized or disclosed at fair value for which, in accordance with FSP FAS 157-2, the Company has not applied the provisions of Statement No. 157 as of January 1, 2008 are (i) fair value calculations associated with annual or periodic impairment tests and (ii) asset retirement obligations measured at fair value upon initial recognition or upon certain remeasurement events under FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (Statement No. 143). The partial adoption on January 1, 2008 of Statement No. 157 for financial assets and liabilities did not have a material impact on the Company’s consolidated financial statements. In October 2008, the FASB issued FASB Staff Position FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active” (FSP FAS 157-3). FSP FAS 157-3 provides clarifying guidance with respect to the application of Statement No. 157 in determining the fair value of a financial asset when the market for that asset is not active. FSP FAS 157-3 was effective upon its issuance. The application of FSP FAS 157-3 did not have a material impact on the Company’s consolidated financial statements.

As defined in Statement No. 157, 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 non-performance 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 possibilities 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. Statement No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value 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 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

The Company’s Level 3 instruments include interest-rate swap derivatives that are valued using an income approach where at least one significant assumption or input to the underlying pricing model, discounted cash flow methodology or similar technique is unobservable – i.e. interest rate swap valuations include composite yield curves provided by the bank counterparty. The financial liabilities that the Company has categorized in Level 3 may later be reclassified to Level 2 when the Company is able to obtain additional observable market data to corroborate the unobservable inputs to models used to measure the fair value of these liabilities.

At December 31, 2008, the Company had no financial assets measured at fair value on a recurring basis in accordance with Statement No. 157.

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

New Accounting Principles

Accounting Principles Recently Adopted.

FASB Statement No. 157, “Fair Value Measurements”. See Note 2 – Significant Accounting Policies – Fair Value Measurement for information related to this Statement which was partially adopted during 2008.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”. Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financial statements.

Accounting Principles Not Yet Adopted.

FASB Statement No. 141 (revised), “Business Combinations”. Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration of a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

FASB Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”. Issued by the FASB in March 2008, this statement requires disclosure of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related items affected an entity’s financial position, financial performance and cash flows. The Statement is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109”. Issued by the FASB in June 2006, FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, for public enterprises and December 15, 2008, for nonpublic enterprises, such as Citrus. The Company has determined the implementation of this Statement will not have a material impact on its consolidated financial statements.

FSP No. FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48”. Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.

(3)	Long Term Debt

The table below sets forth the long-term debt of the Company as of the dates indicated:

	Years	December 31, 2008					December 31, 2007
	Due	Book Value			Fair Value		Book Value			Fair Value
		(In thousands)
Citrus
8.490% Senior Notes	2007-2009	$	30,000		$	31,439	$	60,000		$	63,572
Revolving Credit Agreement Citrus	2012		40,643			37,729		62,400			62,400
Construction and Term Loan Agreement	2033		500,000			500,000		-			-
FGT
9.750% Senior B Notes	1999-2008		-			-		6,500			6,736
10.110% Senior C Notes	2009-2013		70,000			77,010		70,000			82,282
9.190% Senior Notes	2005-2024		120,000			127,945		127,500			158,843
7.625% Senior Notes	2010		325,000			341,574		325,000			353,352
7.000% Senior Notes	2012		250,000			261,891		250,000			277,281
Revolving Credit Agreement FGT	2012		43,940			40,790		54,000			54,000
Total debt outstanding		$	1,379,583		$	1,418,378	$	955,400		$	1,058,466
Current portion of long-term debt			(51,500	)				(44,000	)
Unamortized Debt Discount and Swap Loss			(1,063	)				(1,590	)
Total long-term debt		$	1,327,020				$	909,810

Annual maturities of long-term debt outstanding as of the date indicated were as follows:

	December 31,
	2008
Year	(In thousands)

2009	$	51,500
2010		346,500
2011		21,500
2012		356,083
2013		21,500
Thereafter		582,500
	$	1,379,583

On August 13, 2004 Florida Gas entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50 million, subsequently increased by $125 million to $175 million. The 2004 Florida Gas Revolver terminated in August 2007 and was replaced by a new revolving credit agreement at Florida Gas in the amount of $300 million (“2007 Florida Gas Revolver”), which will mature on August 16, 2012. The 2007 Florida Gas Revolver requires interest based on LIBOR plus a margin tied to the debt rating of the Company’s senior unsecured debt, currently 0.28 percent, and has a facility fee of 0.07 percent. As of December 31, 2008, the amount drawn under the 2007 Florida Gas Revolver was $43.9 million with a weighted average interest rate of 1.26 percent (based on LIBOR plus 0.28 percent) and has a facility fee of 0.07 percent.

Also on August 16, 2007, Citrus entered into a revolving credit facility in the amount of $200 million (“2007 Citrus Revolver”), which will mature on August 16, 2012. This facility will enable Citrus to meet its funding needs and repay its debt maturities. As of December 31, 2008, the amount drawn under the 2007 Citrus Revolver was $40.6 million with a weighted average interest rate of 1.93 percent (based on LIBOR plus 0.28 percent), and has a facility fee of 0.07 percent.

The lenders of the 2007 Florida Gas Revolver and 2007 Citrus Revolver are a group of banks, including Lehman Brothers Bank FSB (Lehman FSB), a subsidiary of Lehman Brothers Holdings Inc. (Lehman). Lehman FSB has a total $35 million credit commitment in the Company’s total of $500 million of capacity under the 2007 Florida Gas Revolver and 2007 Citrus Revolver. Lehman and some of its subsidiaries, but not including Lehman FSB, filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy code on September 15, 2008. However, Lehman FSB has been electing not to fund its pro rata share of the borrowing as required under its commitment to the facility since September 16, 2008. As a result, the Company does not currently expect that Lehman FSB will fund its pro rata share of any future borrowing requests. The Company does not expect this 7 percent effective reduction in available capacity under the revolver to significantly impact liquidity or the Company’s business operations. The Company’s available capacity under its revolvers, excluding Lehman FSB’s portion, at December 31, 2008 was $380 million.

The estimated fair value of the 2007 Florida Gas Revolver and 2007 Citrus Revolver at December 31, 2008 approximates 92.83 percent of their carrying values. Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2008 and 2007 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Construction Loan Agreement) with a wholly owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus will primarily invest the proceeds of this loan into Florida Gas in order to finance a portion of the Phase VIII Expansion (Note 14). On August 6, 2008, the parties amended the Construction Loan Agreement to accelerate the funding date to October 1, 2008. On October 1, 2008, Citrus borrowed the full $500 million available under the Construction Loan Agreement. At December 31, 2008 the effective interest rate applicable to the construction loan was 8.77 percent which was comprised of LIBOR of 3.42 percent plus a margin of 5.35 percent.

On or before the Phase VIII Expansion in-service date, the Construction Loan Agreement will convert to an amortizing 20-year term loan with a $300 million balloon payment at maturity. The loan requires semi-annual payments of principal beginning five years and six months after the conversion to a term loan. The Construction Loan Agreement provides for interest on the outstanding principal amount at the rate of three-month LIBOR plus 535 basis points prior to conversion to a term loan and at the twenty-year treasury rate plus 535 basis points after conversion to a term loan. The loan is not guaranteed by Florida Gas and does not include a prepayment option. The Construction Loan Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas. The Construction Loan Agreement requires any dividends paid by Citrus after October 1, 2008 and prior to Phase VIII Expansion in-service date to be re-contributed by the partners within twelve months of any such dividends.

The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants. Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or Florida Gas on any of their borrowed money obligations in excess of certain thresholds, which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated.

At December 31, 2008 the Company, based on the currently most restrictive debt covenant requirements, was subject to $523.7 million limitation on additional restricted payments including dividends and loans to affiliates. The Company is also subject, under the currently most restrictive debt covenant of a maximum 65 percent of consolidated funded debt to total capitalization, to a limitation of $889 million of total additional indebtedness at December 31, 2008.

(4)	Income Taxes

Total income tax expense for the periods indicated was as follows:

	Year Ended December 31, 2008		Year Ended December 31, 2007			Year Ended December 31, 2006
Current Tax Provision	(In thousands)
Federal	$	34,899	$	99,083		$	52,135
State		810		5,418			5,196
		35,709		104,501			57,331

Deferred Tax Provision
Federal		33,051		(14,531	)		15,863
State		4,721		2,254			2,766
		37,772		(12,277	)		18,629
Total income tax expense	$	73,481	$	92,224		$	75,960

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company’s effective tax rate for the periods indicated are as follows:

	Year Ended December 31, 2008			Year Ended December 31, 2007			Year Ended December 31, 2006
	(In thousands)

Statutory federal income tax provision	$	70,148		$	87,261		$	70,712
State income taxes, net of federal benefit		3,595			4,986			5,176
Other		(262	)		(23	)		72
Income tax expense	$	73,481		$	92,224		$	75,960

Effective Tax Rate		36.7	%		37.0	%		37.6	%

The Company files a consolidated federal income tax return separate from that of its stockholders.

The principal components of the Company's net deferred income tax liabilities as of the dates indicated were as follows:

	December 31, 2008		December 31, 2007
	(In thousands)
Deferred income tax asset
Regulatory and other reserves	$	4,403	$	5,554
		4,403		5,554

Deferred income tax liabilities
Depreciation and amortization		796,339		759,576
Deferred charges and other assets		3,807		4,717
Other		6,263		4,625
		806,409		768,918
Net deferred income tax liabilities	$	802,006	$	763,364

(5)	Employee Benefit Plans

All employees of Florida Gas are eligible to participate in the Florida Gas Transmission Company 401(k) Savings Plan (the Plan). Employees may contribute up to 50 percent of pre-tax compensation, subject to IRS limitations. This Plan allows additional “catch-up” contributions by participants over age 50, and allows Florida Gas to make discretionary profit sharing contributions for the benefit of all participants. Florida Gas matched 50 percent of participant contributions under this Plan up to a maximum of four percent of eligible compensation through December 31, 2007. The matching was increased effective January 1, 2008 to 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Plan. Participants vest in such matching and any profit sharing contributions at the rate of 20 percent per year, except that participants with five years of service at the date of adoption of the Plan, March 1, 2005, were immediately vested. Administrative costs of the Plan and certain asset management fees are paid from Plan assets. Florida Gas’ expensed its contribution of $0.7 million, $0.3 million and $0.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

	As of December 31, 2008 Measurement Date			As of December 31, 2007 Measurement Date
	(In thousands)
Change in Benefit Obligation
Benefit obligation at the beginning of period	$	5,302		$	5,795
Service cost		165			37
Interest cost		545			296
Amendments (1)		9,892			-
Actuarial gain		662			(320	)
Retiree premiums		565			415
Benefits paid		(1,121	)		(1,029	)
CMS Medicare Part D subsidies received		-			108
Benefit obligation at end of year		16,010			5,302

Change in Plan Assets
Fair value of plan assets at the beginning of period		8,599			8,497
Return on plan assets		(1,132	)		336
Employer contributions		1,332			380
Retiree premiums		565			415
Benefits paid		(1,121	)		(1,029	)
Fair value of plan assets at end of year (2)		8,243			8,599

Funded Status
Funded status at the end of the year	$	(7,767	)	$	3,297

Amount recognized in the Consolidated Balance Sheets
Other assets - other (Note 10)	$	-		$	3,297
Regulatory assets (Note 10)		7,675			-
Regulatory liability (Note 11)		-			(3,390	)
Deferred credits - other (Note 11)		(7,767	)		-
Net asset (liability) recognized	$	(92	)	$	(93	)

	One Percentage Point Increase		One Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	45	$	(46	)
Effect on postretirement benefit obligation	$	1,331	$	(1,414	)

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D		Net
	(In thousands)

2009	$	653	$	96	$	557
2010		743		99		644
2011		837		108		729
2012		920		119		801
2013		1,011		131		880
2014-2019		6,487		879		5,608

	Lives in Years	December 31, 2008			December 31, 2007
		(In thousands)

Transmission plant	20-50	$	3,208,476		$	2,953,642
General plant	4-40		19,893			28,540
Intangibles (1)	10		18,548			31,196
Construction work-in-progress			405,585			150,742
Acquisition adjustment	62.5		1,252,466			1,252,466
			4,904,968			4,416,586
Less: Accumulated depreciation and amortization			(1,478,890	)		(1,401,638	)
Property, Plant and Equipment, net		$	3,426,078		$	3,014,948


(1) Includes capitalized computer software costs totaling:
Computer software cost		$	14,556		$	26,498
Less: accumulated amortization			(6,363	)		(16,300	)
Net computer software costs		$	8,193		$	10,198

	Termination Date	Amortization Period	Original Gain/(Loss)			December 31, 2008			December 31, 2007
			(In thousands)
Interest rate swap loss on 7.625% $325 million note due 2010	December 2000	10 years	$	(18,724	)	$	(3,588	)	$	(5,461	)
Interest rate swap loss on 7.0% $250 million note due 2012	July 2002	10 years		(12,280	)		(4,351	)		(5,579	)
Interest rate swap gain on 9.19% $150 million note due 2005-2024	November 1994	20 years		9,236			2,693			3,155
Total						$	(5,246	)	$	(7,885	)