10-K

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, 2006

OR

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
5.00% Corporate Units	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 con-tained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information state-ments incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _P__

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer P Accelerated filer ___ Non-accelerated filer _____

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, 2006 was $2,724,333,209 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2006). 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 16, 2007 was 119,771,014.

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 1, 2007 are incorporated by reference into Part III.

No. of Pages:  167

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2006

Table of Contents

		Page
	PART I
ITEM 1.	Business.	1
ITEM 1A.	Risk Factors.	15
ITEM 1B.	Unresolved Staff Comments.	23
ITEM 2.	Properties.	23
ITEM 3.	Legal Proceedings.	24
ITEM 4.	Submission of Matters to a Vote of Security Holders.	24
	PART II
ITEM 5.	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities.	24
ITEM 6.	Selected Financial Data.	26
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	26
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	51
ITEM 8.	Financial Statements and Supplementary Data.	54
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	54
ITEM 9A.	Controls and Procedures.	54
ITEM 9B.	Other Information.	55
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance.	55
ITEM 11.	Executive Compensation.	56
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	56
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	56
ITEM 14.	Principal Accountant Fees and Services.	56
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.	56
Signatures.		60
Index to the Consolidated Financial Statements.		F-1

PART I

ITEM 1. Business.

OUR BUSINESS

Introduction

Southern Union Company (Southern Union and, together with its subsidiaries, 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. The Company’s discontinued operations relate to certain assets previously included in the Distribution segment, which were sold on August 24, 2006.

Recent Acquisitions and Dispositions - As part of its continued diversification in the natural gas industry, Southern Union has made a series of business acquisitions and dispositions during 2006. These are as follows:

CCE Holdings Transactions. On December 1, 2006, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Florida Gas Transmission Company, LLC (Florida Gas) from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern Pipeline Company, LLC (Transwestern). On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer) entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings, LLC (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 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 Corp. (Citrus), which, in turn, owns 100 percent of Florida Gas.

In connection with the December 1, 2006 closing of the transactions contemplated by the Redemption Agreement, Trunkline LNG Holdings, LLC (LNG Holdings), an indirect wholly-owned subsidiary of the Company, as borrower, and Panhandle Eastern Pipe Line Company, LP (PEPL) and CrossCountry Citrus, LLC (CrossCountry Citrus), each an indirect wholly-owned subsidiary of the Company, as guarantors, entered into a $465 million unsecured term loan facility (2006 Term Loan). The proceeds of the 2006 Term Loan were used to repay the approximately $455 million of indebtedness of Transwestern Holding Company, LLC (Transwestern Holding), a wholly-owned subsidiary of CrossCountry Energy, LLC, and certain other obligations of Transwestern Holding. The 2006 Term Loan is due and payable on April 4, 2008.

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, subject to certain working capital adjustments. Proceeds from the sale were used to retire a portion of the bridge loan facility incurred in connection with Southern Union’s $1.6 billion purchase of Sid Richardson Energy Services, Ltd. and related entities (collectively, Sid Richardson Energy Services).

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 approximately $575 million in cash, less the assumption of approximately $77 million of debt and subject to certain working capital adjustments. Proceeds from the sale were used to retire a portion of the bridge loan facility incurred in connection with Southern Union’s $1.6 billion purchase of Sid Richardson Energy Services.

Acquisition of Sid Richardson Energy Services. On March 1, 2006, Southern Union acquired Sid Richardson Energy Services, a privately held natural gas gathering and processing business for $1.6 billion in cash, subject to working capital adjustments. The acquisition was funded under a bridge loan facility in the amount of $1.6 billion (Sid Richardson Bridge Loan). The Company used the proceeds of 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 retire approximately $1.1 billion of the $1.6 billion Sid Richardson Bridge Loan. On October 23, 2006, the Company retired the remaining approximately $525 million outstanding under the bridge loan facility with proceeds from the Company’s sale of $600 million of fixed/floating rate 7.20% 2006 Series A Junior Subordinated Notes due November 1, 2066 (Junior Subordinated Notes). See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations.

1

For a discussion of the Company’s 2004 change to a December 31 fiscal year end, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Introduction.

BUSINESS SEGMENTS

Reportable Segments

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

·   The Transportation and Storage segment, which is primarily engaged in the interstate transportation and storage of natural gas from gas producing areas in Texas, Oklahoma, Colorado, the Gulf of Mexico and the Gulf Coast to markets throughout the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services. Its operations are currently conducted through PEPL and its subsidiaries (collectively Panhandle) and Florida Gas;

·   The Gathering and Processing segment, which is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services; and

·   The Distribution segment, which is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

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, 2006 and 2005, the six months ended December 31, 2004 or the year ended June 30, 2004.

Transportation and Storage Segment

Services

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas to the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services. Prior to the Company’s transfer of its interest in Transwestern to Energy Transfer on December 1, 2006 pursuant to the Redemption Agreement, the Transportation and Storage segment also included service to the Southwest region through its then interest in Transwestern. The Transportation and Storage segment’s operations are now conducted through Panhandle and Florida Gas.

For the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, the Transportation and Storage segment’s operating revenues were $577.2 million, $505.2 million, $242.7 million and $490.9 million, respectively. For the years ended December 31, 2006 and 2005 and the six months ended December 31, 2004, Earnings from unconsolidated investments contributed through CCE Holdings were $141.1 million, $70.4 million and $4.6 million, respectively.

2

For information about operating revenues, earnings before interest and taxes (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 - Results of Operations - Business Segment Results - Transportation and Storage 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 Gas Company, LLC (Trunkline) transmission system and the Sea Robin Pipeline Company, LLC (Sea Robin) transmission system, serves customers in the Midwest 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. Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage) operates four of these fields and Trunkline operates one. Through Trunkline LNG Company, LLC (Trunkline LNG), Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana. The Trunkline LNG terminal is one of the largest operating LNG facilities in North America based on its current sustainable send out capacity of approximately 1.8 billion cubic feet per day (Bcf/d).

Panhandle earns the majority of its revenue by entering into firm transportation and storage contracts, reserving capacity for customers to transport or store natural gas in its facilities. Approximately 35 percent of Panhandle’s total operating revenue comes from long-term service agreements with local distribution company customers and their affiliates.  Panhandle also provides firm transportation services under contract to gas marketers, producers, other pipelines, electric power generators and a variety of end-users.  In addition, 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.

Citrus and CCE Holdings. 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. Energy Transfer’s 50 percent ownership interest in CCE Holdings was redeemed in exchange for 100 percent of the equity interests in Transwestern.

Florida Gas is an open-access interstate pipeline system with a capacity of 2.1 Bcf/d extending approximately 5,000 miles 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 70 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.

Transwestern is an open-access natural gas interstate pipeline with a capacity of 2.1 Bcf/d extending approximately 2,500 miles 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. The Company no longer has an ownership interest in Transwestern.

Florida Gas and Transwestern earn the majority of their revenue by entering into firm transportation contracts, providing capacity for customers to transport natural gas in their pipelines. Florida Gas and Transwestern also earn variable revenue from charges assessed on each unit of transportation provided. In addition, to the extent that the gas retained by Florida Gas and Transwestern for the operation of their pipeline system is not physically burned in the systems’ compressors, it is sold as operational gas when conditions warrant.

3

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. Beginning November 17, 2004, 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 trillion British thermal units (TBtu)) associated with the reported results of operations for the periods presented:

	Year Ended				Year Ended		Six Months Ended		Year Ended
	December 31, 2006				December 31, 2005		December 31, 2004		June 30, 2004
Panhandle
PEPL		579				609		269		576
Trunkline		486				459		267		564
Sea Robin		115				146		94		182
Trunkline LNG Usage Volumes		149				108		92		217
Citrus and CCE Holdings (1)
Florida Gas		737				699		N/A		N/A
Transwestern		572	(2	)		589		N/A		N/A
_______________________
(1)Represents 100 percent of Transwestern and Florida Gas versus the Company's effective equity ownership interest.
The Company's effective equity 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 redeemed by 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.

4

The following table provides a summary of certain statistical information associated with Panhandle and Florida Gas at December 31, 2006:

	As of
	December 31, 2006
Panhandle
Approximate Miles of Pipelines
PEPL		6,000
Trunkline		3,500
Sea Robin		450
Peak Day Delivery Capacity (Bcf/d)
PEPL		2.8
Trunkline		1.5
Sea Robin		1
Trunkline LNG		2.1
Trunkline LNG Sustainable Send-Out Capacity (Bcf/d)		1.8
Underground Storage Capacity-Owned (Bcf)		72
Underground Storage Capacity-Leased (Bcf)		16
Trunkline LNG Terminal Storage Capacity (Bcf)		9
Average Number of Transportation Customers		500
Weighted Average Remaining Life in Years of Firm Transportation Contracts
PEPL		4.6
Trunkline		9.9
Sea Robin              (1)		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts
PEPL		6.3
Trunkline		1.7
Florida Gas                (2)
Approximate Total Miles of Pipelines		5,000
Peak Day Delivery Capacity (Bcf/d)		2.1
Average Number of Transportation Customers		136
Weighted Average Remaining Life of Firm Transportation Contracts		10
___________________
(1)Sea Robin contracts are interruptible without any 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, 2006.

Recent System Enhancements - Completed or Under Construction

LNG Expansion Projects. Trunkline LNG’s Phase I expansion project was placed into service on April 5, 2006 with a total project cost of $141 million, plus capitalized interest. The expanded vaporization capacity portion of the expansion was placed into service on September 18, 2005. Phase II went into service on July 8, 2006. The final cost of Phase II was $79 million, plus capitalized interest. The expansions increased sustainable send-out capacity from .63 Bcf/d to 1.8 Bcf/d, and storage increased from 6.3 Bcf to 9 Bcf. BG LNG Services has contracted for all of the capacity at the facility through 2028 with a rate moratorium through 2015. Approximately $671,000 and $102 million of costs are included in the line item Construction work-in-progress for the expansion projects at December 31, 2006 and 2005, respectively.

On February 11, 2005, Trunkline received approval from FERC to construct, own and operate a 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal. The pipeline creates additional transport capacity in association with the Trunkline LNG expansion and also includes new and expanded delivery points with major interstate pipelines. The new 36-inch pipeline was placed into service on July 22, 2005.

5

For information related to ongoing and potential expansion projects of the Company or through its investment in Citrus, see Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations -Liquidity and Capital Resources.

Significant Customers

The following table provides the percentage of Transportation and Storage segment revenues and related weighted average contract lives of Panhandle’s significant customers at December 31, 2006:

	Percent of			Weighted
	Segment Revenues			Average Life
	For Year Ended			of Contracts at
Customer	December 31, 2006 (3)			December 31, 2006
BG LNG Services (1)		24	%		17	Years
ProLiance		12			7.8	Years
Ameren Corp. (2)		10			7.1	Years
Other top 10 customers		19				N/A
Remaining customers		35				N/A
Total percentage		100	%

_____________________

(1)   BG LNG Services’ contracts were extended with the completion of Phase I and Phase II in the second and third quarters of 2006, respectively. For additional information, see Item 8. Financial Statements and Supplementary Data, Note 16 - Regulation and Rates.

(2)   Includes Ameren Corp. subsidiaries such as Union Electric, Central Illinois Light Company, Illinois Power and Central Illinois Public Service.

(3)   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 them to release all or part of their capacity, which generally occurs for a limited time period. Under the terms of Panhandle’s tariff, 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, 2006:

	Percent of
	Florida Gas'
	Total Operating			Weighted
	Revenues			Average Life
	For Year Ended			of Contracts at
Customer	December 31, 2006 (1)			December 31, 2006
Florida Power & Light		41	%		8.3	Years
Tampa Electric/Peoples Gas		17			11.2	Years
Other top 10 customers		26			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’ revenues 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.

6

FERC has comprehensive jurisdiction over PEPL, Southwest Gas Storage, Trunkline, Trunkline LNG, Sea Robin 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 disposal of assets and facilities and to the service provided and rates charged.

FERC has authority to regulate rates and charges for transportation or 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 Storage 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 as of December 31, 2006, excluding Transwestern, the Company’s interest in which was redeemed on December 1, 2006:

	Date of Last
Company	Rate Filing	Status
PEPL	May 1992	Settlement effective April 1997
Trunkline	January 1996	Settlement effective May 2001
Sea Robin	April 2001	Settlement effective May 2002
Trunkline LNG	June 2001	Settlement effective January 2002
Southwest Gas Storage	April 1989	Settlement effective October 1989 (1)
Florida Gas	October 2003	Settlement effective March 2005; rate moratorium in effect until October 2007, required to file by October 2009
____________________
(1) For information related to a complaint filed with FERC against Southwest Gas Storage under Section 5 of the
Natural Gas Act, see Item 8. Financial Statements and Supplementary Data, Note 16 - Regulation and Rates -
Panhandle.

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 likely will continue to result, in increased competition in the pipeline business. In order to meet competitive challenges, Panhandle and Florida Gas will need to adapt their marketing strategies, the type of transportation and storage services provided and their pricing and rate responses to competitive forces. Panhandle and Florida Gas also will need to respond to changes in state regulation in their market areas that allow direct sales to all retail end-user customers or, at a minimum, broader customer classes than now allowed.

7

FERC policy allows the issuance of certificates authorizing the construction of new interstate pipelines that are competitive with existing pipelines. A number of new pipeline and pipeline expansion projects are under development to transport large additional volumes of natural gas to the Midwest from the Rockies. These pipelines, which include Kinder Morgan’s Rockies Express Pipeline project, could potentially compete with the Company.

The Company’s direct competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas Pipeline Company of America, Northern Border Pipeline Company, Texas Gas Transmission Corporation, Northern Natural Gas Company, Vector Pipeline, Columbia Gulf Transmission and Midwestern Gas Transmission.

Although for many years the Florida Gas pipeline system was the only interstate natural gas pipeline system serving peninsular Florida, since May 28, 2002, Florida Gas has competed 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

The principal assets of the acquired Sid Richardson Energy Services business, now known as Southern Union Gas Services, are located in the Permian Basin of Texas and New Mexico and include approximately 4,800 miles of natural gas and natural gas liquids gathering pipelines, four cryogenic plants and six natural gas treatment plants. Southern Union Gas Services, which comprises the Company’s Gathering and Processing segment, is engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico.

Southern Union Gas Services’ activities primarily include 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 natural gas liquids, transporting natural gas and redelivering natural gas and natural gas liquids to a variety of markets. Southern Union Gas Services’ primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States. Southern Union Gas Services receives hydrocarbons for purchase or transportation to market from over 200 producers and suppliers, none of which account for more than 10 percent of its total hydrocarbon throughput. Southern Union Gas Services’ business is not generally seasonal in nature.

Due to the flexibility built into its gathering systems and plants, Southern Union Gas Services is able to offer a broad array of services to producers. Sales contracts provided by Southern Union Gas Services primarily include percentage of proceeds, fee based and conditioning contracts, which as of December 31, 2006 comprised 53 percent, 29 percent and 14 percent, respectively, of Southern Union Gas Services’ sales contracts. These contracts vary in term from month-to-month up to and including the related lease life, with many of the contracts falling in the three- to five-year time frame.

For the 2006 period subsequent to the March 1, 2006 acquisition, Southern Union Gas Services’ operating revenues net of Cost of gas and other energy costs were $172.2 million. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -Results of Operations for a summary of average daily volumes of natural gas and natural gas liquids volumes processed and the associated average daily prices for 2006.

8

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 - Results of Operations - Business Segment Results - Gathering and Processing and Item 8. Financial Statements and Supplementary Data, Note 21 - Reportable Segments.

Significant Customers

The following table provides the percentage of Gathering and Processing segment revenues and related weighted average contract lives of Southern Union Gas Services’ significant customers at December 31, 2006:

	Percent of		Weighted
	Segment Revenues		Average Life
	For Year Ended		of Contracts at
Customer	December 31, 2006		December 31, 2006
ConocoPhillips Company (1)	22	%	20 Months
BP Energy Company	11		Month to Month
Constellation Power Source	10		Month to Month
Other top 10 customers	22		N/A
Remaining customers	35		N/A
Total percentage	100	%

 (1) ConocoPhillips Company comprised ten percent of the Company’s consolidated Operating revenues reported in the Consolidated Statement of Operations for 2006.

Natural Gas Connections

Southern Union Gas Services’ 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 Wes Tex Transmission, LP, Public Service Company of New Mexico and Transwestern, a former affiliate of the Company (see Item 8. Financial Statements and Supplementary Data - Note 10 - Unconsolidated Investments). Its major natural gas liquids pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

Regulation

Southern Union Gas Services’ 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. Environmental Protection Agency (U.S. EPA) and its state counterparts, the Occupational Safety and Health Administration (OSHA) and the U.S. Department of Transportation’s Office of Pipeline Safety and its state counterparts. The Company believes that its gathering and processing operations are in material compliance with applicable safety and environmental statutes and regulations.

9

Competition

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

·   producer drilling activity,

·   contract fees charged,

·   pressures maintained on the gathering systems,

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

·   efficiency and reliability of the operations, and

·   delivery capabilities in each system and plant location.

Commodity prices for natural gas and natural gas liquids 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.

Southern Union Gas Services has responded to these industry conditions by positioning and configuring its gathering and processing facilities to offer a broad range of services to accommodate the types and quality of natural gas produced in the region. Many competing systems provide only a single level of service. Southern Union Gas Services also continues to further improve its system integrity by increasing its fuel efficiencies and reducing unaccounted for gas volume losses.

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 560,000 residential, commercial and industrial customers through local distribution systems consisting of 8,983 miles of mains, 6,028 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 Missouri Public Service Commission (MPSC) and the Massachusetts Department of Telecommunications and Energy (MDTE), respectively. The Distribution segment’s operations are generally sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues and net earnings being derived in the traditional winter heating season in the first and fourth calendar quarters.

For the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, the Distribution segment’s operating revenues were $668.7 million, $752.7 million, $273.6 million and $655.7 million, respectively; average customers served totaled 551,604, 548,514, 545,328 and 548,857, respectively; and gas volumes sold or transported totaled 77,890 million cubic feet (MMcf), 84,112 MMcf, 33,959 MMcf and 86,447 MMcf, respectively. 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 consolidated operating revenues for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 or the year ended June 30, 2004.

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

10

The Distribution segment customers served, gas volumes sold or transported and weather-related information for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 are as follows:

					Six
			Year Ended	Year Ended	Months Ended	Year Ended
			December 31,	December 31,	December 31,	June 30,
			2006	2005	2004	2004
Average number of customers:
	Residential		482,882	480,381	479,220	482,146
	Commercial		67,120	66,608	64,940	65,635
	Industrial and irrigation		129	142	140	138
		Total average customers served	550,131	547,131	544,300	547,919
	Transportation customers		1,473	1,383	1,028	938
		Total average gas sales and transportation customers	551,604	548,514	545,328	548,857
Gas sales (MMcf):
	Residential		34,946	39,160	12,045	41,361
	Commercial		14,938	16,633	5,469	17,423
	Industrial and irrigation		517	525	170	455
	Gas sales billed		50,401	56,318	17,684	59,239
	Net change in unbilled gas sales		1,149	185	3,935	85
		Total gas sales	51,550	56,503	21,619	59,324
		Gas transported	26,340	27,609	12,340	27,123
		Total gas sales and gas transported	77,890	84,112	33,959	86,447
Gas sales revenues ($ in thousands):
	Residential		$ 472,926	$ 500,874	$ 155,281	$ 450,824
	Commercial		189,837	201,122	62,775	180,242
	Industrial and irrigation		11,140	10,499	2,142	5,059
	Gas revenues billed		673,903	712,495	220,198	636,125
	Net change in unbilled gas sales revenues		(25,681)	19,561	43,871	1,937
		Total gas sales revenues	648,222	732,056	264,069	638,062
		Gas transportation revenues	12,253	12,885	5,223	10,542
		Other revenues	8,246	7,758	4,305	7,092
Total operating revenues			$ 668,721	$ 752,699	$ 273,597	$ 655,696
Weather:
Massachusetts Utility Operations:
	Degree days (a)		4,901	5,801	2,004	5,644
	Percent of 10-year measure (b)		90%	106%	98%	102%
	Percent of 30-year measure (b)		85%	101%	96%	98%
Missouri Utility Operations:
	Degree days (a)		3,996	4,621	1,669	4,770
	Percent of 10-year measure (b)		77%	89%	81%	92%
	Percent of 30-year measure (b)		77%	89%	82%	92%

___________________                                             
(a) "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.

(b) 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.

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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 gas supplies directly since the mid-1980s when inter-state pipeline systems opened their systems for trans-portation service. The Company sought to ensure reliable service to customers by developing the ability to dispatch and monitor gas volumes on a daily, hourly or real-time basis.

For the year ended December 31, 2006, the majority of the 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 more than twenty commodity suppliers. For this same period, the majority of the gas requirements for the Massachusetts utility operations of New England Gas Company were delivered under long-term contracts through six major pipeline companies and contracts with four commodity suppliers. Collectively, these contracts have various expiration dates ranging from 2007 through 2013. Missouri Gas Energy and New England Gas Company have firm supply commitments for all areas that are supplied with gas purchased under short- and long-term arrangements. Missouri Gas Energy and New England Gas Company hold contract rights to over 17 Bcf and one Bcf of storage capacity, respectively, to assist in meeting peak demands.

Like the gas industry as a whole, Southern Union utilizes gas sales and/or transportation contracts with interruption provisions, by which large volume users purchase gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the 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 MDTE. 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. Gas costs are billed to customers through purchase 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 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.

The Company’s monthly customer bills contain a fixed service charge, a usage charge for service to deliver 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 annual revenue and earnings in the traditional heating load months when usage of natural gas increases.

In addition to the regulation of its utility businesses, the Company 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.

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

	Date of Last
Utility Operations	Rate Filing	Status
Missouri	May 2006	MPSC is expected to issue a ruling in first quarter 2007 on proposed rate increase filed in May 2006.
Massachusetts	May 1996	Effective December 1996; Filed notice of intent with MDTE in June 2006 to file rate schedules.

Competition

As energy providers, Missouri Gas Energy and New England Gas Company historically have competed with alternative energy sources available to end-users in their service areas, particularly electricity, propane, fuel oil, coal, natural gas liquids 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.

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 $5 million for the various policies utilized by the Company. Furthermore, as the Company renews its policies, it is possible that full insurance coverage may not be obtainable on commercially reasonable terms due to recent more restrictive insurance markets.

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Employees

As of January 31, 2007, the Company had 2,312 employees, of whom 1,503 are paid on an hourly basis and 809 are paid on a salary basis. Of the 1,503 hourly paid employees, unions represent 51 percent. 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	Expiration of
Company	Represented by Unions	Current Contract
PEPL
USW Local 348	218	May 27, 2009
Missouri Gas Energy
Gas Workers 781	199	April 30, 2009
IBEW Local 53	99	April 30, 2009
USW Local 5-267	25	April 30, 2009
USW Local 12561, 14228	145	April 30, 2009
New England Gas Company
UWUA Local 431	76	April 30, 2010

As of January 31, 2007, the number of persons employed by each segment was as follows: Transportation and Storage segment -1,122 persons; Gathering and Processing segment - 288 persons; Distribution segment - 797 persons; All Other subsidiary operations - 13 persons. In addition, the corporate employees of Southern Union totaled 92 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 January 31, 2007, Florida Gas had 292 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, 2006 and 2005, the six-month period ended December 31, 2004 or the year ended June 30, 2004.

Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (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.

Southern Union, 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.

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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 and finance 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 it 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 or results of operations could be materially and adversely affected.

RISKS THAT RELATE TO SOUTHERN UNION

Southern Union has substantial debt and depends on its ability to access the capital markets.

Southern Union has a significant amount of debt outstanding. As of December 31, 2006, consolidated debt on the Consolidated Balance Sheet totaled $3.3 billion outstanding compared to total capitalization (long and short-term debt plus stockholders' equity) of $5.3 billion.

Some of the Company’s debt obligations contain financial covenants related to 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 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. Any worsening of the Company’s financial condition or a material decrease in its common stock price could hamper its ability to access the capital markets. External events also could increase the Company’s cost of borrowing or adversely affect its ability to access the capital markets.

Further, because of the need for certain state regulatory approvals in order to incur 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.

The Company plans to refinance its current debt of $462.3 million outstanding at December 31, 2006 with proceeds from bank financings. The Company is in the final stages of planning for the refinancing of debt coming due in March 2007. While an inability to repay these obligations could cause a material adverse change to the Company’s financial condition, the Company reasonably believes that it has the ability to refinance these obligations within the required timeframes, although there can be no assurances that the anticipated refinancings will occur.

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

As of December 31, 2006, both Southern Union’s and Panhandle’s debt are currently rated Baa3 by Moody's Investor Services, Inc., BBB- by Standard & Poor's and BBB by Fitch Ratings. 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.

15

The Company’s growth strategy entails risk for investors.

The Company intends to 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.

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; or

·   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 and joint ventures 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.

16

The Company owns 100 percent of CCE Holdings as of December 1, 2006 and CCE Holdings 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 natural gas liquid products, including 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 material 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). These laws and regulations 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 can impose liability without regard to fault concerning contamination at a broad range of properties, including those currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of waste.

The Company is currently monitoring or remediating contamination at 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 or results of operations, 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.

The Internal Revenue Service may challenge the like-kind exchange treatment the Company has taken or expects to take.

Effective August 25, 2006, the Company consummated a like-kind exchange under Internal Revenue Code Section 1031 (Section 1031) by using the proceeds from the sale of the assets of its PG Energy natural gas distribution division and the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division, to acquire the assets of the Sid Richardson Energy Services business. If like-kind exchange treatment were not to apply to these transactions, most of the tax gain realized with respect to these asset sales would be recognized currently. The like-kind exchange rules of the Internal Revenue Code are highly complex and their application to the asset sales and the acquisition of the assets of the Sid Richardson Energy Services business is not certain. If the Internal Revenue Service successfully denied the benefits of Section 1031, the Company could be required to pay approximately $263 million of additional income tax (before any interest or penalty) for the 2006 taxable year. Under such circumstances, the Company expects that it would be entitled to a corresponding income tax benefit of $263 million over time due to additional depreciation deductions from the Sid Richardson Energy Services assets as a result of the higher tax basis in such assets that would exist if the benefits of Section 1031 were not available.

17

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 natural gas liquid products gathered and processed by Southern Union Gas Services. As a result, the volume of natural gas transported, stored, gathered or processed depends on the actions of those third parties and is beyond the Company’s control. Further, other factors beyond the Company’s control may unfavorably impact its 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 its access to the reserves of available natural gas. Additionally, the amount of revenue generated by Southern Union Gas Services depends substantially upon the volume of natural gas or natural gas liquid products 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 third parties in the development of new natural gas reserves connected to the Company’s facilities depend on many factors beyond the control of the Company.

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

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

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 and state regulatory authorities. FERC, the U.S. Department of Transportation and various state and local regulatory agencies regulate the interstate pipeline business. In particular, FERC regulates services provided and rates charged by Panhandle and Florida Gas. In addition, the U.S. Coast Guard has oversight over certain issues related to the importation of LNG.

The Company’s rates and operations are subject to 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.

18

Should new regulatory requirements regarding the security of its pipeline system or new accounting requirements for certain entities be imposed, the Company could be subject to additional costs that could adversely affect its business, financial condition or results of operations if these costs are deemed unrecoverable in rates.

See information concerning a complaint filed against Southwest Gas Storage under Section 5 of the Natural Gas Act in Item 8. Financial Statements and Supplementary Data, Note 16 - Regulation and 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. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. 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, especially Canada, the volume of gas transported by the Company may be negatively impacted.

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 46 percent of its 2006 revenue. Florida Gas’ top two customers accounted for 58 percent of its 2006 revenue. The loss of any one or more of these customers could have a material adverse effect on the Company’s business, financial condition or results of operation.

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. 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.

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

The Company’s natural gas gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas and natural gas liquids gathering and processing operations conducted at Southern Union Gas Services are not regulated and may potentially have a higher level of risk than the Company’s regulated operations.

Although Southern Union Gas Services 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 financial position, results of operations or cash flows.

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

The natural gas gathering and processing industry is expected to remain highly competitive. Most customers of Southern Union Gas Services have access to more than one alternative gathering and/or processing system. The Company’s ability to compete depends on a number of factors, including the infrastructure and contracting strategy of competitors in the Company’s gathering region; the efficiency, quality and reliability of the Company’s system; and the Company’s ability to maintain a reliable low-cost pipeline operating system.

In addition to Southern Union Gas Services’ current competitive position in the natural gas 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 liquid byproducts. If natural gas or natural gas liquid products prices in the supply basins connected to the Company’s gathering system are comparatively higher than prices in other natural gas producing regions, the volume of gas that Southern Union Gas Services chooses to process may be reduced to maximize returns to the Company. Similarly, since the demand for natural gas or natural gas liquid products 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 by Southern Union Gas Services may be reduced based on these market conditions on a daily basis after analysis by the Company.

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

Southern Union Gas Services’ fees are typically charged either (a) as a percentage of the volume of gas gathered and natural gas liquids processed through its facilities, or (b) for a specified fee for a range of services provided. The purchase price for the gas gathered and natural gas liquids processed by the Company is based on a market clearing index (typically a daily price) and is matched with the price at which the gas and liquids are ultimately sold to its market customers on the same basis. Therefore, Southern Union Gas Services’ operating margin is highly dependent on energy commodity prices.

The Company uses various derivative financial instruments to manage commodity price risk and to take advantage of pricing anomalies among derivative financial instruments related to natural gas and natural gas liquids. The Company uses a combination of fixed price physical forward contracts, exchange-traded futures and options, fixed for floating index and basis swaps to manage commodity price risk. 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 the physical market and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations. However, these financial derivative instrument contracts do not entirely eliminate pricing risks. Specifically, the Company is subject to other risks including un-hedged commodity price changes, market supply shortages and customer defaults. The impact of these variables could result in the Company paying higher energy or fuel costs relative to corresponding sales contracts. 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.

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Operational risks are involved in operating a natural gas 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. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. 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’s natural gas gathering and processing business accepts some credit risk in dealing with customers.

Southern Union Gas Services derives its revenues from customers engaged primarily in the natural gas and utilities industries and extends payment credit to these customers. Southern Union Gas Services’ accounts receivable primarily consists of mid- to large-size domestic customers with credit ratings of investment grade or better. Moreover, Southern Union Gas Services 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 derivatives agreement. Nevertheless, the Company cannot predict to what extent future declines in customers’ creditworthiness may negatively impact its business.

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 natural gas gathering and processing business.

Southern Union Gas Services’ ability to operate within its operating region will depend on its success in maintaining existing rights-of-way and obtaining new right-of-way grants. Securing additional rights-of-way is also critical to Southern Union Gas Services’ ability to pursue expansion projects. Southern Union Gas Services cannot assure that it will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants. The Company’s financial position could be adversely affected if the costs of new or extended right-of-way grants exceed the margin within a gathering region.

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 MDTE. 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 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.

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.

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

The gas distribution business is a seasonal business and is subject to weather conditions. A significant percentage of annual revenues and earnings occur in the traditional winter heating season when demand for natural gas usually increases due to colder weather conditions. 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 natural gas 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 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. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. 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.

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-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.

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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 by the Company’s customers, the composition of the Company’s customer base and 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 natural gas liquid products 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 such as hurricanes;

·   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;

·   risks relating to Southern Union’s recent acquisition of the Sid Richardson Energy Services business, including without limitation, the Company’s increased exposure to highly competitive commodity businesses;

·   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.

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 generation 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.

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ITEM 3. Legal Proceedings.

The Company and certain of its affiliates are occasionally parties to routine lawsuits and administrative proceedings incidental to their business involving, for example, claims for personal injury and property damage, environmental matters, contractual matters, various tax matters, and rates and licensing. The Company and certain of its affiliates are also subject to various federal, state and local laws and regulations relating to the environment. Reference is made to Item 1. Business - Regulation and Rates, as well as to Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition and Item 8. Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements included herein for a discussion of the Company's legal proceedings. 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

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 (adjusted for any stock dividends) for shares of Southern Union common stock since January 1, 2005 are set forth below:

	$/Share
	High		Low
January 1 to February 16, 2007	29.43		26.81
(Quarter Ended)
December 31, 2006		29.76		26.19
September 30, 2006		27.75		25.83
June 30, 2006		27.22		22.76
March 31, 2006		25.55		22.90
(Quarter Ended)
December 31, 2005		26.29		21.66
September 30, 2005		25.82		23.35
June 30, 2005		24.33		21.80
March 31, 2005		25.48		20.77

HOLDERS

As of February 16, 2007, there were 6,184 holders of record of Southern Union's common stock, and 119,771,014 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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DIVIDENDS

Provisions in certain of Southern Union’s long-term debt and its 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 debt restrictions at Panhandle that could limit Southern Union’s access to funds from Panhandle for debt service or dividends. See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations.

Prior to 2006, Southern Union distributed an annual stock dividend of five percent. On September 1, 2005, August 31, 2004 and July 31, 2003, the Company distributed its then annual five percent common stock dividend to stockholders of record on August 22, 2005, August 20, 2004 and July 17, 2003, respectively.

On December 21, 2005, Southern Union’s board of directors approved the payment of an annual cash dividend of $.40 per share. The cash dividend replaced the Company’s historic practice of issuing an annual five percent stock dividend. On April 14, 2006, July 14, 2006, October 6, 2006 and January 12, 2007, the Company paid quarterly cash dividends of $11.2 million, $11.2 million, $11.9 million and $12 million to stockholders of record on March 31, 2006, June 30, 2006, September 29, 2006 and December 29, 2006, respectively.

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 $20 million (to the extent that earnings were available) and $26.3 million, respectively.

EQUITY COMPENSATION PLANS

Equity compensation plans approved by stockholders include the Southern Union Company Second Amended and Restated 2003 Stock and Incentive Plan (Second Amended 2003 Plan) and the 1992 Long-Term Stock Incentive Plan (1992 Plan). While Southern Union Company 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 stock appreciation rights, the weighted-average exercise price of outstanding options and the number of shares remaining available for issuance as of December 31, 2006:

	Number of Securities		Number of Securities
	to Be issued Upon	Weighted-Average	Remaining Available for
	Exercise of	Exercise Price of	Future Issuance Under
Plan Category	Outstanding Options	Outstanding Options	Equity Compensation Plans
Plans approved by stockholders	1,859,285 (1)	18.49	7,247,810

(1) Excludes 168,784 shares of restricted stock that were outstanding at December 31, 2006.

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ITEM 6. SELECTED FINANCIAL DATA.

							For the
	For the years ended						six months ended			For the years ended
	December 31,						December 31,			June 30,
	2006  (a)			2005			2004  (a)			2004		2003 (b)			2002
	(In thousands of dollars, except per share amounts)
Total operating revenues	$	2,340,144		$	1,266,882		$	517,849		$	1,149,268	$	596,330		$	495,281
Earnings from unconsolidated
investments		141,370			70,742			4,745			200		422			1,420
Net earnings:
Continuing operations (c)		199,718			135,731			(1,635	)		51,729		(12,425	)		(51,130	)
Discontinued operations (d)		(152,952	)		(132,413	)		7,723			49,610		88,614			70,754
Available for common stockholders		46,766			3,318			6,088			101,339		76,189			19,624
Net earnings per diluted
common share (e):
Continuing operations		1.70			1.20			(0.02	)		0.63		(0.19	)		(0.80	)
Discontinued operations		(1.30	)		(1.17	)		0.09			0.61		1.36			1.11
Available for common stockholders		0.40			0.03			0.07			1.24		1.17			0.31
Total assets		6,782,790			5,836,819			5,568,289			4,572,458		4,590,938			2,680,064
Stockholders’ equity		2,050,408			1,854,069			1,497,557			1,261,991		920,418			685,346
Current portion of long-term debt and
capital lease obligation		461,011			126,648			89,650			99,997		734,752			108,203
Long-term debt and capital lease
obligation, excluding current portion		2,689,656			2,049,141			2,070,353			2,154,615		1,611,653			1,082,210
Company-obligated mandatorily
redeemable preferred securities
of subsidiary trust		-			-			-			-		100,000			100,000
Common stock dividends (f)		46,289			-			-			-		-			-

_____________________    

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

(b)   Panhandle was acquired on June 11, 2003 and was accounted for as a purchase. The Panhandle assets were included in the Company's Consolidated Balance Sheet at June 30, 2003 and its results of operations have been included in the Company's Consolidated Statement of Operations since its acquisition on June 11, 2003. For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisition is not comparable to the year of acquisition.

(c)   Net earnings from continuing operations are net of dividends on preferred stock of $17.4 million, $17.4 million, $8.7 million and $12.7 million for the years ended December 31, 2006

and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively.

(d) 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.  On January 1, 2003, ONEOK acquired the Company’s Southern Union Gas natural gas operating division and related assets.  These dispositions were accounted for as discontinued operations in the Consolidated Statement of Operations.

(e) 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, July 31, 2003 and July 15, 2002.

(f) 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 Note 10 - Stockholders’ Equity -- Dividends.

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 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.

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Effective December 17, 2004, Southern Union’s board of directors approved a change in the Company’s fiscal year from a 12-month period ending June 30 to a 12-month period ending December 31. As a requirement of this change, the results for the six-month period from July 1, 2004 to December 31, 2004 are reported as a separate transition period.

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and natural gas liquids 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.

BUSINESS STRATEGY

As detailed in the Company's Strategic Plan & Outlook for 2007 and beyond, 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. Examples of new initiatives include creation of a master limited partnership and potential further diversification of earning sources through strategic acquisitions or joint ventures in the North American diversified natural gas industry. In this regard, Southern Union diversified the Company’s regulated and non-regulated cash flow and earnings sources in 2006 with its acquisition of Sid Richardson Energy Services, its increased equity interests in Citrus as a result of the transactions under the Redemption Agreement and the sales 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. See Item 1. Business - Our Business - Introduction.

·   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 believes that its acquisition of Sid Richardson Energy Services on March 1, 2006, its investment in CCE Holdings on November 17, 2004 and the related exchange of ownership interests of CCE Holdings with Energy Transfer more fully described below, and 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 represent significant steps undertaken by the Company in its transformation into a higher return business with significant growth opportunities.

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 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 the 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.

In connection with the December 1, 2006 closing, LNG Holdings, an indirect wholly-owned subsidiary of the Company, as borrower, and PEPL and CrossCountry Citrus, each an indirect wholly-owned subsidiary of the Company, as guarantors, entered into the 2006 Term Loan. The proceeds of the 2006 Term Loan were used to repay the approximately $455 million of existing indebtedness of Transwestern Holding and certain other obligations of Transwestern Holding.

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, which is 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 from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes;

·   income taxes;

·   interest; and

·   dividends on 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 operating cash flow.

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The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders. Due to the Company’s change in its fiscal year, certain unaudited periods are presented to facilitate a meaningful comparison of financial results between periods.

										Six Months Ended
	Years Ended December 31,									December 31,
							2004						2003
	2006			2005			(Unaudited)			2004			(Unaudited)
	(In thousands)
EBIT:
Transportation and storage segment	$	417,536		$	281,344		$	198,422		$	94,971		$	96,212
Gathering and processing segment		62,630			-			-			-			-
Distribution segment		41,883			61,698			32,435			4,266			12,405
Corporate and other		14,324			(11,424	)		(24,642	)		(20,686	)		(8,438	)
Total EBIT		536,373			331,618			206,215			78,551			100,179
Interest		210,043			128,470			119,722			61,597			63,250
Earnings from continuing operations before
income taxes		326,330			203,148			86,493			16,954			36,929
Federal and state income taxes		109,247			50,052			36,919			9,906			15,040
Net earnings from continuing operations		217,083			153,096			49,574			7,048			21,889
Discontinued operations:
Earnings (loss) from discontinued operations
before income taxes		(2,369	)		(111,588	)		68,257			11,744			20,148
Federal and state income taxes		150,583			20,825			23,750			4,021			7,322
Net earnings (loss) from discontinued operations		(152,952	)		(132,413	)		44,507			7,723			12,826
Preferred stock dividends		17,365			17,365			17,365			8,683			4,004
Net earnings available for common stockholders	$	46,766		$	3,318		$	76,716		$	6,088		$	30,711

Year ended December 31, 2006 versus the year ended December 31, 2005. The Company’s $43.4 million increase in earnings was primarily attributable to improved earnings from Panhandle largely due to higher LNG terminalling revenue resulting from the LNG terminal enhancement construction projects completed during 2006, the earnings contribution from Southern Union Gas Services, which was acquired on March 1, 2006, and increased equity earnings primarily due to the gain on CCE Holdings’ exchange of Transwestern, partially offset by higher interest expense, most of which is related to debt and debt issuance costs associated with the Southern Union Gas Services acquisition, and losses and taxes associated with the 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.

Year ended December 31, 2005 versus the year ended December 31, 2004. The Company’s $73.4 million decrease in earnings was caused by the impact of the goodwill impairment charge of $175 million resulting from the execution of agreements for the sale of the Company’s Pennsylvania and Rhode Island natural gas distribution businesses. Excluding this charge, earnings would have improved by $101.6 million. The improvement was primarily due to realization of a full year of operating results from CCE Holdings, cost sharing synergies split between Southern Union and CCE Holdings related to the November 17, 2004 acquisition of CrossCountry Energy, LLC (CrossCountry Energy) and an MPSC base revenue rate order authorization applicable to Missouri Gas Energy. Additionally, decreases in operating expenses in both the Transportation and Storage and Distribution segments were realized, partially offset by higher depreciation expense.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. The Company’s $24.6 million decrease in earnings in the 2004 period as compared to 2003 was primarily caused by a charge for the impairment of the Company’s investment in a technology company, increases in operating expenses associated with the Distribution segment and discontinued operations, primarily due to increased bad debt expenses, and an increase in preferred stock dividends. Such decrease was partially offset by an increase in Earnings from unconsolidated investments related to the investment in CCE Holdings on November 17, 2004 and a decrease in income tax expense.

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Business Segment Results

Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas from gas producing areas in Texas, Oklahoma, Colorado, and the Gulf of Mexico and the Gulf Coast to markets throughout the Midwest, and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Prior to the closing of the Redemption Agreement on December 1, 2006, the Transportation and Storage segment also provided service to the Southwest region through its interests in Transwestern. The Transportation and Storage segment’s operations, now conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. The Transportation and Storage segment’s operations are somewhat 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.

Historically, much of the Transportation and Storage segment’s business was conducted through long-term contracts with customers. Over the past several years, some customers within the segment have shifted to shorter term transportation services contracts. This shift, which can increase the volatility of revenues, is primarily due to changes in market conditions and competition with other pipelines, new supply sources, changing supply sources and volatility in natural gas prices. However, changes in commodity prices and volumes transported do not generally have a significant short-term impact on operating revenues because the majority of the Transportation and Storage segment revenues are related to firm capacity reservation charges. 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.

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

							Six Months Ended
	Years Ended December 31,						December 31,
					2004				2003
Transportation and Storage Segment	2006		2005		(Unaudited)		2004		(Unaudited)
	(In thousands)
Operating revenues	$	577,182	$	505,233	$	489,164	$	242,743	$	244,473
Operating expenses		206,181		204,711		212,106		109,796		107,796
Depreciation and amortization		72,724		62,171		56,989		30,159		33,158
Taxes other than on income
and revenues		25,405		28,196		26,867		12,667		13,089
Total operating income		272,872		210,155		193,202		90,121		90,430
Earnings from unconsolidated
investments		141,310		70,618		4,861		4,761		90
Other income, net		3,354		571		359		89		5,692
EBIT	$	417,536	$	281,344	$	198,422	$	94,971	$	96,212

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, 2006 versus the year ended December 31, 2005. The $136.2 million EBIT improvement in the year ended December 31, 2006 versus the same period in 2005 was primarily due to improved contributions from Panhandle totaling $65.5 million and higher equity earnings from the Company’s investment in CCE Holdings of $70.7 million, including a $74.8 million non-recurring gain.

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Panhandle’s $65.5 million EBIT improvement was primarily related to the following items:

·   Higher operating revenues of $71.9 million primarily due to:

o   A $49.3 million increase in LNG terminalling revenue primarily due to expanded vaporization capacity, a base capacity increase on the BG LNG Services contract and higher volumes resulting from an increase in LNG cargoes;

o   Increased transportation and storage revenue of $17 million due to higher reservation revenues of $15.6 million, which were primarily driven by higher average rates on contracts, higher parking revenues of $1.6 million and higher storage revenues of $4.7 million due to increased contracted capacity. These increases were partially offset by lower usage revenues of $4.9 million, of which $3.1 million resulted from the impact on Sea Robin in 2006 of the hurricanes that occurred in the third quarter of 2005 and $1.8 million resulted from lower overall capacity utilization at Trunkline; and

o   Increased other revenue of $5.7 million primarily due to $3.7 million of non-recurring operational sales of gas in 2006 and $1.1 million of higher liquids revenue.

·   Higher operating expenses of $1.5 million primarily due to:

o   Approximately $3.2 million of higher pipeline integrity assessment costs;

o   Approximately $1.6 million of higher maintenance project costs;

o   $1.3 million in 2006 for inspections of facilities due to Hurricane Rita;

o   $2.1 million of higher LNG fuel and electric power tracker costs associated with greater LNG cargo activity;

o   A $3.8 million nonrecurring adjustment in 2005 for lower vacation accruals due to a change in vacation pay practice; and

o   Favorable offsetting impact of a $9.7 million decrease in insurance related costs due to accrued losses recorded in 2005 associated with the hurricanes and lower 2006 premiums and a $4.4 million decrease in benefit costs primarily related to lower postretirement benefit expenses including the impact of enactment of Medicare Part D reimbursements and benefit plan changes;

·   Increased depreciation and amortization expense of $10.6 million due to an increase in property, plant and equipment placed in service in 2006, including the Trunkline LNG Phase I and Phase II expansions;

·   Decreased taxes other than on income of $2.8 million primarily due to refunds of franchise and sales taxes received in 2006; and

·   A $2.8 million increase in other income, net primarily due to a gain on sale of certain Trunkline assets in 2006.

Equity earnings were higher by $70.7 million primarily due to:

·   A nonrecurring gain of $74.8 million resulting from the transfer of Transwestern pursuant to the Redemption Agreement;

·   Higher earnings from Florida Gas of $5.5 million, $2.8 million of which related to the December 2006 incremental earnings resulting from the Company’s additional 25 percent ownership interest in Florida Gas as a result of the transactions under the Redemption Agreement;

·   Lower earnings from discontinued operations of $10.6 million (adjusted to reflect the Company’s 50 percent share) related to Transwestern primarily due to:

·   Lower net revenues of $4.8 million primarily related to an $8 million impact from a decrease in transportation volumes associated with the replacement of expired contracts at discounted rates, partially offset by $3.2 million of increased operational gas sales revenue;

·   Higher operating expense of $5.5 million primarily related to higher system balancing expenses of $3.7 million and $2 million of higher electricity costs due to the addition of San Juan compression;

·   A decrease of $1.9 million in net earnings attributable to Transwestern due to 2006 containing only 11 months versus a full year of operations in 2005 due to the redemption of Transwestern on December 1, 2006; and

·   The favorable offsetting impact of lower depreciation expense of $2.4 million due to the cessation of depreciation on Transwestern following the execution of the Redemption Agreement with Energy Transfer.

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Year ended December 31, 2005 versus the year ended December 31, 2004.The $82.9 million EBIT improvement was primarily due to the realization of a full year of equity earnings in 2005, totaling $70.4 million, from the Company’s investment in CCE Holdings versus $4.6 million recognized in 2004. Additional EBIT improvements in 2005 compared with 2004 at Panhandle were primarily related to the following items:

·   Higher transportation and storage revenue of approximately $11.5 million primarily due to:

o   An $8.8 million increase on PEPL, reflecting higher average reservation rates on new contracts;

o   A $7.4 million increase in Trunkline reservation revenues primarily related to the pipeline loop facilities extending from the Trunkline LNG terminal, which went into service in the third quarter of 2005.

o   Decreased commodity revenues on Trunkline of $2.3 million due to a reduction in commodity volumes of six percent resulting from lower market spreads; and

o   Impacts of Hurricane Rita, which significantly reduced volumes flowing on Sea Robin and caused shutdowns of liquids production, resulting in approximately $3 million of revenue decreases;

·   Higher LNG terminalling revenue of $6 million primarily due to expanded vaporization capacity and a base capacity increase on the BG LNG contract, partially offset by lower volumes resulting from fewer LNG cargoes;

·   A reduction in certain administrative and operating expenses of approximately $6.9 million primarily due to synergies associated with the workforce reduction undertaken in the fourth quarter of 2004 associated with the integration of CrossCountry Energy;

·   A decrease of approximately $3.8 million in operating expenses due to a change in vacation pay practice and a corresponding accrual reduction;

·   A decrease of approximately $3.4 million in benefit costs primarily due to headcount reductions and lower postretirement costs including the impact of the enactment of Medicare Part D reimbursements and benefit plan changes;

·   Incurrence of approximately $1.7 million of severance-related costs in 2004 associated with the CrossCountry Energy integration; and

·   Lower LNG power costs of approximately $1.5 million due to lower LNG volumes received in 2005.

The following items caused a negative impact in 2005 versus 2004:

·   The higher net recovery of previously under-recovered fuel volumes of approximately $4.2 million in 2004;

·   Higher expense of approximately $7 million related to repair of damages directly associated with Hurricanes Katrina and Rita;

·   Higher depreciation and amortization of $5.2 million primarily due to depreciation associated with normal property, plant and equipment growth of approximately $2 million and a $3.2 million acquisition adjustment recorded by Southern Union in 2004 reducing customer contracts value and related amortization; and

·   An increase of $1.4 million in property tax assessments in 2005 related to higher utility income.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. The $1.2 million reduction in EBIT in the six-month period ended December 31, 2004 versus the same period in 2003 was primarily due to the following items:

·   Recognition of a $6.1 million non-recurring gain in 2003 on the early extinguishment of debt;

·   Reservation revenues were $4.6 million lower in 2004 primarily due to the replacement of expired Trunkline contracts during 2004 at lower average reservation rates than were in effect in 2003 due to market driven factors;

·   LNG terminalling revenues were $1.6 million lower due to decreased LNG cargo volumes received;

·   Net commodity revenues increased in 2004 by $4.1 million primarily due to higher parking revenue of $6.5 million, partially offset by the impact of a six percent reduction in throughput volumes associated with a cooler winter during 2003 versus 2004;

·   Operating expenses were higher by $2 million in 2004 primarily due to increased insurance and severance-related costs of $3 million and $1.7 million, respectively, partially offset by the net over-recovery of approximately $2 million in 2004 of previously under-recovered fuel volumes and a $1.3 million reduction in contract storage expenses due to a reduction in contracted storage capacity;

·   Decrease in depreciation and amortization expense of $3 million in 2004 versus 2003 was primarily due to preliminary purchase price allocations relating to the Panhandle acquisition used in 2003 that were subsequently revised in 2004; and

·   Realization of equity earnings from CCE Holdings of $4.6 million for the period subsequent to the acquisition on November 17, 2004.

Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. The results of operations provided by Southern Union Gas Services have been included in the Consolidated Statement of Operations since its March 1, 2006 acquisition.

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

	Inception Through
Gathering and Processing Segment	December 31, 2006 (1)
	(In thousands)
Operating revenues	$	1,090,216
Cost of gas and other energy		(918,064	)
Operating expenses		61,428
Depreciation and amortization		47,321
Taxes other than on income and revenues		2,156
Total operating income		61,247
Earnings (loss) from unconsolidated investments		(188	)
Other income, net		1,571
EBIT	$	62,630
(1) Represents results from operations for the period subsequent to the March 1, 2006 acquisition.

A significant portion of Southern Union Gas Services’ margin is impacted by natural gas commodity prices. As natural gas and natural gas liquid commodity prices increase, Southern Union Gas Services’ margin generally increases. Southern Union Gas Services’ results of operations for the period from the March 1, 2006 acquisition to December 31, 2006 were favorably impacted by larger processing spreads associated with higher natural gas liquids prices, partially offset by low natural gas prices and certain operating expense increases currently being experienced by the energy sector.

Because 53 percent of its sales contracts were percentage of proceeds contracts, Southern Union Gas Services benefited from higher average natural gas liquids prices of $0.945/Mt. Belvieu gallon in the 2006 period subsequent to the March 1, 2006 acquisition compared to approximately $0.88/Mt. Belvieu gallon during the same period in 2005. This favorable impact was somewhat offset by lower average natural gas prices of $5.78/MMBtu at Waha in the same 2006 period compared to record high prices of approximately $7.98/MMBtu in the same period in 2005. As discussed below, the Company is managing its commodity pricing risk through its purchase of commodity-based put options.

Operating expenses for the period subsequent to the March 1, 2006 acquisition were somewhat higher compared to previous years primarily due to higher prices for lubricants, motor fuels, steel products and related materials. Increased energy prices were the primary underlying cause of these price increases.

The Company has purchased commodity-based put options to reduce the downside commodity price risk of the Southern Union Gas Services business. Certain put options have been designated as cash flow hedges in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (Statement No. 133). Changes in fair value of the put options designated as hedges are recorded in Accumulated other comprehensive loss and reclassified to earnings in the period the sales occur. For the year ended December 31, 2006, the Company reclassified into Operating revenues of the Gathering and Processing segment $11.4 million ($7.1 million, net of tax), of previously deferred gains recorded in Accumulated other comprehensive loss. During 2007, the Company expects that all of the $8.5 million ($5.3 million, net of tax) gain included in its Accumulated other comprehensive loss balance at December 31, 2006 will be reclassified into earnings. During the year ended December 31, 2006, the Company realized $74.2 million in settlement value associated with the hedged put options. 

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Southern Union Gas Services has also purchased certain derivatives that have not been designated as accounting hedges. For the year ended December 31, 2006, a gain of $1.2 million was recorded for the non-hedging derivatives.

For further information related to Southern Union Gas Services’ commodity-based put options, see Item 8. Financial Statements and Supplementary Data, Note 11 - Derivative Instruments and Hedging Activities -Gathering and Processing Segment.

Distribution Segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, and Massachusetts. The Company’s utilities 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 utilities operations are generally 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. For additional information concerning risks applicable to the Distribution segment, see Item 1A. Risk Factors - Risks that Relate to the Company’s Distribution Business.

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

										Six Months Ended
	Years Ended December 31,									December 31,
							2004						2003
Distribution Segment	2006			2005			(Unaudited)			2004			(Unaudited)
	(In thousands)
Net operating revenues (1)	$	174,584		$	184,257		$	171,923		$	75,266		$	68,743
Operating expenses		90,178			87,306			92,763			45,353			38,024
Depreciation and amortization		30,353			29,447			29,866			16,527			13,243
Taxes other than on income
and revenues		10,040			3,208			14,071			7,723			5,508
Total operating income		44,013			64,296			35,223			5,663			11,968
Other income (expenses), net		(2,130	)		(2,598	)		(2,788	)		(1,397	)		437
EBIT	$	41,883		$	61,698		$	32,435		$	4,266		$	12,405
(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.

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

Year ended December 31, 2006 versus the year ended December 31, 2005. The $19.8 million EBIT reduction in the year ended December 31, 2006 versus the same period in 2005 was primarily due to the following items:

·   Net operating revenues were $9.7 million lower primarily due to a 9 percent reduction in consumption volumes resulting from the warmer than normal weather, as evidenced by a 15 percent reduction in degree days;

·   Higher taxes other than on income and revenues of $6.8 million primarily due to refunds received for Missouri property tax settlements in 2005; and

·   Higher operating expenses of $2.9 million primarily due to higher bad debt expenses of $900,000 due to the residual effects of higher gas prices in the 2005 to 2006 winter season and higher general expenses in 2006 of $1.3 million primarily due to higher corrosion control costs resulting from drier weather in 2006 compared to 2005.

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Year ended December 31, 2005 versus the year ended December 31, 2004. EBIT for the Distribution segment improved by $29.3 million in 2005 compared with 2004. The EBIT improvement was primarily due to the following items:

·   Net operating revenue increased by approximately $12.3 million primarily due to Missouri Gas Energy’s higher average rates in 2005 based on the $22.4 million MPSC base revenue rate order authorization in October 2004;

·   Operating expenses were lower by $5.5 million primarily due to the net deferral of approximately $6.6 million of pension expense for Missouri Gas Energy associated with the October 2004 MPSC rate order authorization and approximately $2.1 million of lower bad debt expense primarily as a result of more aggressive collection efforts in 2005, partially offset by approximately $1.7 million of insurance costs primarily due to higher claims in 2005; and

·   Taxes other than on income and revenues were approximately $10.9 million lower primarily due to property tax refunds for the years 2002 to 2004 received by Missouri Gas Energy during 2005.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. The $8.1 million EBIT reduction for the six-month period ended December 31, 2005 compared with the same period in 2004 is primarily due to the following items:

·   Bad debt expense increased $2.6 million resulting from higher uncollected customer receivables due to rising gas prices during 2004;

·   Pension and other postretirement benefit costs increased $1.6 million in the 2004 period primarily due to the impact of stock market volatility on plan assets;

·   Outside service costs increased $1.2 million in the 2004 period for costs related to increased collection agency fees, distribution system inspection fees and fees associated with Sarbanes-Oxley documentation and compliance efforts;

·   An increase of $1 million in other net operating costs in the 2004 period primarily due to general wage increases, increased overtime costs associated with distribution system maintenance and Sarbanes-Oxley related costs;

·   Higher depreciation and amortization expense of $3.3 million principally related to a charge taken in the 2004 period to write off certain capitalized software costs, in addition to normal plant growth; and

·   Taxes other than on income and revenues, principally consisting of property, payroll and state franchise taxes, increased $2.2 million, primarily due to a $2 million increase in the 2004 period in property taxes in the Company’s Missouri service territory.

Such EBIT reduction was partially offset by an increase of $6.5 million in net operating revenue primarily due to the positive impact of the $22.4 million annual increase to base revenues granted to Missouri Gas Energy by the MPSC, effective October 2, 2004.

Corporate and Other

Year ended December 31, 2006 versus the year ended December 31, 2005. The $25.7 million EBIT improvement for the year ended December 31, 2006 versus the same period in 2005 was primarily due to the following items:

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

·   Negative impact of $12.8 million of executive bonus compensation awarded and paid in 2006;

·   Negative impact of a $6.5 million write-down in the carrying value of the Scranton corporate building recorded in 2006;

·   Negative impact of $1.4 million of corporate stock-based compensation costs resulting from the implementation of and accounting under Statement No. 123R in 2006;

·   Impact of $3.8 million of non-cash compensation expense in the third quarter of 2005 related to separation agreements with former executives of the Company; and

·   Charges of $6.3 million in the first quarter of 2005 to: (i) reserve for an other-than-temporary impairment in the Company’s investment in a technology company, and (ii) record a liability for the guarantee by a subsidiary of the Company of a line of credit between the technology company and a bank.

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Year ended December 31, 2005 versus the year ended December 31, 2004.EBIT improved by $13.2 million in 2005 compared with 2004 primarily due to the following items:

·   Recognition of a $4.3 million management fee for services provided under a management agreement with CCE Holdings;

·   The incurrence in 2004 of a charge of $16.4 million for an other-than-temporary impairment of the Company’s investment in a technology company;

·   A $1.5 million charge in 2004 related to a sales and use tax audit;

·   A charge of $3 million recorded by PEI Power Corporation in 2004 to provide for estimated debt service payments in excess of projected tax revenues for the incremental financing obtained for the development of PEI Power Park;

·   Additional charges of $6.3 million recorded in 2005 to reserve for an other-than-temporary impairment of the Company’s investments in technology companies;

·   Noncash compensation expense incurred in 2005 totaling $3.8 million related to separation agreements with former executives of the Company; and

·   Increased pension expense incurred in 2005 of $3.1 million, including $1.3 million of curtailment losses from a plan termination and a $1.1 million curtailment loss associated with a payment obligation to a former executive of the Company.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. EBIT was reduced in the six-month period ended December 31, 2004 compared with the same period ended December 31, 2003 by $12.2 million primarily due to the following items:

·   A charge of $16.4 million in 2004 for an other-than-temporary impairment of the Company’s investment in a technology company;

·   A charge of $1.5 million recorded by PEI Power Corporation in 2004 to provide for estimated future debt service payments in excess of projected tax revenues for the tax incremental financing obtained for the development of PEI Power Park; and

·   Charges of $1.6 million and $1.2 million recorded in the 2003 period for an other-than-temporary impairment of the Company’s investments in a technology company and an energy-related joint venture, respectively.

Interest Expense

Year ended December 31, 2006 versus the year ended December 31, 2005.Interest expense was $81.6 million higher in 2006 compared with 2005 primarily due to:

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

·   Increased interest expense of $10.8 million related to Panhandle debt primarily due to higher average interest rates in 2006 versus 2005;

·   Interest expense of $2.5 million under the $465 million 2006 Term Loan;

·   Interest expense of $8.3 million related to the $600 million Junior Subordinated Notes issued in 2006; and

·   Increased interest expense of $4.4 million associated with borrowings under the Company’s credit agreements primarily due to higher average outstanding balances and higher interest rates in 2006 compared to 2005.

The Company used the approximately $1.1 billion in 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 pay down a portion of the $1.6 billion Sid Richardson Bridge Loan during the third quarter of 2006. The Sid Richardson Bridge Loan was retired in October 2006 with debt financing. See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt.

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Year ended December 31, 2005 versus the year ended December 31, 2004.Interest expense was $8.7 million higher in 2005 compared with 2004 primarily due to the following items:

·   Increased interest expense of $3.9 million related to the issuance of the Company’s 4.375% Senior Notes in February 2005;

·   Increased interest expense of $6.5 million related to increased costs for borrowings under the Company’s credit agreements, primarily due to the increase in the average amount of short-term debt outstanding from $125.8 million in 2004 to $234.2 million in 2005, principally as a result of increases in the cost of natural gas purchased for the Distribution operations, and the increase in the average interest rate on such debt from 2.2% in 2004 to 4.0% in 2005;

·   Increased interest expense of $373,000 recorded in 2004 related to the $407 million bridge loan used to finance a portion of the Company’s investment in CCE Holdings; and

·   Decreased interest expense of $2.1 million on the $311.1 million bank note (2002 Term Note) primarily due to the $76.1 million payoff of the 2002 Term Note in June 2005.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. Interest expense was $1.7 million lower in the six-month period ended December 31, 2004 compared with the same period ended December 31, 2003 primarily because of the following items:

·   Dividends on preferred securities decreased $3.2 million due to the redemption of the preferred securities on October 31, 2003 (see Item 8. Financial Statements and Supplementary Data, Note 12 - Preferred Securities);

·   Decreased interest expense of $530,000 on the 2002 Term Note due to the principal repayment of $85 million on the 2002 Term Note since December 31, 2003;

·   Increased interest expense of $2.7 million recorded in 2004 related to the $407 million bridge loan used to finance a portion of the Company’s investment in CCE Holdings;

·   Increased interest expense in 2004 on Panhandle Energy’s debt of $801,000 (net of amortization of debt premiums established in purchase accounting related to the Panhandle Energy acquisition); and

·   Lower interest expense on short-term debt primarily due to the decrease in the average amount of short-term debt outstanding from $240.3 million during 2003 to $121.7 million during 2004. The decrease in the average amount of short-term debt outstanding was primarily due to cash generated from operations and the excess proceeds from capital market issuances over the amounts used for the redemption of securities.

Federal and State Income Taxes from Continuing Operations

Year ended December 31, 2006 versus the year ended December 31, 2005. The effective federal and state income tax rate (EITR) from continuing operations for the years ended December 31, 2006 and 2005 was 33 percent and 25 percent, respectively. The fluctuation in the EITR from continuing operations was primarily due to:

·   The release in 2005 of an $11.9 million valuation allowance, which was originally established in 2004 for a deferred tax asset related to the difference between the book and tax basis of the Company’s investment in CCE Holdings. The Company determined that this valuation allowance was no longer necessary because the book income from CCE Holdings was substantially greater than the taxable income for 2005 and was expected to continue to be higher for the foreseeable future;

·   The release in 2006 of $9.4 million of tax reserves 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; and

·   $5.4 million of additional taxes resulting from the $14.5 million of non-deductible executive compensation paid in 2006.

Year ended December 31, 2005 versus the year ended December 31, 2004. The effective federal and state income tax rate for the years ended December 31, 2005 and December 31, 2004 was 25 percent and 43 percent, respectively. The fluctuation in the EITR from continuing operations was primarily due to:

·   Establishment of a valuation allowance of $11.9 million in 2004 for a deferred tax asset related to the difference between the book and tax basis of the Company’s investment in CCE Holdings and the release of this valuation allowance in 2005 as discussed above; and

·   An adjustment of $6.4 million to lower income tax expense in 2005 resulting from the Company’s analysis of its deferred income tax accounts. This decrease was primarily due to bad debt reserves and property, plant and equipment.

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Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. The increase in the effective federal and state income tax rate to 58 percent for the six-month period ended December 31, 2004 versus 41 percent for the same period ended December 31, 2003 was primarily the result of the $70 million taxable dividend paid by Citrus to CCE Holdings on November 17, 2004. CCE Holdings used the dividend to fund a portion of its acquisition of CrossCountry Energy. The Company recorded $2.5 million of tax expense on its 50 percent share of the dividend, which includes the establishment of a valuation allowance related to the difference between the book and tax basis of the Company’s investment in CCE Holdings net of the benefit of a dividends received deduction.

Internal Revenue Service 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. The Company paid $12.6 million of income tax in November 2006 and expects to receive a $1 million refund of income tax and pay $2.2 million of accrued interest in 2007 with respect to this settlement. The Company estimates the additional state liability to be approximately $1.9 million plus interest to be paid in 2007. 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.

Net Earnings from Discontinued Operations

Year ended December 31, 2006 versus the year ended December 31, 2005.Earnings from discontinued operations before incometaxes for the year ended December 31, 2006 versus the same period in 2005 were $109.2 million higher primarily due to the $175 million goodwill impairment recognized in 2005, partially offset by a loss of $56.8 million resulting from the sales of the assets in 2006 and lower earnings of $8.9 million primarily due to the inclusion of a full year of activity in 2005 versus activity only through August 24 in 2006. Significant components contributing to the $56.8 million loss include $19.4 million of asset impairment charges related to increases in plant, property and equipment during 2006, selling costs of $4.7 million, and charges associated with pre-closing arrangements between the Company and UGI Corporation and National Grid USA, principally consisting of $15.1 million of pension funding requirements and $5.8 million of premiums related to early retirement of debt.

As of December 31, 2006, the working capital adjustment related to the sale of the assets of the PG Energy natural gas distribution division has not been finalized. The ultimate effect of this adjustment, once completed, is not expected to materially affect the Company’s results from discontinued operations.

The Company’s EITR from discontinued operations was significantly higher in 2006 compared to 2005 primarily due to the following items that resulted from 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:

·   The Company incurred $142.4 million of income tax expense in 2006 resulting from $379.8 million of non-deductible goodwill related to the disposition of these assets in 2006 compared to $65.6 million of income tax expense resulting from $175 million of non-deductible goodwill impairment related to these assets recorded in 2005; and

·   The Company incurred income tax expense of $17.6 million in 2006 as a result of the write-off of a tax-related regulatory asset of PG Energy.

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Year ended December 31, 2005 versus the year ended December 31, 2004.Net earnings from discontinued operations decreased $176.9 million in the year ended December 31, 2005 compared with the same period in 2004. The decrease of $179.8 million in Earnings from discontinued operations before income taxes was primarily due to the impact of the goodwill impairment charge of $175 million resulting from the executed agreements for the sale of the assets of the PG Energy natural gas distribution division and the Rhode Island oeprations of the New England Gas Company natural gas distribution division. The effective federal and state income tax rate for the years ended December 31, 2005 and December 31, 2004 was (19) percent and 35 percent, respectively. The fluctuation was primarily due to the impact of the goodwill impairment charge, which is not tax deductible.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. Net earnings from discontinued operations decreased $5.1 million for the six-month period ended December 31, 2004 compared with the same period in 2003. The decrease of $8.4 million in Earnings from discontinued operations before income taxes was primarily due to increased environmental site remediation costs of approximately $6.6 million related to mercury remediation at New England Gas Company. The effective federal and state income tax rate for the six months ended December 31, 2004 and December 31, 2003 was 34 percent and 36 percent, respectively.

Preferred Stock Dividends

There is no change in dividends on preferred securities for the years ended December 31, 2006, 2005 and 2004.

Dividends on preferred securities for the six-month period ended December 31, 2004 versus the same period in 2003 increased by $4.7 million due to the Company’s issuance of $230 million of 7.55% Non-Cumulative Preferred Stock, Series A on October 8, 2003. See Item 8. Financial Statements and Supplementary Data, Note 12 - Preferred Securities.

LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity. Additional sources of liquidity include use of available credit facilities, various equity offerings, project and bank financings, issuance of long-term debt and proceeds from asset dispositions. The availability and terms of any such financing sources 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. Acquisitions, which generally require a substantial increase in expenditures, and related financings also affect the Company's combined results due to factors such as the Company's ability to realize any anticipated benefits from the acquisitions, successful integration of new and different operations and businesses and effects of different regional economic and weather conditions. Future acquisitions or related financings or refinancings may involve the issuance of shares of the Company's common stock, which could have a dilutive effect on the then-current stockholders of the Company.

Operating Activities

Year ended December 31, 2006 versus the year ended December 31, 2005. Cash flows provided by operating activities were $458.8 million for the year ended December 31, 2006 compared with cash flows provided by operating activities of $218.6 million for the same period in 2005. Cash flows provided by operating activities before changes in operating assets and liabilities for 2006 were $393.6 million compared with $356.6 million for 2005. Changes in operating assets and liabilities provided cash of $65.2 million in 2006 and used cash of $138 million in 2005, resulting in an increase in cash of $203.2 million in 2006 compared to 2005. The $203.2 million increase in cash is primarily due to the receipt in 2006 of $74.2 million from cash settlements of put options versus the purchase of $49.7 million of put options in 2005, higher net accounts receivable resulting from increased billings due to improved earnings and other increases of operating activities from the Gathering and Processing segment, partially offset by increased usage of cash primarily related to the replenishment of natural gas inventory levels in the 2006 period compared to 2005.

Year ended December 31, 2005 versus the year ended December 31, 2004. Cash flows provided by operating activities were $218.6 million for the year ended December 31, 2005 compared with cash flows provided by operating activities of $324.1 million for the same period in 2004. Cash flows provided by operating activities before changes in operating assets and liabilities for 2005 were $356.6 million compared with $297 million for 2004. Changes in operating assets and liabilities used cash of $138 million in 2005 and provided cash of $27.1 million in 2004. The financing of the high accounts receivable balance and funds expended for replenishing natural gas stored in inventory, both of which occurred due to higher gas costs during 2005 compared to 2004, negatively impacted working capital to a greater extent in 2005 than 2004. Additionally, the Company purchased $49.7 million of put options in December 2005 in conjunction with its March 1, 2006 acquisition of the Sid Richardson Energy Services business. See related discussion in Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company also used more cash related to deferred charges and credits in 2005 than 2004. These amounts were somewhat offset by growth in cash provided by accounts payable, deferred purchased gas costs and an increase in cash provided by changes in prepaids and other assets.

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Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. Cash flows used in operating activities were $27.3 million for the six months ended December 31, 2004 compared with cash flows used in operating activities of $20.1 million for the same period in 2003. Cash flows provided by operating activities before changes in operating assets and liabilities for 2004 were $111.9 million compared with $117.6 million for 2003. Changes in operating assets and liabilities used cash of $139.2 million in 2004 and $137.7 million in 2003. The high accounts receivable balance that occurred due to high gas costs during both 2004 and 2003 and funds expended for replenishing natural gas stored in inventory, negatively impacted working capital in both 2004 and 2003. These amounts were somewhat offset by growth in cash provided by accounts payable, net gas imbalances and deferred charges and credits.

Investing Activities

Summary

The Company’s business strategy includes making prudent capital expenditures across its base of interstate transmission, gathering, processing 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.

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Cash flow changes associated with these objectives resulted primarily from the $1.54 billion (net of $53.2 million cash received) March 1, 2006 acquisition of Sid Richardson Energy Services, the change in ownership interests of CCE Holdings resulting from the closing of the transactions under the Redemption Agreement on December 1, 2006, and the ongoing expansion of the Company’s existing asset base through additions to property, plant and equipment in 2006. 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.

					Six months		Year
	Years ended				Ended		Ended
	December 31,				December 31,		June 30,
Property, Plant and Equipment Additions	2006		2005		2004		2004
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions	$	57,045	$	75,263	$	51,751	$	65,260
Trunkline LNG Loop		3,173		25,329		17,647		3,675
Trunkline LNG Field Zone Expansion		12,314		169		-		-
Pipeline Integrity		20,223		21,816		11,278		18,378
East End Enhancement		52,102		1,012		-		-
Information Technology		14,142		6,162		2,762		10,696
Hurricanes		20,296		900		-		-
Compression Modernization		11,642		-		-		-
Air Emission Compliance		15,346		11,481		5,015		2,694
Other		38,538		47,283		23,433		30,675
Total		244,821		189,415		111,886		131,378
Gathering and Processing Segment (1)		35,101		-		-		-
Distribution Segment
Missouri Safety Program		11,592		11,426		4,653		6,878
Other, primarily system replacement
and expansion		36,362		73,470		51,789		71,913
Total		47,954		84,896		56,442		78,791
Corporate and other		4,798		2,306		10,109		15,884
Total (2)	$	332,674	$	276,617	$	178,437	$	226,053
(1) Reflects expenditures for the period subsequent to the March 1, 2006 acquisition of Sid Richardson Energy
Services versus the year ended December 31, 2006.
(2) Includes net capital accruals totaling $14.9 million, $(3.1) million, $7.8 million and $12.1 million for the years ended
2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively.

Principal Capital Expenditure Projects

The following is a summary of the Company’s principal capital expenditure projects.

LNG Terminal Enhancement. The Company has received approval from FERC and commenced construction of an additional enhancement at its Trunkline LNG terminal. This infrastructure enhancement project, which is expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. The project is expected to be in operation in 2008. Approximately $40.8 million and $9.4 million of costs are included in the line item Construction work-in-progress at December 31, 2006 and 2005, respectively.

Compression Modernization. The Company has received approval from FERC to modernize and replace various compression facilities on PEPL. Such replacements will be made at 12 different compressor stations and are expected to be installed by the end of 2009. The estimated cost of these replacements is approximately $290 million, which includes the compression component of a PEPL east end enhancement project already under construction. The Company has also filed for FERC approval to replace approximately 32 miles of existing pipeline on the east end of the PEPL system at an estimated cost of approximately $60 million, which would further improve system integrity. The project is planned to be completed in late 2007. Approximately $11.6 million and $46.3 million of costs, related to the compression modernization and east end enhancement projects, respectively, are included in the line item Construction work-in-progress at December 31, 2006.

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Trunkline Field Zone Expansion Project. Trunkline has announced a field zone expansion project, which includes adding capacity to its pipeline system in Texas and Louisiana to increase deliveries to Henry Hub. The field zone expansion project includes the previously announced north Texas expansion as well as additional capacity to Henry Hub. Trunkline will increase the capacity along existing rights of way from Kountze, Texas, to Longville, Louisiana, by approximately 510 million cubic feet per day with the construction of approximately 45 miles of 36-inch diameter pipeline. The project includes horsepower additions and modifications at existing compressor stations. Trunkline also will create 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 will provide capacity of 475 million cubic feet per day from Kaplan, Louisiana to Henry Hub. Trunkline filed the project with FERC on September 11, 2006 with an anticipated in-service date during the fourth quarter of 2007. The cost estimate has been revised to approximately $200 million, plus capitalized interest, including a $40 million contribution in aid of construction (CIAC) to a subsidiary of Energy Transfer toward construction costs to be incurred by Energy Transfer to move its delivery point to a location near Buna, Texas, increasing the field zone project capacity by up to 330,000 dekatherms per day. The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer, additional capacity created, and sale by Trunkline of the additional capacity. Approximately $12.5 million of costs for this project are included in the line item Construction work-in-progress at December 31, 2006.

Hurricane-Related Expenditures. Late in the third quarter of 2005, after coming through the Gulf of Mexico, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast. These hurricanes caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG and construction project delays at the Trunkline LNG terminal. As of December 31, 2006, the Company has incurred capital expenditure outlays of $30.8 million primarily related to replacement or abandonment of damaged property and equipment and incremental Trunkline LNG terminal construction costs. Estimated capital outlays of approximately $9.3 million are expected in early 2007.

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from Hurricane Rita in excess of its $5 million deductible. Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1 billion total limit on payout per claim. As of December 31, 2006, the Company has received payments of $1.6 million from the insurance carriers. No receivables due from the insurance carriers have been recorded as of December 31, 2006.

In addition, after the 2005 hurricanes, the Mineral Management Service mandated inspections by leaseholders and pipeline operators along the hurricane tracks. The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be re-covered to comply with applicable regulations. Capital expenditures are estimated at $4.8 million, $1.1 million of which had been incurred as of December 31, 2006. The Company will seek recovery of these capital and other related expense amounts as part of the hurricane related claims.

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 $11.6 million in 2006 related to this program and estimates incurring approximately $135.8 million over the next 13.5 years, after which all service lines, representing about 50 percent of the annual safety program investment, will have been replaced.

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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.

Financing Activities

Summary

The Company continues to pursue opportunities to enhance its credit profile by reducing its ratio of total debt to total capital. At December 31, 2006, the Company’s ratio of total debt to total capital was 61 percent. The issuance of common stock, equity units and preferred stock and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with acquisitions is continued evidence of the Company’s commitment to strengthen its balance sheet and solidify its current investment grade status.

On March 1, 2006, in connection with its purchase of Sid Richardson Energy Services, the Company entered into the $1.6 billion Sid Richardson Bridge Loan in order to provide temporary financing. The Sid Richardson Bridge Loan was repaid primarily with the proceeds from the 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, with the balance being repaid through the issuance of debt. For additional information, see Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations.

Cash flows provided by financing activities were $336.8 million for the year ended December 31, 2006 compared with $50.8 million for the same period in 2005. Financing activity cash flow changes were primarily due to the net impact of acquisition financing and the repayment of such debt, net borrowings under the revolving credit facilities and the payment of common and preferred stock dividends.

Cash flows provided by financing activities were $50.8 million for the year ended December 31, 2005 compared with $575.6 million for the same period in 2004. Financing activity cash flow changes were primarily due to the net impact of acquisition financing, repayment of debt, net borrowings under the revolving credit facilities, issuance of common stock and the redemption of preferred securities of the Company’s subsidiary trust.

Cash flows provided by financing activities were $815.1 million for the six months ended December 31, 2004 compared with $60.3 million for the same period in 2003. Financing activity cash flow changes were primarily due to the net impact of acquisition financing, repayment of debt, net borrowings under the revolving credit facilities, issuance of common stock and the redemption of preferred securities of the Company’s subsidiary trust.

Common Stock, Equity Units and Preferred Stock Issuances

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. The Senior Notes will mature on August 16, 2008.  On August 16, 2006, the Company issued 7,413,074 shares of common stock for $125 million in conjunction with the remarketing of its 2.75% Senior Notes. See Note 13 - Debt Obligations - Long-Term Debtand Capital Lease Obligations - Remarketing Obligation for additional related information.

On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $97.4 million. Southern Union used the proceeds to repay the balance of the bridge loan used to fund a portion of the Company’s investment in CCE Holdings (CCE Holdings Bridge Loan) and to repay borrowings under its credit facilities. Each 5% Equity Unit consists of a 1/20th interest in a $1,000 principal amount of Southern Union’s 4.375% Senior Notes due 2008 and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $23.44 and $29.30, respectively, which are subject to adjustments for future stock splits or stock dividends). The 5% Equity Units carry a total annual coupon of 5.00 percent (4.375 percent annual face amount of the senior notes plus 0.625 percent annual contract adjustment payments).

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On February 9, 2005, Southern Union issued 14,913,042 shares of its common stock at $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions of $332.6 million. Southern Union used the net proceeds to repay a portion of the CCE Holdings Bridge Loan.

On July 30, 2004, the Company issued 4,800,000 shares of common stock at the public offering price of $18.75 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $86.6 million. The Company also sold 6,200,000 shares of the Company’s common stock through forward sale agreements with its underwriters and granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,650,000 shares of the Company’s common stock at the same price, which was exercised by the underwriters. At settlement, which occurred on November 16, 2004, Southern Union received approximately $142 million in net proceeds upon the issuance of 8,242,500 shares of common stock. The total net proceeds from the settlement of the forward sale agreements were used to fund a portion of the Company’s equity investment in CCE Holdings.

On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public through the issuance of 9,200,000 Depositary Shares, each representing a one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at the public offering price of $25.00 per share, or $230 million in the aggregate. After the payment of issuance costs, including underwriting discounts and commissions, the Company realized net proceeds of $223.4 million. The total net proceeds were used to repay debt under the Company’s revolving credit facilities.

Debt Refinancing, Repayment and Issuance Activity

LNG Holdings Term Loan. In connection with the December 1, 2006 closing of the transactions contemplated by the Redemption Agreement, LNG Holdings, an indirect wholly-owned subsidiary of the Company, as borrower, and PEPL and CrossCountry Citrus, each an indirect wholly-owned subsidiary of the Company, as guarantors, entered into the $465 million 2006 Term Loan due April 4, 2008. The interest rate under the 2006 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 the Company’s unsecured senior funded debt. At December 31, 2006, the interest rate was 6.22 percent, including a credit spread over LIBOR of 87.5 basis points.  The proceeds of the 2006 Term Loan were used to repay the approximately $455 million of indebtedness of Transwestern Holding, a wholly-owned subsidiary of CrossCountry Energy and certain other obligations of Transwestern Holding.

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. The outstanding balance of $525 million on the Sid Richardson Bridge Loan discussed below was retired using the proceeds from the debt offering and the remaining approximately $65 million of debt offering proceeds were used 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 and Capital Lease Obligations - Junior Subordinated Notes.

Sid Richardson Bridge Loan. On March 1, 2006, Southern Union acquired Sid Richardson Energy Services 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.

Interest expense totaling $49.2 million related to the Sid Richardson Bridge Loan was incurred during 2006 at an average interest rate of 5.72 percent. Debt issuance costs totaling $9.2 million were incurred in connection with the financing of the acquisition, of which $7.8 million was related to the Sid Richardson Bridge Loan and $1.4 million was related to the placement of permanent financing. The Company fully amortized the $7.8 million of the Sid Richardson Bridge Loan debt issuance cost to interest expense during 2006.

Credit Facilities. On September 29, 2005, the Company entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400 million (Long-Term Facility). The Long-Term Facility has a five-year term and matures on May 28, 2010. The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount. Borrowings under the Long-Term Facility are available for Southern Union’s working capital and letter of credit requirements and other general corporate purposes. The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (Senior Notes). As of December 31, 2006, the commitment fees were an annualized 0.15 percent. The Company has additional availability under uncommitted lines of credit facilities with various banks.

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Balances of $100 million and $420 million were outstanding under the Company’s credit facilities at effective interest rates of 6.02 percent and 4.73 percent at December 31, 2006 and December 31, 2005, respectively. As of February 16, 2007, there was a balance of $129 million outstanding under the Company’s credit facilities at an average effective interest rate of 6.0 percent.

Other Debt Refinancings, Repayments and Issuances. On July 14, 2005, the Company amended an existing uncommitted short-term bank note to increase the principal amount from $15 million to $65 million in order to provide additional liquidity. The note is repayable upon demand and the Company borrowed $50 million under the note on July 19, 2005 at an initial interest rate of 4.54 percent, which was based upon LIBOR, plus 70 basis points. The Company repaid the $50 million additional principal amount on April 17, 2006.

On April 26, 2005, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a credit agreement, with a consortium of banks for a senior term loan financing in the aggregate principal amount of $255.6 million, maturing on March 15, 2007. The senior term loan carries a floating interest rate tied to LIBOR or prime interest rates at Panhandle’s option, in addition to a margin tied to the rating of Panhandle’s unsecured senior funded debt. On April 29, 2005, the proceeds from the senior term loan were used to repay all outstanding indebtedness under LNG Holdings’ floating rate bank loans that were due in 2007.

On November 17, 2004, a wholly-owned subsidiary of the Company entered into the $407 million CCE Holdings Bridge Loan with a group of three banks in order to provide a portion of the funding for the Company’s investment in CCE Holdings. This loan was repaid in February 2005.

On March 12, 2004, Panhandle issued $200 million of its 2.75% Senior Notes due 2007, the proceeds of which were used to fund the redemption of the remaining $146.1 million principal amount of its 6.125% Senior Notes due 2004 that matured on March 15, 2004 and to provide working capital to the Company. A portion of the remaining net proceeds was also used to repay the remaining $52.5 million principal amount of Panhandle’s 7.875% Senior Notes due 2004 that matured on August 15, 2004.

On October 1, 2003, the Company called its Subordinated Notes for redemption, and its Subordinated Notes and related Preferred Securities were redeemed on October 31, 2003. The Company financed the redemption with borrowings under its revolving credit facilities, which were paid down with the net proceeds of a $230 million offering of preferred stock by the Company on October 8, 2003, as previously discussed.

In July 2003, Panhandle announced a tender offer for any and all of the $747.4 million in principal amount of five of its series of senior notes then outstanding (Panhandle Tender Offer) and also called for redemption of all of the $134.5 million in principal amount of its two series of debentures then outstanding (Panhandle Calls). Panhandle repurchased approximately $378.3 million in principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396.4 million plus accrued interest through the purchase date. Panhandle also redeemed approximately $134.5 million in principal amount of its debentures through the Panhandle Calls for total consideration of $139.4 million, plus accrued interest through the redemption dates. As a result of the Panhandle Tender Offer, the Company recorded a pre-tax gain on the extinguishment of debt of $6.4 million during the year ended June 30, 2004. In August 2003, Panhandle issued $300 million of its 4.80% Senior Notes due 2008 and $250 million of its 6.05% Senior Notes due 2013, principally to refinance the repurchased notes and redeemed debentures. Also in August and September 2003, Panhandle repurchased $3.2 million in principal amount of its senior notes on the open market through two transactions for total consideration of $3.4 million, plus accrued interest through the repurchase date.

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Expected Refinancing and Other Debt Matters

Expected Refinancing.The Company plans to refinance its debt coming due in March 2007 with proceeds from a $455 million multi-year bank term loan to LNG Holdings (2007 Expected TLNG Term Loan). The Company is near the final stages of consummating this refinancing, which is expected to close on or about March 12, 2007. The Company will use Wachovia Capital Markets and UniCredit Markets and Investment Banking as lead arrangers for the 2007 Expected TLNG Term Loan, which will be guaranteed by PEPL and Trunkline LNG. Borrowings based on the current term sheet under the 2007 Expected TLNG Term Loan will bear interest at LIBOR, plus a credit spread based on the senior unsecured credit ratings by Standard & Poor’s and Moody’s Investors Service for PEPL. Should the Company not be successful in the aforementioned refinancing effort, the Company would implement alternative refinancing plans, including a combination of drawing down on its existing revolving credit facility, utilizing cash from operations and additional commitments from third-party lenders, which are subject to material adverse change clauses and other customary terms and conditions, to repay the March 2007 obligations at maturity in the event the 2007 Expected TLNG Term Loan is not completed in the required timeframe.

The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital 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 these obligations under acceptable terms within the required timeframes. However, there can be no assurance the Company will be successful in its implementation of these refinancing plans and the Company’s inability to do so would cause a material adverse change to the Company’s financial condition.

Credit Ratings. On November 29, 2006, Standard & Poor’s Ratings Services lowered its corporate credit ratings on Southern Union and its subsidiary PEPL to BBB- from BBB. At the same time, Standard & Poor’s removed the ratings from Creditwatch with negative implications and revised the outlook to stable.  On December 19, 2005, Moody’s Investor Services, Inc. placed the Company on review for possible downgrade in connection with the announcement of the acquisition of the Sid Richardson Energy Services business.  On December 7, 2006, Moody’s Investor Services, Inc. affirmed the Baa3 rating, but also retained the negative outlook.  Fitch Ratings placed the Company on Rating Watch Negative on December 16, 2005, in connection with the announcement of the acquisition of Sid Richardson Services.  On September 15, 2006, Fitch Ratings, Inc. affirmed the Company’s BBB rating and retained the stable outlook.

OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

As of December 31, 2006, the Company had guarantees related to PEI Power Corporation of $5.8 million, letters of credit related to insurance claims and other commitments of $8.7 million and surety bonds related to construction or repair projects of approximately $4.3 million. The Company believes that the likelihood of having to make payments under the letters of credit or the surety bonds is remote, and therefore has made no provisions for making any such payments.

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The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2006:

	Contractual Obligations (In thousands)
													2012 and
	Total		2007		2008		2009		2010		2011		thereafter
Long-term debt,
including capital leases (1), (2)	$    3,142,319		$       462,290		$       983,336		$         60,623		$         40,500		$                   -		$    1,595,570
Short-term borrowing,
including credit facilities (1)		100,000		100,000		-		-		-		-		-
Gas purchases (3)		889,372		284,637		247,682		201,487		155,566		-		-
Missouri Gas Energy Safety Program		135,843		9,448		9,542		9,638		9,734		9,831		87,650
Transportation contracts		387,612		78,068		77,557		71,255		54,900		42,702		63,130
Storage contracts (4)		83,737		14,875		13,389		13,033		10,696		8,944		22,800
Trading and Marketing		1,609		1,454		155		-		-		-		-
Operating lease payments		91,192		18,434		13,625		12,617		11,389		11,087		24,040
Interest payments on debt (5)		4,000,571		189,151		154,843		123,948		118,336		116,666		3,297,627
Benefit plan contributions		31,151		31,151		-		-		-		-		-
Non-trading derivative liabilities		1,265		1,265		-		-		-		-		-
Total contractual cash obligations	$	8,864,671	$	1,190,773	$	1,500,129	$	492,601	$	401,121	$	189,230	$	5,090,817

_________________________

(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. See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations.

(2)   The long-term debt principal payment obligations exclude $9.6 million of unamortized debt premium as of December 31, 2006.

(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, 2006. Includes approximately $2.6 billion of interest payments associated with the $600 million Junior Subordinated Notes due November 1, 2066.

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 has required and will continue to require it to replace assets at higher costs. 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 the Transportation and Storage and Distribution segments in adjusting those rates.

Regulatory

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

Benefit Plan Changes

Panhandle Postretirement Benefits. Certain changes that were approved in the fourth quarter of 2005 relating to Panhandle’s postretirement benefit obligation reduced Panhandle’s accumulated postretirement benefit obligation by approximately $24.3 million in 2005 and future expenses by approximately $1 million per quarter.

Panhandle Vacation Plan. Effective January 1, 2006, non-union employees of Panhandle began earning vacation on a monthly accrual basis versus having their complete vacation entitlement earned at the beginning of the year. At December 31, 2005, Panhandle reduced the previously accrued obligation by $3.8 million to reflect this vacation plan change.

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Critical Accounting Policies

Summary

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. 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 on 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. 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.

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 as discontinued operations. Missouri Gas Energy, PG 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 Sheets applicable to the Distribution segment and discontinued operations are $65.9 million at December 31, 2006 and $113 million at December 31, 2005, 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 Southern Union Gas Services do not currently apply Statement No. 71.

Long-Lived Assets

Long-lived assets, including property, plant and equipment and goodwill, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates about the carrying value 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. The impairment test consists of a comparison of an asset’s fair value with its carrying value; if the carrying value of the asset exceeds its fair value, an impairment loss is recognized in the Consolidated Statement of Operations in an amount equal to that excess. When an asset’s fair value is not readily apparent from other sources, management’s determination of an asset’s fair value requires it to make long-term forecasts of future net cash flows related to the asset. These forecasts require assumptions about future demand, future market conditions and regulatory developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

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As of November 30, 2006, the Company evaluated goodwill for impairment. The determination of whether an impairment has occurred is based on an estimate of discounted future cash flows attributable to the Company’s reporting units that have goodwill, as compared to the carrying value of those reporting units’ net assets. As of November 30, 2006, no impairment was indicated based on FASB Statement No. 142, Goodwill and Other Intangible Assets. Execution of agreements for the sale 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 in the first quarter of 2006 constituted a subsequent event of the type that under generally accepted accounting principles in the United States of America required the Company to consider the fair value indicated by the definitive sale agreements in its 2005 goodwill impairment evaluation. Based on the purchase prices reflected in the definitive agreements, the Company reported a $175 million goodwill impairment in the fourth quarter of 2005.

During 2005, the Company changed the date upon which its annual goodwill impairment assessment is performed from May 31 to November 30 to correspond with the change in fiscal year end and related change in the timing of completing the Company’s annual operating and capital budgets. The Company believes this change is preferable.

Purchase Accounting

The Company’s acquisition of Panhandle and Sid Richardson Energy Services 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 Southern Union 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. Southern Union has generally used outside appraisers to assist in the initial determination of fair value. The appraisals related to Southern Union’s acquisition of Panhandle, CCE Holdings and Sid Richardson Energy Services were finalized in 2004, 2005 and 2006, respectively.

Southern Union 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 accounted for under Accounting Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock, is preliminary and assumes the amount in excess of CCE Holdings’ pre-December 1, 2006 book basis in Citrus is allocable to equity goodwill. For additional information, see Item 8. Financial Statements and Supplementary Data, Note 9 - Unconsolidated Investments - CCE Holdings Goodwill Evaluation.

Pensions and 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. Effective for years ending after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date. The Company has not yet adopted the measurement date provisions of Statement No. 158.

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The Company accounted for the measurement of its defined benefit postretirement plans under Statement No. 87, Employers Accounting for Pensions (Statement No. 87) and Statement No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement No. 106). 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 No. 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 benefit 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 2006 pension expense for continuing operations and PBO at the end of 2006 by $283,000 and $9.5 million, respectively, and would decrease equity at the end of 2006 by $5.9 million.

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 2006 pension expense for continuing operations by $510,000.

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

Derivatives and Hedging Activities

The Company follows Statement No. 133, as amended, to account for derivative and hedging activities. In accordance with this statement 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 non-hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value are 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 income 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 earnings immediately. For derivatives treated as trading or non-hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon mathematical models using current and historical data.

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.

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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 - New Accounting Principles.

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

Debt Obligations. The Company has long-term debt and revolving credit facilities, which subject the Company to the risk of loss associated with movements in market interest rates.

At December 31, 2006, the Company had issued fixed-rate long-term debt aggregating $2.23 billion in principal amount (including premiums on Panhandle’s debt of $9.6 million) and having a fair value of $2.34 billion. These instruments are fixed-rate and, therefore, do not expose the Company to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $144.9 million if interest rates were to decline by ten percent from December 31, 2006 levels. In general, such an increase in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments in the open market prior to their maturity.

The Company's floating-rate obligations aggregated $1.02 billion at December 31, 2006 and primarily consisted of the $200 million Panhandle notes that were swapped to a floating rate, the refinanced LNG Holdings bank loans, and amounts borrowed under the revolving credit facilities. The floating-rate obligations under these agreements expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating rates were to increase by ten percent from December 31, 2006 levels, the Company's consolidated interest expense would increase by a total of approximately $519,000 for each month during which such increase continued.

The risk of an economic loss is reduced at this time as a result of the Company’s regulated status with respect to its Distribution segment operations. Any unrealized gains or losses are accounted for in accordance with Statement No. 71 as a regulatory asset or liability.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2006 is not material to the Company.

See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations.

Commodity Derivative Activities. The Company markets natural gas and natural gas liquids in its Gathering and Processing segment and manages associated commodity price risks using derivative financial instruments. These instruments involve not only the risk of dealing with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations. Under Statement No. 133, the Company is required to record derivative financial instruments at fair value, which is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

The Company uses various derivative financial instruments to manage commodity price risk and to take advantage of pricing anomalies among derivative financial instruments related to natural gas and natural gas liquids. The Company uses a combination of fixed-price physical forward contracts, exchange-traded futures and options, and fixed for floating index and basis swaps to manage commodity price risk. 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 the physical market and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations. The Company does not enter into speculative derivative instruments.

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In connection with its agreement to acquire Sid Richardson Energy Services, now known as Southern Union Gas Services, the Company purchased natural gas put options in December 2005 for $49.7 million based on the price of natural gas in December 2005. The Company believed that given the then relative price of natural gas and natural gas liquids, natural gas was the appropriate commodity to use as a hedging instrument. These commodity options were tied to the WAHA price of natural gas for the monthly delivery periods from March 2006 through December 2007. The put options for 2006 relate to 45,000 MMBtu/day at the price of $11.00 per MMBtu and the put options for 2007 relate to 25,000 MMBtu/day at the price of $10.00 per MMBtu. The objective for purchasing the put options was to reduce the downside commodity price risk of the Southern Union Gas Services business. Prior to the closing of the Company’s acquisition of Sid Richardson Energy Services on March 1, 2006, the put options were required to be accounted for using mark-to-market accounting, with the change in fair value between measurement dates recorded as a gain or loss in current period earnings. The impact on the Company’s results of operations for the January and February 2006 pre-acquisition period was a pre-tax gain of $37.2 million. The gain was recorded in Other, net in the Consolidated Statement of Operations and was not reflected in the results of the Gathering and Processing Segment. There was a similar $1.8 million pre-tax gain in December 2005.

As a result of the required mark-to-market gains, the Company’s basis in the put options was increased to $88.7 million as of March 1, 2006. With the closing of the acquisition on March 1, 2006, the commodity-based put options were designated as cash flow hedges and since that date have been accounted for in accordance with Statement No. 133, with the earnings impact, including amortization of the basis, reflected in the results of the Gathering and Processing segment. In accordance with Statement No. 133, changes in the fair value of the put options that are considered effective will initially be recorded in Accumulated other comprehensive loss, and reclassified to earnings in the period the hedged sales occur. If it is determined that a hedge is not effectively operating as anticipated, income is adjusted to the extent of such ineffectiveness.

In July 2006, Southern Union Gas Services purchased put options for its propane, ethane and crude oil equivalent products for premiums of $2.8 million, $2.7 million and $4.6 million, respectively. The propane put options relate to 122,000 barrels of 2006 production at a strike price of $1.185/gallon and 401,500 barrels of 2007 production at a strike price of $1.1075/gallon. The ethane put options relate to 183,000 barrels of 2006 production at a strike price of $0.81/gallon and 620,500 barrels of 2007 production at a strike price of $0.69/gallon. The crude oil put options relate to 1,058,500 barrels of 2007 production at a strike price of $70.00/barrel. On an energy-equivalent basis, the volumes hedged by these put options were 8,000 MMBtu/day in 2006 and 26,000 MMBtu/day in 2007. The objective for purchasing the put options was to further reduce Southern Union Gas Services’ downside commodity price risk associated with its sales of propane, ethane and other natural gas liquids products, which usually correlate with crude oil. The Company designated the propane and ethane put options as cash flow hedges, which are accounted for in accordance with Statement No. 133. Accordingly, changes in fair value of the put options that are considered effective are initially recorded in Accumulated other comprehensive loss and reclassified to earnings in the period the hedged sales occur. If it is determined that the hedge is ineffective, income is adjusted to the extent of such ineffectiveness.

At December 31, 2006, the Company marked the hedging put options to fair value and recorded a gain for the effective portion of the change in value between measurement dates in Accumulated other comprehensive loss of $19.8 million ($12.4 million, net of tax). The Company recorded a gain of approximately $22,000 related to ineffectiveness of the cash flow hedges. At December 31, 2006, the Company reported the $38.1 million balance, all of which is current, of the fair market value of the put options in the Consolidated Balance Sheet in Prepayments and other assets. During the year ended December 31, 2006, the Company realized $74.2 million in settlement value associated with the hedging put options. For the year ended December 31, 2006, the Company reclassified to earnings $11.4 million ($7.1 million, net of tax) of previously deferred gains recorded in Accumulated other comprehensive loss. Such reclassified earnings were recorded in Operating revenues in the Consolidated Statement of Operations. During 2007, the Company expects that all of the $8.5 million ($5.3 million, net of tax) gain included in the Accumulated other comprehensive loss balance at December 31, 2006 will be reclassified into earnings.

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See Item 8. Financial Statements and Supplementary Data, Note 11 - Derivative Instruments and Hedging Activities - Gathering and Processing Segment.

TIF Debt Guarantee.The Company has a guaranty with a bank whereby the Company unconditionally guaranteed payment of financing obtained for the development of PEI Power Park. In March 1999, the Borough of Archbald, the County of Lackawanna, and the Valley View School District (collectively the Taxing Authorities) approved a Tax Incremental Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan requires that: (i) the Redevelopment Authority of Lackawanna County raise $10.6 million of funds to be used for infrastructure improvements of the PEI Power Park; (ii) the Taxing Authorities create a tax increment district and use incremental tax revenues generated from new development to service the $10.6 million debt; and (iii) PEI Power Corporation, a subsidiary of the Company, guarantee the debt service payments. In May 1999, the Redevelopment Authority of Lackawanna County borrowed $10.6 million from a bank under a promissory note (TIF Debt), which was refinanced and modified in May 2004. Beginning May 15, 2004 the TIF Debt bears interest at a variable rate equal to three-quarters percent (.75 percent) lower than the National Prime Rate of Interest with no interest rate floor or ceiling. The TIF Debt matures on June 30, 2011. Interest-only payments were required until June 30, 2003, and semi-annual interest and principal payments are required thereafter. As of December 31, 2006, the balance outstanding on the TIF Debt was $5.8 million with an interest rate of 7.5 percent. Estimated incremental tax revenues are expected to cover approximately 39 percent of the 2007 annual debt service. Based on information available at this time, the Company believes that the $3.1 million amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2006.

Interest Rate Swaps. Interest rate swaps are used 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 into 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.

On April 29, 2005, the Company refinanced the existing bank loans of LNG Holdings in the amount of $255.6 million, due 2007. See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt Obligations. Interest rate swaps previously designated as cash flow hedges of the LNG Holdings’ bank loans were terminated upon refinancing of the loans. As a result, a gain of $3.5 million ($2.1 million net of tax) was recorded in Accumulated other comprehensive loss during the second quarter of 2005 and is being amortized to interest expense through the maturity date of the original bank loans in 2007. From January 1, 2005 through the termination date of the swap agreements on April 29, 2005, there was no swap ineffectiveness.

In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250 million to manage its exposure against changes in future interest payments attributable to changes in the benchmark interest rate prior to the anticipated issuance of fixed-rate debt. These treasury rate locks expired on June 30, 2003, resulting in a $6.9 million after-tax loss that was recorded in Accumulated other comprehensive loss and will be amortized into interest expense over the lives of the associated debt instruments. As of December 31, 2006, approximately $967,000 of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months.

In March 2004, Panhandle entered into interest rate swaps to hedge the risk associated with the fair value of its $200 million principal amount of 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under Statement No. 133. Under the swap agreements, Panhandle will receive fixed interest payments at a rate of 2.75 percent and will make floating interest payments based on the six-month LIBOR. No ineffectiveness is assumed in the hedging relationship between the debt instrument and the interest rate swap. As of December 31, 2006 and December 31, 2005, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $1.3 million and $5.7 million, respectively.

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.

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Distribution Segment Non-Hedging Activities. During 2006, 2005 and 2004, 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 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, 2006 and December 31, 2005, the fair values of the contracts, which expire at various times through March 2008, are included in the Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $19 million and $17.5 million, respectively.

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 Securities Exchange Act of 1934, as amended (Exchange Act) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company performed an evaluation under the supervision and with the participation of management, including its Chief Executive Officer (CEO) and Chief Financial Officer (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 the evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2006.

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 generally accepted accounting principles, and includes those policies that:

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

·   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

·   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. Additionally, the Company is required to provide an attestation report of the Company’s independent registered public accountant on management’s assessment of internal control over financial reporting.

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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 assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 excluded Southern Union Gas Services, which was acquired on March 1, 2006 and comprises the Gathering and Processing segment. Such exclusion was in accordance with SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal control over financial reporting, provided the acquisition took place within twelve months of management’s evaluation. Collectively, Southern Union Gas Services comprised 25 percent of the Company’s consolidated assets at December 31, 2006 and 47 percent of the Company’s consolidated revenues for the year ended December 31, 2006. The Company’s disclosure controls and procedures were not materially impacted by the acquisition.

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 theCommittee of Sponsoring Organizations of the Treadway Commission (COSO). 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, 2006.

Management's assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report included herein.

Southern Union Company

March 1, 2007

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is not aware of any change in Southern Union’s internal control over financial reporting that occurred during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. Other Information.

All information required to be reported on Form 8-K for the quarter ended December 31, 2006 was appropriately reported.

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 2007 Annual Meeting of Stockholders under the captions Meetings and Committees of the Board - Board of Directors, 2006 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 Company has adopted a Code of Ethics that applies to its CEO, CFO, Controller and other individuals in the finance department performing similar functions. The Code of Ethics is available on the Company’s website at www.sug.com. If any substantive amendment to the Code of Ethics is made or any waiver is granted thereunder, including any implicit waiver, the Company’s CEO, CFO or other authorized officer will disclose the nature of such amendment or waiver on the website at www.sug.com or in a Current Report on Form 8-K.

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 May 17, 2006.

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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 2007 Annual Meeting of Stockholders under the captions Compensation Discussion and Analysis, 2006 Executive Compensation - Summary Compensation Table - Grants of Plan-Based Awards - Outstanding Equity Awards at December 31, 2006 - Option Exercises and Stock Vested - Non-Qualified Deferred Compensation and - Potential Payments Upon Termination or Change of Control, and 2006 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 2007 Annual Meeting of Stockholders under the captions 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 2007 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 -Independent Director Chairman.

ITEM 14. Principal Accounting 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 2007 Annual Meeting of Stockholders under the caption Meetings and Committees of the Board - Board Committees and Meetings - Audit Committee.

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 Agreement among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated as of June 24, 2004. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on June 25, 2004 and incorporated herein by reference.)
2(b)	Amendment No. 1 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated September 1, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)
2(c)	Amendment No. 2 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated November 10, 2004. (Filed as Exhibit 2.c to Southern Union’s Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)
2(d)	Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated as of September 16, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed on September 17, 2004 and incorporated herein by reference.)

56

2(e)Escrow Agreement attached as Exhibit B to the Order of the United States Bankruptcy Court for the Southern District of New York dated September 10, 2004 (Filed as Exhibit 10.c to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)

2(f)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(g) 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(h)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(i)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(j)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(k)      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.)

   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 filed on March 16, 2006 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.)

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 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.)

57

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 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 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 JP Morgan Chase Bank (assuccessor 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 JPMorgan 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)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)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 December 1, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 7, 2006 and incorporated herein by reference.)

10(b)Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein dated September 29, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 5, 2005 and incorporated herein by reference.)

10(c)First Amendment to the Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

10(e)Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company. (Filed as Exhibit 10(i) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 1986 and incorporated herein by reference.)

10(f)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(g)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(h)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(i)Separation Agreement and General Release Agreement between Thomas F. Karam and Southern Union Company dated November 8, 2005 (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 8, 2005 and incorporated herein by reference.)

58

10(j)Separation Agreement and General Release Agreement between John E. Brennan and Southern Union Company dated July 1, 2005 (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(k)Separation Agreement and General Release Agreement between David J. Kvapil and Southern Union Company dated July 1, 2005 (Filed as Exhibit 10.4 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(l)Southern Union Company Pennsylvania Division Stock Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146, filed on May 3, 2000 and incorporated herein by reference.)

10(m)Southern Union Company Pennsylvania Division 1992 Stock Option Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36150, filed on May 3, 2000 and incorporated herein by reference.)

10(n)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.)

10(o)  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(p)  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. filed herewith.

10(q) Certificate of Incorporation of Citrus Corp., filed herewith.

        10(r) By-Laws of Citrus Corp., filed herewith.

14 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.)

21 Subsidiaries of the Registrant.

23 Consent of Independent Registered Public Accounting Firm.

24 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.

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.

59

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 March 1, 2007.

SOUTHERN UNION COMPANY

By: /s/ George L. Lindemann

George L. Lindemann

Chairman of the Board, President 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 March 1, 2007.

Signature/NameTitle

/s/ George L. Lindemann* Chairman of the Board, President and

George L. LindemannChief Executive Officer

     (Principal Executive Officer)

/s/ Richard N. Marshall Senior Vice President and Chief Financial Officer

Richard N. Marshall(Principal Financial Officer)

/s/ George E. Aldrich Vice President and Controller

George E. Aldrich(Chief Accounting Officer)

/s/ David Brodsky* Director

David Brodsky

/s/ Frank W. Denius* Director

Frank W. Denius

/s/ Kurt A. Gitter, M.D.* Director

Kurt A. Gitter, M.D.

/s/ Herbert H. Jacobi* Director

Herbert H. Jacobi

/s/ Adam M. Lindemann* Director

Adam M. Lindemann

/s/ Thomas N. McCarter, III* Director

Thomas N. McCarter, III

/s/ George Rountree, III* Director

George Rountree, III

/s/ Allan D. Scherer*Director

Allan Scherer

*By: /s/ RICHARD N. MARSHALL*By: /s/ ROBERT M. KERRIGAN, III

Richard N. Marshall           Robert M. Kerrigan, III

Senior Vice President and Chief          
60;    Vice President, Assistant General Counsel

Financial Officerand Secretary

Attorney-in-fact            Attorney-in-fact

60

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-73
Consolidated Financial Statements of Citrus Corp. and Subsidiaries	F-74

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

	Year Ended			Year Ended			Six Months Ended			Year Ended
	December 31,			December 31,			December 31,			June 30,
	2006			2005			2004			2004
	(In thousands, except per share amounts)
Operating revenues (Note 21):
Gas distribution	$	668,721		$	752,699		$	273,597		$	655,696
Gas transportation and storage		577,182			505,233			242,743			490,883
Gas gathering and processing		1,090,216			-			-			-
Other		4,025			8,950			1,509			2,689
Total operating revenues		2,340,144			1,266,882			517,849			1,149,268
Operating expenses:
Cost of gas and other energy		1,377,147			529,450			184,299			456,291
Revenue-related taxes		35,281			40,080			14,399			34,806
Operating, maintenance and general		381,844			302,025			158,566			301,728
Depreciation and amortization		152,103			92,562			47,393			87,735
Taxes, other than on income and revenues		38,684			33,648			20,248			41,388
Total operating expenses		1,985,059			997,765			424,905			921,948
Operating income		355,085			269,117			92,944			227,320
Other income (expenses):
Interest		(210,043	)		(128,470	)		(61,597	)		(121,376	)
Earnings from unconsolidated investments		141,370			70,742			4,745			200
Other, net (Note 4)		39,918			(8,241	)		(19,138	)		324
Total other expenses, net		(28,755	)		(65,969	)		(75,990	)		(120,852	)
Earnings from continuing operations before income taxes		326,330			203,148			16,954			106,468
Federal and state income taxes		109,247			50,052			9,906			42,053
Net earnings from continuing operations		217,083			153,096			7,048			64,415
Discontinued operations (Note 19):
Earnings (loss) from discontinued operations before
income taxes		(2,369	)		(111,588	)		11,744			76,660
Federal and state income taxes		150,583			20,825			4,021			27,050
Net earnings (loss) from discontinued operations		(152,952	)		(132,413	)		7,723			49,610
Net earnings		64,131			20,683			14,771			114,025
Preferred stock dividends		(17,365	)		(17,365	)		(8,683	)		(12,686	)
Net earnings available for common stockholders	$	46,766		$	3,318		$	6,088		$	101,339
Net earnings (loss) available for common stockholders from
continuing operations per share (Note 5):
Basic	$	1.74		$	1.24		$	($0.02	)	$	0.64
Diluted	$	1.70		$	1.20		$	($0.02	)	$	0.63
Net earnings available for common stockholders per
share (Note 5):
Basic	$	0.41		$	0.03		$	0.07		$	1.26
Diluted	$	0.40		$	0.03		$	0.07		$	1.24
Cash dividends declared on common stock per share:	$	0.40			N/A			N/A			N/A
Weighted average shares outstanding (Note 5):
Basic		114,787			109,395			87,314			80,432
Diluted		117,344			112,794			87,314			81,480

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

F-2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

ASSETS

	December 31,			December 31,
	2006			2005
	(In thousands)
Current assets:
Cash and cash equivalents	$	5,751		$	16,938
Accounts receivable, billed and unbilled,
net of allowances of $4,830 and $15,893, respectively		298,231			428,735
Accounts receivable – affiliates		3,546			8,827
Inventories		241,137			295,658
Gas imbalances - receivable		69,877			105,233
Prepayments and other assets		72,317			68,382
Total current assets		690,859			923,773
Property, plant and equipment (Note 6):
Plant in service		5,025,631			4,183,280
Construction work in progress		178,935			184,423
		5,204,566			4,367,703
Less accumulated depreciation and amortization		(620,139	)		(881,763	)
Net property, plant and equipment		4,584,427			3,485,940
Deferred charges:
Regulatory assets (Note 8)		65,865			112,963
Deferred charges		61,602			113,793
Total deferred charges		127,467			226,756
Unconsolidated investments (Note 9)		1,254,749			682,834
Goodwill (Note 7)		89,227			465,547
Other		36,061			51,969
Total assets	$	6,782,790		$	5,836,819

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

F-3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,			December 31,
	2006			2005
	(In thousands)
Stockholders’ equity (Note 10):
Common stock, $1 par value; 200,000 shares authorized;
120,718 shares issued at December 31, 2006	$	120,718		$	112,530
Preferred stock, no par value; 6,000 shares authorized;
920 shares issued at December 31, 2006 (Note 12)		230,000			230,000
Premium on capital stock		1,775,763			1,681,167
Less treasury stock: 1,059 and 1,054
shares, respectively, at cost		(27,708	)		(27,566	)
Less common stock held in trust: 863
and 826 shares, respectively		(14,628	)		(12,910	)
Deferred compensation plans		14,691			10,173
Accumulated other comprehensive loss		(901	)		(56,272	)
Accumulated deficit		(47,527	)		(83,053	)
Total stockholders' equity		2,050,408			1,854,069
Long-term debt and capital lease obligation (Note 13)		2,689,656			2,049,141
Total capitalization		4,740,064			3,903,210
Current liabilities:
Long-term debt and capital lease obligation
due within one year (Note 13)		461,011			126,648
Notes payable		100,000			420,000
Accounts payable and accrued liabilities		300,762			206,504
Federal, state and local taxes payable		30,828			47,195
Accrued interest		46,342			40,688
Customer deposits		14,670			16,096
Deferred gas purchases		15,551			83,147
Gas imbalances - payable		146,995			124,297
Other		84,665			158,555
Total current liabilities		1,200,824			1,223,130
Deferred credits		224,725			313,989
Accumulated deferred income taxes (Note 15)		617,177			396,490
Commitments and contingencies (Note 18)
Total stockholders' equity and liabilities	$	6,782,790		$	5,836,819

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

F-4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

	Year Ended			Year Ended			Six Months Ended			Year Ended
	December 31,			December 31,			December 31,			June 30,
	2006			2005			2004			2004
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	64,131		$	20,683		$	14,771		$	114,025
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		154,601			126,393			63,376			118,755
Goodwill impairment		-			175,000			-			-
Amortization of debt expense (premium)		12,130			2,186			(446	)		(10,100	)
Deferred income taxes		225,843			61,211			12,082			67,455
Provision for bad debts		20,151			22,519			11,649			21,216
Provision for impairment of other assets		6,500			2,338			16,425			1,603
Gain on derivative		(55,146	)		-			-			-
Loss on sale of subsidiaries and other assets		56,815			-			-			1,150
Non-cash stock compensation		6,804			3,848			-			-
Earnings from unconsolidated investments, net of cash distributions		(92,607	)		(55,742	)		(4,745	)		(200	)
Other		(5,643	)		(1,821	)		(1,197	)		(7,429	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable, billed and unbilled		147,450			(126,590	)		(174,716	)		(6,181	)
Accounts payable		(67,021	)		43,681			45,511			(4,421	)
Gas imbalance payable		3,167			(465	)		2,307			1,655
Customer deposits		3,542			2,940			1,113			(542	)
Deferred gas purchase costs		(35,906	)		59,385			10,239			20,670
Inventories		(14,369	)		(52,420	)		(47,474	)		(9,279	)
Deferred charges and credits		(37,459	)		(26,849	)		22,743			13,773
Prepaids and other assets		104,889			(41,256	)		(17,215	)		9,841
Taxes and other liabilities		(39,067	)		3,596			18,323			(4,831	)
Net cash flows provided by (used in) operating activities		458,805			218,637			(27,254	)		327,160
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(347,896	)		(279,721	)		(170,644	)		(213,983	)
Acquisition of equity interest in unconsolidated investment		-			-			(605,388	)		-
Acquisitions of operations, net of cash received		(1,537,627	)		-			-			-
Proceeds from sale of subsidiaries and other assets		1,076,714			-			-			2,175
Other		2,005			(2,808	)		(1,711	)		(3,131	)
Net cash flows used in investing activities		(806,804	)		(282,529	)		(777,743	)		(214,939	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in bank overdraft		(4,941	)		(17,091	)		7,405			1,820
Issuance of long-term debt		1,065,000			255,626			-			750,000
Issuance costs of debt and equity		(10,590	)		(3,536	)		(337	)		(15,120	)
Issuance of preferred stock		-			-			-			230,000
Issuance of common stock and equity units		125,000			431,772			228,287			-
Issuance of Bridge Loan		1,600,000			-			-			-
Repayment of Bridge Loan		(1,600,000	)		-			-			-
Purchase of treasury stock		-			(15,032	)		-			(2,403	)
Dividends paid on common and preferred stock		(51,695	)		(17,365	)		(8,683	)		(8,393	)
Repayment of debt and capital lease obligation		(470,365	)		(335,567	)		(94,123	)		(908,773	)
Net (payments) borrowings under revolving credit facilities		(320,000	)		(279,000	)		678,000			(230,500	)
Proceeds from exercise of stock options		9,216			22,242			4,530			4,122
Other		(4,813	)		8,728			-			-
Net cash flows provided by (used in) financing activities		336,812			50,777			815,079			(179,247	)
Change in cash and cash equivalents		(11,187	)		(13,115	)		10,082			(67,026	)
Cash and cash equivalents at beginning of period		16,938			30,053			19,971			86,997
Cash and cash equivalents at end of period	$	5,751		$	16,938		$	30,053		$	19,971
Cash paid for interest, net of amounts capitalized	$	204,573		$	139,770		$	69,954		$	143,715
Cash paid for income taxes, net of refunds		50,750			(2,007	)		7,764			(10,875	)

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

F-5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

																	Accumulated
																	Other
	Common		Preferred		Premium						Common			Deferred			Compre-						Total
	Stock,		Stock,		on			Treasury			Stock			Compen-			hensive			Retained			Stock-
	$1 Par		No Par		Capital			Stock,			Held			sation			Income			Earnings			holders'
	Value		Value		Stock			at cost			In Trust			Plans			(Loss)			(Deficit)			Equity
	(In thousands)
Balance July 1, 2003	$	73,074	$	-	$	909,191		$	(10,467	)	$	(15,617	)	$	9,960		$	(62,579	)	$	16,856		$	920,418
Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			114,025			114,025
Unrealized loss in investment
securities, net of tax benefit		-		-		-			-			-			-			(21	)		-			(21	)
Minimum pension liability
adjustment, net of tax		-		-		-			-			-			-			10,768			-			10,768
Unrealized gain on hedging
activities, net of tax		-		-		-			-			-			-			1,608			-			1,608
Comprehensive income		-		-		-			-			-			-			-			-			126,380
Preferred stock dividends		-		-		-			-			-			-			-			(12,686	)		(12,686	)
Payment on note receivable		-		-		347			-			-			-			-			-			347
Purchase of treasury stock		-		-		-			(2,403	)		-			-			-			-			(2,403	)
5% stock dividend		3,656		-		67,847			-			-			-			-			(71,503	)		-
Sale of common stock held in trust		-		-		598			-			1,805			-			-			-			2,403
Issuance of preferred stock		-		230,000		(6,590	)		-			-			-			-			-			223,410
Exercise of stock options		411		-		3,711			-			-			-			-			-			4,122
Contributions to Trust		-		-		-			-			(2,799	)		2,799			-			-			-
Disbursements from Trust		-		-		-			-			799			(799	)		-			-			-
Balance June 30, 2004	$	77,141	$	230,000	$	975,104		$	(12,870	)	$	(15,812	)	$	11,960		$	(50,224	)	$	46,692		$	1,261,991
Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			14,771			14,771
Minimum pension liability
adjustment, net of tax benefit		-		-		-			-			-			-			(8,832	)		-			(8,832	)
Unrealized loss on hedging
activities, net of tax benefit		-		-		-			-			-			-			(62	)		-			(62	)
Comprehensive income																								5,877
Preferred stock dividend		-		-		-			-			-			-			-			(8,683	)		(8,683	)
5% stock dividend		242		-		4,494			-			-			-			-			(4,736	)		-
Payment on note receivable		-		-		473			-			-			-			-			-			473
Issuance of common stock		13,042		-		215,245			-			-			-			-			-			228,287
Exercise of stock options		338		-		9,274			-			-			-			-			-			9,612
Contributions to Trust		-		-		-			-			(2,168	)		2,168			-			-			-
Balance December 31, 2004	$	90,763	$	230,000	$	1,204,590		$	(12,870	)	$	(17,980	)	$	14,128		$	(59,118	)	$	48,044		$	1,497,557

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

F-6

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			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, 2004	$	90,763	$	230,000	$	1,204,590		$	(12,870	)	$	(17,980	)	$	14,128		$	(59,118	)	$	48,044		$	1,497,557
Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			20,683			20,683
Unrealized gain on hedging
activities, net of tax		-		-		-			-			-			-			1,075			-			1,075
Minimum pension liability
adjustment, net of tax		-		-		-			-			-			-			1,771			-			1,771
Comprehensive income																								23,529
Preferred stock dividends		-		-		-			-			-			-			-			(17,365	)		(17,365	)
Distibution of common stock
held in trust		-		-		3,130			-			4,186			-			-			-			7,316
Issuance of common stock		14,913		-		316,859			-			-			-			-			-			331,772
Issuance cost of equity units		-		-		(2,622	)		-			-			-			-			-			(2,622	)
Restricted stock award		-		-		4,998			-			-			(4,998	)		-			-			-
Restricted stock amortization		-		-		-			-			-			2,198			-			-			2,198
Contract adjustment payment		-		-		(1,759	)		-			-			-			-			-			(1,759	)
Purchase of treasury stock		-		-		-			(15,032	)		-			-			-			-			(15,032	)
5% stock dividend		5,294		-		129,121			-			-			-			-			(134,415	)		-
Stock option award		-		-		3,848			-			-			-			-			-			3,848
Exercise of stock options		1,560		-		20,617			336			(271	)		-			-			-			22,242
Payment on note receivable		-		-		2,385			-			-			-			-			-			2,385
Contributions to Trust		-		-		-			-			(1,025	)		1,025			-			-			-
Disbursements from Trust		-		-		-			-			2,180			(2,180	)		-			-			-
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
Unrealized loss on hedging
activities, net of tax		-		-		-			-			-			-			918			-			918
Change in fair value of hedging
derivatives, net of tax		-		-		-			-			-			-			5,276			-			5,276
Reversal of minimum pension
liability related to disposition		-		-		-			-			-			-			26,331			-			26,331
Minimum pension liability
adjustment, net of tax		-		-		-			-			-			-			6,803			-			6,803
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

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 outstanding.

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

F-7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Structure

Operations. Southern Union Company (Southern Union and, together with its subsidiaries, 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 Southern Union’s wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LP (PEPL), and its subsidiaries (collectively, Panhandle), the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.3 billion cubic feet per day (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 liquefied natural gas (LNG) import terminal, located on Louisiana’s Gulf Coast, which is one of the largest operating LNG facilities in North America. Through its investment in Citrus Corp. (Citrus), the Company has an interest in and operates Florida Gas Transmission Company (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, LLC (CCE Holdings) on December 1, 2006 applicable to Florida Gas and Transwestern Pipeline Company, LLC (Transwestern) in Note 3 - Acquisitions and Sales - CCE Holdings Transactions. Through Southern Union’s wholly-owned subsidiary, Southern Union Gas Services, the Company owns approximately 4,800 miles of natural gas and natural gas liquids gathering pipelines, four cryogenic plants and six natural gas treatment plants. Southern Union Gas Services is engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and 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.

2. Summary of 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). Effective December 17, 2004, Southern Union’s board of directors approved a change in the Company’s fiscal year end from a 12-month period ending June 30 to a 12-month period ending December 31. As a consequence of this change, the consolidated financial statements include presentation of a transition period beginning on July 1, 2004 and ending on December 31, 2004.

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.

Purchase Accounting. The Company’s March 1, 2006 acquisition of Sid Richardson Energy Services, Ltd. and related entities (Sid Richardson Energy Services) was accounted for using the purchase method of accounting in accordance with Financial Accounting Standards Board (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 value. Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions. Southern Union generally has used outside appraisers to assist in the initial determination of fair value. The appraisal related to Southern Union’s acquisition of Sid Richardson Energy Services was finalized in 2006. See Note 3 - Acquisitions and Sales - Acquisition of Sid Richardson Energy Services.

F-8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 accounted for under Accounting Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock (APB 18), is preliminary and assumes the amount in excess of CCE Holdings’ pre-December 1, 2006 book basis in Citrus is allocable to equity goodwill. For additional information, see Note 9 - Unconsolidated Investments - CCE Holdings Goodwill Evaluation.

Property, Plant and Equipment. Ongoing additions of property, plant and equipment (PP&E) 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 PP&E is also capitalized. The cost of repairs and replacements of minor PP&E items is charged to expense as incurred.

When PP&E is retired, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of PP&E 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 income.

The Company computes depreciation expense using the straight-line method over periods ranging from one to 75 years. Depreciation rates for the utility and transmission plants are approved by the applicable regulatory commissions. The composite weighted-average depreciation rates for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were 3.0 percent, 3.0 percent, 3.3 percent and 3.2 percent, respectively.

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

See Note 6 - Property, Plant and Equipment.

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

Cash and Cash Equivalents. 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 overdraft balances for accounting purposes and are classified in accounts payable in the Consolidated Balance Sheet. At December 31, 2006 and December 31, 2005, such overdraft balances classified in accounts payable were approximately $45.3 million and $7.9 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.

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 Gas Company, LLC (Trunkline), which settles 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.

F-9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gathering and Processing Revenues and Cost of Sales Recognition. Revenue and the related cost of sales for natural gas and natural gas liquids are recognized in the period when the physical product is delivered to the customer at the contractually agreed-upon price and title is transferred. Cost of sales primarily includes the cost of purchased natural gas and natural gas liquids.

Southern Union Gas Services accounts for sale and purchase arrangements on a gross basis in the Consolidated Statement of Operations as Operating revenues and Cost of gas and other energy, respectively. Contractual arrangements establish the purchase of natural gas and natural gas liquids at specified locations and the sale at different locations on the same or other specified dates. Both purchase and sale transactions require physical delivery of the natural gas and natural gas liquids. The transfer of ownership is evidenced by the purchaser’s assumption of title, price risk, credit risk, counterparty nonperformance risk, environmental risk, and transportation scheduling.

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, 2006 and 2005 were $47.3 million and $147.6 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. In addition, the Company requires a deposit from customers in the Gathering and Processing and Distribution segments 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.

F-10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2006 and 2005, the six-month period ended December 31, 2004 and the year ended June 30, 2004:

	Year Ended			Year Ended			Six Months Ended			Year Ended
	December 31,			December 31,			December 31,			June 30,
	2006			2005			2004			2004
	(In thousands)
Beginning balance	$	15,893		$	15,424		$	16,111		$	22,651
Additions: charged to cost and expenses (1)		9,646			22,519			11,649			21,216
Deductions: write-off of uncollectible accounts		(9,756	)		(22,751	)		(14,752	)		(30,809	)
Balance related to discontinued operations (2)		(10,968	)		-			-			-
Other		15			701			2,416			3,053
Ending balance	$	4,830		$	15,893		$	15,424		$	16,111

_________________

(1) Additions charged to cost and expenses applicable to continuing operations for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were $9.6 million, $8.5 million, $5 million and $7 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 (Statement No. 128). All share and per share data have been appropriately restated for all stock dividends, unless otherwise stated. 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. Prior to adoption of Statement No. 123R, the Company used the intrinsic value method of accounting for stock-based compensation awards in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), which generally resulted in no compensation expense for employee stock options with an exercise price not less than fair value on the date of grant. For more information, see Note 24 - Stock-based Compensation.

F-11

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to the modified prospective application method of transition, the Company has not adjusted results of operations for prior periods. The following table reflects pro forma net earnings and net earnings per share adjusted for subsequent stock dividends that the Company would have reported if it had elected to adopt the fair value approach of Statement No. 123 prior to January 1, 2006:

	Year Ended		Six Months Ended		Year Ended
	December 31,		December 31,		June 30,
	2005		2004		2004
	(In thousands, except per share amounts)
Net earnings, as reported	$	20,683	$	14,771	$	114,025
Add stock-based compensation expense included in
reported net earnings, net of related taxes		3,767		-		-
Deduct total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related taxes		4,355		496		1,699
Pro forma net earnings	$	20,095	$	14,275	$	112,326
Net earnings available for common stockholders per share:
Basic - as reported	$	0.03	$	0.07	$	1.26
Basic - pro forma	$	0.02	$	0.06	$	1.24
Diluted - as reported	$	0.03	$	0.07	$	1.24
Diluted - pro forma	$	0.02	$	0.06	$	1.21

Accumulated Other Comprehensive Loss. The Company reports comprehensive income and its components in accordance with FASB Statement No. 130, Reporting Comprehensive Income. The main components of comprehensive income that relate to the Company are net earnings, minimum pension liability adjustments, unrealized gain (loss) on hedging activities and adjustments related to the adoption of Statement No. 158 at December 31, 2006, all of which are presented in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income. For more information see Note 22 - Accumulated Other Comprehensive Loss.

Inventories. In the Transportation and Storage segment, inventories consist of 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 12 months is reflected in non-current assets. Gas held for operations at December 31, 2006 was $129.4 million, or 20,965,000 million British thermal units (MMBtu), of which $14.9 million was classified as non-current. Gas held for operations at December 31, 2005 was $102.5 million, or 14,145,000 MMBtu, of which $25.1 million was classified as non-current. Materials and supplies inventory in the Transportation and Storage segment were $13.2 million and $12.3 million at December 31, 2006 and 2005, respectively.

In the Gathering and Processing segment, inventories consist of materials and supplies and are stated at the lower of weighted average cost or market value. Materials and supplies in the Gathering and Processing segment, primarily comprised of compressor components and parts, were $6.9 million at December 31, 2006.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies, both of which are carried at weighted average cost. Natural gas in underground storage at December 31, 2006 and December 31, 2005 was $103.5 million and $187.6 million, respectively, and consisted of 14,702,000 and 25,324,000 MMBtu, respectively.

F-12

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 reviews its portfolio of unconsolidated investment securities on a quarterly basis to determine whether a decline in value is other-than-temporary. Factors that are considered in assessing whether a decline in value is other-than-temporary include, but are not limited to, the following: earnings trends and asset quality; near term prospects and financial condition of the issuer, including the availability and terms of any additional financing requirements; financial condition and prospects of the issuer's region and industry, customers and markets; and the Company's intent and ability to retain the investment. If the Company determines that a decline in value of an investment security is other-than-temporary, the Company will record a charge in its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value. Write-downs associated with equity-method investments are recognized in Earnings from unconsolidated investments in the Consolidated Statement of Operations, and write-downs associated with cost-method investments are recognized in Other income (expenses),net, in the Consolidated Statement of Operations. See Note 9 - Unconsolidated Investments.

Regulatory Assets and Liabilities. The Company is subject to regulation by certain state and federal authorities. In its Distribution segment and for certain of its operations reported as discontinued operations, 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 and Liabilities.

Goodwill and Other Intangible Assets. The Company accounts for its goodwill and other intangible assets in accordance with FASB Statement No. 142, Accounting for Goodwill and Other Intangible Assets (Statement No. 142). 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 Company’s goodwill is related to its Distribution segment. See Note 7 - Goodwill and Intangibles.

Fair Value of Financial Instruments. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, accounts payable, derivative instruments and notes payable approximate their fair value. The fair value of the Company’s long-term debt is estimated using current market quotes and other estimation techniques. See Note 13 - Debt Obligations.

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.

F-13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Liability accounts are maintained in the Transportation and Storage segment for net volumes of fuel gas owed to customers collectively. Whenever fuel is due from customers from prior under-recovery based on contractual and specific tariff provisions, Trunkline and Trunkline LNG Company, LLC (Trunkline LNG) record an asset. Panhandle’s other companies that are subject to fuel tracker provisions record an expense when fuel is under-recovered. The pipelines’ fuel reimbursement is in-kind and non-discountable.

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, 2006 and 2005, the six month period ended December 31, 2004 and the year ended June 30, 2004 was $5.4 million, $9 million, $2.7 million and $3.8 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. In accordance with this statement, 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 non-hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value are recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive income (loss) until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in earnings immediately. For derivatives treated as trading or non-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. See Note 11 - Derivative Instruments and Hedging Activities.

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 FIN 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 using the provisions of FASB Statement No. 109, Accounting for Income Taxes. Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carry-forward items based on income tax laws and rates existing at the time the temporary differences are expected to reverse. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax audits and issues. In addition, valuation allowances are established for deferred tax assets where the amount of expected future taxable income from operations or the ability to generate capital gains does not support the realization of the asset.

F-14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company accounts for income taxes utilizing the liability method, which bases the amounts of current and future income tax assets and liabilities on events recognized in the financial statements and on income tax laws and rates existing at the time the temporary differences are expected to reverse.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken, regarding the potential tax effects of various financial transactions and ongoing operations to estimate its obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes, including taxes that are subject to ongoing appeals.

Pensions and Other Postretirement Benefit Plans. 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. Effective for years ending after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date. The Company has not yet adopted the measurement date provisions of Statement No. 158.

The Company accounted for the measurement of its defined benefit postretirement plans under Statement No. 87 and Statement No. 106. 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 No. 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.

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.

FASB Statement No. 123R, “Share-Based Payment (revised 2004)”:Issued by the FASB in December 2004, the statement revises FASB Statement No. 123, Accounting for Stock-Based Compensation, supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. 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. The Company’s additional compensation expense resulting from the implementation of this statement was $2.4 million ($1.9 million, net of tax) in 2006. Based upon unvested stock-based compensation awards outstanding at December 31, 2006, the Company estimates additional compensation expense resulting from the implementation of this Statement will be $1.6 million for each of 2007 and 2008 and $1 million for 2009. The Company did not make any amendments to existing stock option arrangements as a result of considering Statement No. 123R’s adoption. Upon the Company’s adoption of Statement No. 123R, no cumulative effect of a change in accounting principle was required to be recorded since the Company has historically granted all options at their grant date fair value and, accordingly, there is no historical intrinsic value option compensation expense to adjust. See Note 24 - Stock Based Compensation.

F-15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)”: Issued by the FASB in September 2006, the Statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through accumulated other comprehensive income. The Statement also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The recognition and disclosure provision of the Statement, which is effective for fiscal years ending after December 15, 2006, was adopted by the Company effective December 31, 2006. The measurement date provisions of the Statement are effective for fiscal years ending after December 15, 2008. See Note 14 - Benefits for the impact the adoption of Statement No. 158 had on the Company.

SEC Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108): In September 2006, the SEC provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the Company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB No. 108 did not materially impact the Company’s consolidated financial statements.

Accounting Principles Not Yet Adopted.

FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109” (FIN 48): Issued by the FASB in July 2006, the Interpretation 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. The Company has evaluated this guidance and does not believe its consolidated financial statements will be materially impacted.

FASB Statement No. 157, “Fair Value Measurements”: Issued by the FASB in September 2006, this Statement 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 generally accepted accounting principles. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

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. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

F-16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Acquisitions and Sales

Acquisition of Sid Richardson Energy Services. On March 1, 2006, Southern Union acquired 100 percent of the partnership interests in Sid Richardson Energy Services 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 Southern Union Gas Services, are located in the Permian Basin of Texas and New Mexico and include approximately 4,800 miles of natural gas and natural gas liquids gathering pipelines, four cryogenic plants and six natural gas treating plants. Southern Union Gas Services is engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Southern Union Gas Services’ activities primarily include 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 natural gas liquids, transporting natural gas and redelivering natural gas and natural gas liquids to a variety of markets. Southern Union Gas Services’ primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States. Southern Union Gas Services receives hydrocarbons for purchase or transportation to market from over 200 producers and suppliers, none of which account for more than 10 percent of its total hydrocarbon throughput. Southern Union Gas Services’ 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 natural gas liquids 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 Southern Union Gas Services’ net assets as of the acquisition date based on their fair values. Southern Union Gas Services’ assets acquired and liabilities assumed have been recorded in the Consolidated Balance Sheet beginning March 1, 2006 at their estimated fair values and have been adjusted to reflect the results of a third-party appraisal and final working capital adjustments. Southern Union Gas Services’ 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.

F-17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the estimated fair values of Southern Union Gas Services’ assets acquired and liabilities assumed at the date of acquisition.

	At March 1, 2006
		(In thousands)
Property, plant and equipment (1)	$	1,556,212
Current assets (2)		156,053
Unconsolidated investment (3)		6,875
Other non-current assets (4)		7,880
Total assets acquired		1,727,020
Current liabilities		140,678
Other non-current liabilities		634
Total liabilities assumed		141,312
Net assets acquired (5)	$	1,585,708

_________________________

(1)   Includes an allocation of $15.5 million to other intangibles for leases and software with weighted-average lives of 4 years and 1 year, respectively.

(2)   Includes cash and cash equivalents of approximately $53.2 million.

(3)   Represents a 50 percent ownership interest in Grey Ranch Plant LP.

(4)   Includes intangibles for contracts totaling $2.6 million with a weighted average life of 3 years.

(5)   Reflects final working capital adjustments of $11 million from the $1.6 billion purchase price.

The following unaudited pro forma financial information for the periods presented is reported as though the acquisition of Sid Richardson Energy Services and the related permanent financing, including utilization of the proceeds from the sales of the Company’s Pennsylvania and Rhode Island natural gas distribution divisions,

occurred at January 1, 2005. The pro forma financial information is not necessarily indicative of the results that would have been obtained if the acquisition of Sid Richardson Energy Services and the related financing had been completed as of the assumed date for the period presented or of the results that may be obtained in the future.

	Year Ended
	December 31,
	2006		2005
	(In thousands)
Operating revenue	$	2,570,693	$	2,636,056
Net earnings available for common shareholders
from continuing operations		209,807		163,471
Net earnings available for common shareholders from
continuing operations per share:
Basic	$	1.83	$	1.49
Diluted	$	1.79	$	1.45

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, subject to certain working capital adjustments. 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 Sid Richardson Energy Services.

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 subject to certain working capital adjustments. 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 Sid Richardson Energy Services.

F-18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 7 - Goodwill and Intangibles 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.

As of December 31, 2006, the working capital adjustment related to the sale of the assets of the PG Energy natural gas distribution division has not been finalized. The ultimate effect of this adjustment, once completed, is not expected to materially affect the Company’s results from discontinued operations, financial condition or operating cash flows.

CCE Holdings Transactions. On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owned a 50 percent interest, acquired 100 percent of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron Corp. and its subsidiaries for a purchase price of approximately $2.45 billion in cash, including certain consolidated debt. Concurrent with this transaction, CCE Holdings sold CrossCountry Energy’s interests in Northern Plains Natural Gas Company, LLC and NBP Services, LLC to ONEOK Inc. (ONEOK) for $175 million in cash. Following these transactions, CCE Holdings owned 100 percent of Transwestern and had a 50 percent interest in Citrus which, in turn, owns 100 percent of Florida Gas. An affiliate of El Paso Corporation owns the remaining 50 percent of Citrus. The Company funded its $590.5 million equity investment in CCE Holdings through borrowings of $407 million under a bridge loan facility, net proceeds of $142 million from the settlement on November 16, 2004 of its July 2004 forward sale of 8,242,500 shares of its common stock and additional borrowings of approximately $42 million under its existing revolving credit facility. In February 2005, Southern Union issued 2 million of its 5% Equity Units, from which it received net proceeds of approximately $97.4 million, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $332.6 million, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note 10 - Stockholders’ Equity). The Company’s investment in CCE Holdings was accounted for using the equity method of accounting. Accordingly, Southern Union reported its share of CCE Holdings’ earnings as Earnings from unconsolidated investments in the Consolidated Statement of Operations until it became a wholly-owned subsidiary on December 1, 2006, as more fully described below. The Consolidated Statement of Operations for the periods subsequent to December 1, 2006 is therefore not comparable to the same periods in prior years.

Florida Gas is an open-access interstate pipeline system extending approximately 5,000 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 70 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.

Transwestern is 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.

F-19

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, L.P. (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 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.

4. Other Net Income (Expense)

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 Sid Richardson Energy Services 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.

Other, net expense for the year ended December 31, 2005 of $8.2 million primarily includes charges of $6.3 million to reserve for the other-than-temporary impairment of the Company’s investment in separate technology companies and to record a liability for a related loan guaranty (see Note 9 - Unconsolidated Investments), partially offset by a $1.8 million gain related to the mark-to-market accounting of put options purchased in connection with the agreement to acquire Sid Richardson Energy Services. See Note 11 - Derivative Instruments and Hedging Activities - Gathering and Processing Segment for additional information related to the put options.

Other, net expense for the six months ended December 31, 2004 of $19.1 million includes a non-cash charge of $16.4 million to reserve for the other-than-temporary impairment of the Company’s investment in a technology company (see Note 9 - Unconsolidated Investments) and $903,000 of legal costs associated with the Company’s attempt to collect damages from former Arizona Corporation Commissioner James Irvin related to the Southwest Gas Corporation (Southwest) litigation.

Other, net income for the year ended June 30, 2004 of $324,000 includes a gain of $6.4 million on the early extinguishment of debt. This item was partially offset by charges of $1.6 million and $1.2 million to reserve for the impairment of Southern Union’s investments in a technology company and in an energy-related joint venture, respectively, and $836,000 of legal costs related to the Southwest litigation.

F-20

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Earnings Per Share

The following table summarizes the Company’s basic and diluted earnings per share (EPS) calculations for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004:

							Six Months
	Year Ended			Year Ended			Ended			Year Ended
	December 31,			December 31,			December 31,			June 30,
	2006			2005			2004			2004
	(In thousands, except per share amounts)
Net earnings from continuing operations	$	217,083		$	153,096		$	7,048		$	64,415
Net earnings (loss) from discontinued operations		(152,952	)		(132,413	)		7,723			49,610
Preferred stock dividends		(17,365	)		(17,365	)		(8,683	)		(12,686	)
Net earnings available for common stockholders	$	46,766		$	3,318		$	6,088		$	101,339
Weighted average shares outstanding - Basic		114,787			109,395			87,314			80,432
Weighted average shares outstanding - Diluted		117,344			112,794			87,314			81,480
Basic earnings per share:
Net earnings (loss) available for common stockholders
from continuing operations	$	1.74		$	1.24			($0.02	)	$	0.64
Net earnings (loss) from discontinued operations		(1.33	)		(1.21	)		0.09			0.62
Net earnings available for common stockholders	$	0.41		$	0.03		$	0.07		$	1.26
Diluted earnings per share:
Net earnings (loss) available for common stockholders
from continuing operations	$	1.70		$	1.20			($0.02	)	$	0.63
Net earnings (loss) from discontinued operations		(1.30	)		(1.17	)		0.09			0.61
Net earnings available for common stockholders	$	0.40		$	0.03		$	0.07		$	1.24

 

F-21

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 common stock equivalents from stock options, stock appreciation rights, warrants, restricted stock and convertible equity units. A reconciliation of the shares used in the basic and diluted EPS calculations is shown in the following table.

					Six Months
	Year Ended		Year Ended		Ended		Year Ended
	December 31,		December 31,		December 31,		June 30,
	2006		2005		2004		2004
	(In thousands)
Weighted average shares outstanding - Basic		114,787		109,395		87,314		80,432
Add assumed vesting of restricted stock		35		16		-		-
Add assumed conversion of equity units		2,021		2,141		-		-
Add assumed exercise of stock options		501		1,242		-		1,048
Weighted average shares outstanding - Dilutive		117,344		112,794		87,314		81,480

Due to its anti-dilutive effect, Statement No. 128 prohibits the inclusion of potential common shares in diluted earnings per share in the period that a loss from continuing operations available for common stockholders is incurred. As the Company incurred a loss from continuing operations available for common stockholders for the six months ended December 31, 2004, basic and diluted earnings per share are equal for that period.

For the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, no adjustments were required in net earnings available for common stockholders in the earnings per share calculations.

The Company repurchased nil, 649,343, nil and 122,203 shares of its common stock outstanding during the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively. These repurchases substantially occurred in private off-market large-block transactions.

There were nil, 87,346 and 304,595 “anti-dilutive” options outstanding for the 12-month periods ended December 31, 2006 and 2005 and June 30, 2004, respectively. There were no “anti-dilutive” shares outstanding for the six-month period ended December 31, 2004. At December 31, 2006, 863,458 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 regular restrictions.

See Note 10 - Stockholders’ Equity - 2005 Equity Issuances and Note 13 - Debt Obligations - Long-Term Debt and Capital Lease Obligations - Remarketing Obligation for information related to the 5.75% and 5% Equity Units issued on June 11, 2003 and February 11, 2005, respectively, which had a dilutive effect on earnings per share for the years 2005 and 2006.

F-22

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. Property, Plant and Equipment

The following table provides a summary of PP&E at the dates indicated:

			December 31,			December 31,
Property, Plant and Equipment	Lives in Years		2006			2005
			(In thousands)
Gathering plant		3-50	$	1,623,265		$	45,822
Transmission plant		36-46		1,400,547			1,285,848
Distribution plant		21-75		897,075			1,774,802
General - LNG		40		619,018			494,827
Underground storage plant		36-46		279,845			275,603
General plant and other		1-50		205,881			306,378
Plant in service (1)				5,025,631			4,183,280
Construction work in progress				178,935			184,423
				5,204,566			4,367,703
Less accumulated depreciation and amortization (1)				(620,139	)		(881,763	)
Net property, plant and equipment			$	4,584,427		$	3,485,940
_________________________
(1) Includes capitalized computerized software cost totaling:
Unamortized computer software cost		1-10	$	96,556		$	119,471
Less accumulated amortization				(41,186	)		(44,588	)
Net capitalized computer software costs			$	55,370		$	74,883

Amortization expense of capitalized computer software costs for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and for the year ended June 30, 2004 was $9.8 million, $11 million, $7.6 million and $10 million, respectively. Computer software costs are amortized between one and ten years.

7. Goodwill and Intangibles

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 June 30, 2003	$	642,921
Impairment losses		-
Reversal of income tax reserve		(2,374	)
Balance as of June 30, 2004		640,547
Impairment losses		-
Balance as of December 31, 2004		640,547
Impairment losses		(175,000	)
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

F-23

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During 2005, the Company changed the date upon which its annual goodwill impairment assessment is performed from May 31 to November 30 to correspond with the change in fiscal year end and related change in the timing of completing the Company’s annual operating and capital budgets. The Company believes this change is preferable. The determination of whether an impairment has occurred is based on an estimate of discounted future cash flows attributable to the Company’s reporting units that have goodwill, as compared to the carrying value of those reporting units’ net assets. No impairment was evident based upon the evaluations performed as of May 31, 2005 and November 30, 2005. Execution of agreements for the sale 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 constituted a subsequent event of the type that, under GAAP, required the Company to consider the market value indicated by the definitive sale agreements in its 2005 goodwill impairment evaluation. Accordingly, based on the fair values of these reporting units derived principally from the definitive sales agreements, a goodwill impairment charge of $175 million was recorded in the 2005 period in Earnings (losses) from discontinued operations before income taxes in the Consolidated Statement of Operations. 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.

As a result of the reversal of income tax reserves related to the purchase of PG Energy, goodwill of $2.4 million was eliminated during the year ended June 30, 2004. All goodwill reflected in the Company’s Consolidated Balance Sheet is applicable to its Distribution segment.

On June 11, 2003 and March 1, 2006, the Company completed its acquisition of Panhandle and Sid Richardson Energy Services, respectively. Based on the purchase price allocations and outside appraisals, the acquisitions of Panhandle and Sid Richardson Energy Services resulted in the recognition of intangible assets relating to customer relationships of approximately $9.5 million and $2.6 million, respectively, which are currently being amortized over a period of twenty-five years and three years, respectively, the remaining estimated lives of the contracts for which the value is associated. As of December 31, 2006, the carrying amount of these intangibles was approximately $9.5 million and is included in Deferred charges on the Consolidated Balance Sheet. Amortization expense on the customer contracts for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 was approximately $1.1 million, $465,000, $224,000 and $583,000, respectively. The Company estimates the annual amortization expense for years 2007 through 2011 will be $1.2 million, $1.2 million, $490,000, $346,000, and $346,000 per year, respectively.

8. Regulatory Assets

The Company records regulatory assets and liabilities with respect to its Distribution segment operations and for certain of its operations reported as discontinued operations in accordance with Statement No. 71. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	December 31,		December 31,
Regulatory Assets	2006		2005
	(In thousands)
Pension and Postretirement Benefits	$	33,969	$	32,627
Deferred Income Tax		-		28,076
Environmental		15,571		23,656
Missouri Safety Program		8,751		11,956
Other		7,574		16,648
	$	65,865	$	112,963

The Company’s regulatory assets at December 31, 2006 relating to Distribution segment operations that are being recovered through current rates totaled $30.7 million. The remaining recovery period associated with these assets ranged from 12 months to 93 months. As of December 31, 2005, the Company’s regulatory assets relating to the Distribution segment operations and discontinued operations included $59.1 million that is being recovered through current rates. The remaining recovery period as of December 31, 2005 associated with these assets ranged from one month to 187 months.

9. Unconsolidated Investments

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

	December 31,		December 31,
Unconsolidated Investments	2006		2005
	(In thousands)
Equity investments:
Citrus	$	1,233,172	$	-
CCE Holdings		-		668,985
Other		20,802		13,074
Investments at cost		775		775
	$	1,254,749	$	682,834

Equity Investments. Unconsolidated investments at December 31, 2006 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch Plant, LP, Lee 8 and PEI Power II, respectively. Unconsolidated investments at December 31, 2005 included the Company’s 50 percent, 29 percent and 49.9 percent investments in CCE Holdings, Lee 8 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.

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.

F-25

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s equity investment balances include amounts in excess of the Company’s share of the underlying equity of the investee of $585.6 million and $18.4 million as of December 31, 2006 and 2005, respectively. These amounts relate to the Company’s 50 percent equity ownership interest in Citrus and CCE Holdings. The allocation of the $208.4 million excess purchase cost associated with the additional 25 percent interest in Citrus effectively acquired on December 1, 2006 is preliminary with respect to the fair values of certain underlying Citrus tangible and intangible assets. The incremental purchase cost in excess of CCE Holdings’ basis in Citrus is currently assumed to all be allocable to equity goodwill. Based on the preliminary allocation, the combined fair value amount recorded in excess of the Company’s 50 percent share of the underlying Citrus equity at December 31, 2006 was as follows:

	Excess Purchase Costs			Amortization Period
	(In thousands)
Property, plant and equipment	$	34,000			40 years
Capitalized software		2,100			5 years
Long-term debt (1)		(83,300	)		4-20 years
Deferred taxes (1)		(13,100	)		40 years
Other net liabilities (2)		(21,300	)		N/A
Goodwill (3)		642,200			N/A
Sub-total		560,600
Accumulated, net accretion to equity earnings		25,000
Net investment in excess of underlying equity	$	585,600

____________________

(1)   Accretion of this amount increases equity earnings and accumulated net accretion.

(2)   Includes reserve for Citrus accounts receivable amounts under dispute, proceeds from which were obligated to be remitted to Enron Corp. under terms in place at December 1, 2006 pursuant to the purchase agreement for the November 17, 2004 acquisition of CCE Holdings.

(3)   The Company expects to have a tax basis in all of the equity goodwill.

Other. The Company’s investments in Grey Ranch Plant, LP, the Lee 8 partnership and PEI Power are accounted for under the equity method. The Grey Ranch Plant, LP is a 225 million cubic feet per day carbon dioxide treatment facility. The Lee 8 partnership operates a 2.4 Bcf natural gas storage facility in Michigan. PEI Power II is a 45-megawatt, natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.

F-26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	At December 31, 2006				At December 31, 2005
			Other Equity		CCE		Other Equity
	Citrus		Investments		Holdings		Investments
	(In thousands)
Balance Sheet Data:
Current assets	$	64,295	$	3,552	$	69,983	$	2,122
Non-current assets		3,056,818		37,633		2,313,874		28,832
Current liabilities		191,341		1,589		49,428		2,955
Non-current liabilities		1,636,671		1,802		1,034,092		356

	Year Ended										Year Ended
	December 31, 2006										December 31, 2005
	CCE								Other Equity		CCE					Other Equity
	Holdings (a)						Citrus (d)		Investments		Holdings					Investments
	(In thousands)
Income Statement Data:
Revenues	$	-				$	37,598	$	5,386	$	-				$	6,942
Operating income (loss)		(5,729	)				21,201		1,157		(11,024	)				1,230
Equity earnings		70,086		(c	)		-		-		72,492		(c	)		-
Interest expense		25,445					7,109		146		58,143					151
Income from discontinued
operations		156,612		(b	)		-		-		103,072					-
Net income		196,857					9,579		1,005		140,735					1,058
_____________________
(a) The income statement 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.
(b) Income 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 contemplated by 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 contemplated by the Redemption Agreement. See Note 3 - Acquisitions and Sales - CCEHoldings
Transactions for a description of the transaction.
(c) Represents equity earnings of CCE Holdings in Citrus through the period ending December 1, 2006.
(d) Includes Citrus results for the post-Redemption Agreement period of December 2006.

Investments at Cost. As of December 31, 2006 and 2005, the Company, either directly or through a subsidiary, owned common and preferred stock in two non-public companies, Advent Networks, Inc. (Advent) and PointServe, Inc. (PointServe), whose fair values are not readily determinable. These investments are accounted for under the cost method. Realized gains and losses on sales of these investments, as determined on a specific identification basis, are included in the Consolidated Statement of Operations when incurred, and dividends are recognized as income when received. Various officers, directors and employees of Southern Union either directly or through a partnership also have an equity ownership interest in Advent.

Advent. In December 2004, the Company recorded a total non-cash charge of $16.4 million to recognize an other-than-temporary impairment of the carrying value of its investment in Advent. This impairment was comprised of write-downs of $4.9 million and $11.5 million to the Company’s investment and convertible notes receivable accounts, respectively.

F-27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In March 2005, Advent filed for Chapter 11 bankruptcy relief. As a result, Southern Union recorded a $4 million liability associated with the guarantee of an Advent line of credit by a subsidiary of the Company. In April 2005, Advent defaulted on its $4 million line of credit and the guarantee liability was funded. In March 2005, the Company also recorded a $508,000 other-than-temporary impairment of its remaining unreserved investment in Advent. The total charge of $4.5 million was reflected in Other income, net in the Consolidated Statement of Operations for the quarter ended March 31, 2005.

PointServe. In December 2005 and September 2003, Southern Union determined that declines in the value of its investment in PointServe were other-than-temporary. Accordingly, the Company recorded non-cash charges of $1.6 million and $1.8 million during the quarter ended September 30, 2003 and the quarter ended December 31, 2005, respectively. The Company recognized these valuation adjustments to reflect significant lower private equity valuation metrics and changes in the business outlook of PointServe. PointServe is a closely held, privately owned company and, as such, has no published market value. The Company’s remaining investment of $775,000 at December 31, 2006 may be subject to future market value risk. The Company will continue to monitor the value of its investment and periodically assess the impact, if any, on reported earnings in future periods.

Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus.

Environmental Matters. Florida Gas is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted from the past releases of hydrocarbons and chlorinated compounds. 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.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (U.S. EPA) Spill Prevention, Control and Countermeasures (SPCC) program. The Company is currently reviewing the impact of these modifications to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot reasonably be estimated 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.

CCE Holdings’ Goodwill Evaluation. CCE Holdings applied the purchase method of accounting for its acquisition of CrossCountry Energy on November 17, 2004. Goodwill associated with the acquisition of CrossCountry Energy related to Transwestern totaled nil and approximately $113.3 million at December 31, 2006 and 2005, respectively. Goodwill associated with CCE Holdings’ equity investment in Citrus accounted for under APB 18 was approximately $642.2 million and $433.8 million at December 31, 2006 and 2005, respectively. The amounts recorded at December 31, 2006 are subject to 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.

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 their 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, 2006 were $19.3 million and $14.3 million, respectively.

F-28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 regulation 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 rank the risk of their pipeline segments containing HCAs and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. 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 the total scope of required remediation activities prior to completion of the assessments and inspections. Therefore, the costs of implementing the requirements of this regulation is impossible to determine with certainty at this time. For Florida Gas, the required modifications and inspections are estimated to be in the range of approximately $16 million to $20 million per year, inclusive of remediation costs.

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages that may, over the next ten years, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way. Florida Gas is currently considering its options relating to the first phase of the turnpike project, which include replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida. Estimated cost of such replacement would be $110.5 million. Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’s 18- and 24-inch pipelines within FDOT/FTE right-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 right-of-way costs, cannot be determined at this time.

Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for 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 right-of-way costs. On January 25, 2007, Florida Gas filed a complaint against FDOT in the Seventeenth Judicial Circuit, Broward County, Florida, which seeks relief with respect to three specific sets of FDOT widening projects in Broward County. The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. 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.

Citrus Trading Litigation. On January 29, 2007, Citrus Trading, Citrus, Southern Union and El Paso Corporation  (collectively, Citrus Parties) entered into a settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly known as Duke Energy LNG Sales, Inc. (Duke), and its parent company Spectra Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100 million to Citrus Trading. The litigation related to a natural gas purchase contract between Citrus Trading and Duke which had been terminated in 2003. Citrus expects to record an approximate $14 million after-tax gain in the first quarter of 2007.  On January 29, 2007, the Citrus Parties entered into a settlement with Enron Corp. pursuant to which CCE Holdings' obligation to remit to Enron Corp. certain proceeds of any Duke settlement was reduced.

F-29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Litigation.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Florida Gas, for damages for mis-measurement of 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.

10. Stockholders’ Equity

Dividends. On December 19, 2006, the Company announced that its Board of Directors authorized the payment of the Company’s fourth regular quarterly cash dividend of $0.10 per share on the Company’s common stock. Dividend payments totaling $12 million were paid on January 12, 2007, to holders of record as of the close of business on December 29, 2006. 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 earnings were available) and $26.4 million, respectively.

On April 14, 2006, July 14, 2006, and October 6, 2006, the Company paid its quarterly cash dividend of $11.2 million, $11.2 million, and $11.9 million to stockholders of record on March 31, 2006, June 30, 2006 and September 29, 2006, respectively.

Prior to 2006, the Company distributed common stock dividends in lieu of cash dividend payments. On September 1, 2005, August 31, 2004 and July 31, 2003, the Company distributed its then annual five percent common stock dividend to stockholders of record on August 22, 2005, August 20, 2004 and July 17, 2003, respectively. Unless otherwise stated, all per share and share data in this report for periods prior to 2006 have been restated to give effect to the stock dividends.

Under the terms of the indenture governing its 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. On May 9, 2005, the stockholders of the Company adopted the Southern Union Company Amended and Restated 2003 Stock and Incentive Plan (Amended 2003 Plan). The Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), stock appreciation rights, stock bonus awards, restricted stock, performance units or other equity-based rights. The persons eligible to receive awards under the 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. The Amended 2003 Plan provides that each non-employee director, will receive annually a restricted stock award, or at the election of the non-employee director options having an equivalent value, which will be granted at such time or times as the compensation committee shall determine. Under the 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 more than ten years after the date of the Amended 2003 Plan.

On May 2, 2006, the stockholders of the Company adopted the Second Amended and Restated 2003 Plan (Second Amended 2003 Plan), which included the following changes to the Amended 2003 Plan:

·   An increase from 7,000,000 to 9,000,000 in the aggregate number of shares of stock that may be issued under the plan;

·   An increase from 725,000 to 1,500,000 in the total number of shares of stock that may be issued pursuant to stock awards, performance units and other equity-based rights; and

·   An increase from 4,000 to 5,000 in the maximum number of shares of restricted common stock that each non-employee director is eligible to receive annually.

F-30

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contingent upon the Second Amended 2003 Plan becoming effective, the Compensation Committee of the Board of Directors approved a grant of 5,000 shares of restricted common stock to each of the non-employee directors. The restricted stock awards contain certain restrictions that expired on January 2, 2007. The Second Amended 2003 Plan was approved by the Massachusetts Department of Telecommunications and Energy (MDTE) on October 13, 2006 and became effective upon the filing of a Form S-8 with the SEC on November 8, 2006.

On July 1, 2005, pursuant to the respective separation agreements between the Company and each of its former Vice Chairman of the Board of Directors and former Chief Financial Officer, the Company modified the terms of approximately 307,000 options to purchase its common stock that had previously been granted to and were exercisable by these executives under the Company’s 1992 Long-Term Stock Incentive Plan (1992 Plan) and Amended 2003 Plan. As a result of the modification and re-valuation of the options as of July 1, 2005, the Company recorded $3.8 million of non-cash compensation expense during the quarter ended September 30, 2005. All of these options were exercised as of December 31, 2006.

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 at prices not less than the fair market value on the date of grant. The 1992 Plan allowed for the granting of stock appreciation rights, dividend equivalents, performance shares and restricted stock. 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. Options typically vest at the rate of 20 percent per year, but may vest over a longer or shorter period as designated for a particular option grant. At December 31, 2006, there were no shares available for future option grants under the 1992 Plan.

In connection with the acquisition of Pennsylvania Enterprises, Inc., the Company adopted the Pennsylvania Division 1992 Stock Option Plan (Pennsylvania Option Plan) and the Pennsylvania Division Stock Incentive Plan (Pennsylvania Incentive Plan and, together with the Pennsylvania Option Plan, the Pennsylvania Plans). At December 31, 2005 no options were outstanding and no additional options will be granted under the Pennsylvania Plans. During the year ended December 31, 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, options exercised under the Pennsylvania Option Plan were 466,127, nil and nil, respectively. During the year ended December 31, 2005, 139,837 and 91,831 options were exercised and canceled, respectively. For the six months ended December 31, 2004 and the year ended June 30, 2004, no options were exercised under the Pennsylvania Incentive Plan.

For more information on share-based awards, see Note 24 - Share-Based Compensation.

2006 Equity Issuances. 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 and Capital Lease Obligations - Remarketing Obligation. 

2005 Equity Issuances. On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $97.4 million. Southern Union used the proceeds to repay the balance of the bridge loan used to finance a portion of its investment in CCE Holdings and to repay borrowings under its credit facilities. Each 5% Equity Unit consists of a 1/20^th interest in a $1,000 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note 13 - Debt Obligations) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $23.44 and $29.30, respectively, which are subject to adjustments for future stock splits or stock dividends). Southern Union will issue between 3,413,247 shares and 4,266,558 shares of its common stock (also subject to adjustments for any future stock splits or stock dividends) upon the consummation of the forward purchase contracts. The 5% Equity Units carry a total annual coupon of 5.00 percent (4.375 percent annual face amount of the senior notes plus 0.625 percent annual contract adjustment payments). The present value of the 5% Equity Units’ contract adjustment payments was initially charged to stockholders’ equity, with an offsetting credit to liabilities. The liability is accreted over three years by interest charges to the Consolidated Statement of Operations. Before the issuance of Southern Union’s common stock upon settlement of the purchase contracts, the 5% Equity Units will be reflected in the Company’s diluted earnings per share calculations using the treasury stock method.

F-31

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On February 9, 2005, Southern Union issued 14,913,042 shares of common stock at a public offering price of $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions of $332.6 million. Southern Union used the net proceeds to repay a portion of the bridge loan used to finance a portion of its investment in CCE Holdings.

2004 Equity Issuances. On July 30, 2004, Southern Union issued 4,800,000 shares of common stock at a public offering price of $18.75 per share, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $86.6 million. Southern Union also sold 6,200,000 shares of its common stock through forward sale agreements with its underwriters and granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,650,000 shares of its common stock at the same price, which was exercised by the underwriters. Under the terms of the forward sale agreements, Southern Union had the option to settle its obligation to the forward purchasers through either (i) paying a net settlement in cash, (ii) delivering an equivalent number of shares of its common stock to satisfy its net settlement obligation, or (iii) the physical delivery of shares. Upon settlement, which occurred on November 16, 2004, Southern Union received approximately $142 million in net proceeds upon the issuance of 8,242,500 shares of common stock to affiliates of JP Morgan and Merrill Lynch, joint book-running managers of the offering. Southern Union used the total net proceeds from the settlement of the forward sale agreements to fund a portion of its investment in CCE Holdings.

11. Derivative Instruments and Hedging Activities

Interest Rate Swaps. Interest rate swaps are used 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 into 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.

On April 29, 2005, the Company refinanced the existing bank loans of Trunkline LNG Holdings, LLC (LNG Holdings) in the amount of $255.6 million, due 2007. See Note 13 - Debt Obligations. Interest rate swaps previously designated as cash flow hedges of the LNG Holdings’ bank loans were terminated upon refinancing of the loans. As a result, a gain of $3.5 million ($2.1 million net of tax) was recorded in Accumulated other comprehensive loss during the second quarter of 2005 and is being amortized to interest expense through the maturity date of the original bank loans in 2007. From January 1, 2005 through the termination date of the swap agreements on April 29, 2005, there was no swap ineffectiveness.

In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250 million to manage its exposure against changes in future interest payments attributable to changes in the benchmark interest rate prior to the anticipated issuance of fixed-rate debt. These treasury rate locks expired on June 30, 2003, resulting in a $6.9 million after-tax loss that was recorded in Accumulated other comprehensive loss and will be amortized into interest expense over the lives of the associated debt instruments. As of December 31, 2006, approximately $967,000 of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months.

In March 2004, Panhandle entered into interest rate swaps to hedge the risk associated with the fair value of its $200 million principal amount of 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under Statement No. 133. Under the swap agreements, Panhandle will receive fixed interest payments at a rate of 2.75 percent and will make floating interest payments based on the six-month LIBOR. No ineffectiveness is assumed in the hedging relationship between the debt instrument and the interest rate swap. As of December 31, 2006 and December 31, 2005, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $1.3 million and $5.7 million, respectively.

F-32

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Distribution Segment

Non-Hedging Activities. During 2006, 2005 and 2004, 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 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, 2006 and December 31, 2005, the fair values of the contracts, which expire at various times through March 2008, are included in the Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $19 million and $17.5 million, respectively.

Gathering and Processing Segment

The Company markets natural gas and natural gas liquids in its Gathering and Processing segment and manages associated commodity price risks using derivative financial instruments. These instruments involve not only the risk of dealing with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations. Under Statement No. 133, the Company is required to record derivative financial instruments at fair value, which is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

Non-Hedging Derivatives. The Company uses various derivative financial instruments to manage commodity price risk and to take advantage of pricing anomalies among derivative financial instruments related to natural gas and natural gas liquids. The Company uses a combination of fixed-price physical forward contracts, exchange-traded futures and options, and fixed for floating index and basis swaps to manage commodity price risk. 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 the physical market and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.  For the year ended December 31, 2006, a gain of $1.2 million was recorded for the non-hedging activities.

Cash Flow Hedges.

December 2005 Put Options. In connection with its agreement to acquire Sid Richardson Energy Services, now known as Southern Union Gas Services, the Company purchased natural gas put options in December 2005 for $49.7 million based on the price of natural gas in December 2005. The Company believed that given the then relative price of natural gas and natural gas liquids, natural gas was the appropriate commodity to use as a hedging instrument. These commodity options were tied to the WAHA price of natural gas for the monthly delivery periods from March 2006 through December 2007. The put options for 2006 relate to 45,000 MMBtu/day at the price of $11.00 per MMBtu and the put options for 2007 relate to 25,000 MMBtu/day at the price of $10.00 per MMBtu. The objective for purchasing the put options was to reduce the downside commodity price risk of the Southern Union Gas Services business. Prior to the closing of the Company’s acquisition of Sid Richardson Energy Services on March 1, 2006, the put options were required to be accounted for using mark-to-market accounting, with the change in fair value between measurement dates recorded as a gain or loss in current period earnings. The impact on the Company’s results of operations for the January and February 2006 pre-acquisition period was a pre-tax gain of $37.2 million. The gain was recorded in Other, net in the Consolidated Statement of Operations and was not reflected in the results of the Gathering and Processing segment. There was a similar $1.8 million pre-tax gain in December 2005.

F-33

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As a result of the required mark-to-market gains, the Company’s basis in the put options was increased to $88.7 million as of March 1, 2006. With the closing of the acquisition on March 1, 2006, the commodity-based put options were designated as cash flow hedges and since that date have been accounted for in accordance with Statement No. 133, with the earnings impact, including amortization of the basis, reflected in the results of the Gathering and Processing segment. In accordance with Statement No. 133, changes in the fair value of the put options that are considered effective will initially be recorded in Accumulated other comprehensive loss, and reclassified to earnings in the period the hedged sales occur. If it is determined that a hedge is not effectively operating as anticipated, income is adjusted to the extent of such ineffectiveness.

July 2006 Put Options. In July 2006, Southern Union Gas Services purchased put options for its propane, ethane and crude oil equivalent products for premiums of $2.8 million, $2.7 million and $4.6 million, respectively. The propane put options relate to 122,000 barrels of 2006 production at a strike price of $1.185/gallon and 401,500 barrels of 2007 production at a strike price of $1.1075/gallon. The ethane put options relate to 183,000 barrels of 2006 production at a strike price of $0.81/gallon and 620,500 barrels of 2007 production at a strike price of $0.69/gallon. The crude oil put options relate to 1,058,500 barrels of 2007 production at a strike price of $70.00/barrel. On an energy-equivalent basis, the volumes hedged by these put options were 8,000 MMBtu/day in 2006 and 26,000 MMBtu/day in 2007. The objective for purchasing the put options was to further reduce Southern Union Gas Services’ downside commodity price risk associated with its sales of propane, ethane and other natural gas liquids products, which usually correlate with crude oil. The Company designated the propane and ethane put options as cash flow hedges, which are accounted for in accordance with Statement No. 133. Accordingly, changes in fair value of the put options that are considered effective are initially recorded in Accumulated other comprehensive loss and reclassified to earnings in the period the hedged sales occur. If it is determined that the hedge is ineffective, income is adjusted to the extent of such ineffectiveness.

Financial Statement Impact of Cash Flow Hedges. At December 31, 2006, the Company marked the hedging put options to fair value and recorded a gain for the effective portion of the change in value between measurement dates in Accumulated other comprehensive loss of $19.8 million ($12.4 million, net of tax). The Company recorded a gain of approximately $22,000 related to ineffectiveness of the cash flow hedges. At December 31, 2006, the Company reported the $38.1 million balance, all of which is current, of the fair market value of the put options in the Consolidated Balance Sheet in Prepayments and other assets. During the year ended December 31, 2006, the Company realized $74.2 million in settlement value associated with the hedging put options. For the year ended December 31, 2006, the Company reclassified to earnings $11.4 million ($7.1 million, net of tax) of previously deferred gains recorded in Accumulated other comprehensive loss. Such reclassified earnings were recorded in Operating revenues in the Consolidated Statement of Operations. During 2007, the Company expects that all of the $8.5 million ($5.3 million, net of tax) gain included in the Accumulated other comprehensive loss balance at December 31, 2006 will be reclassified into earnings.

12. Preferred Securities

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10^th interest in a share of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) at the public offering price of $25.00 per share, or $230 million in the aggregate. The total net proceeds were used to repay debt under the Company’s revolving credit facilities.

F-34

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. Debt Obligations

The following table sets forth the debt obligations of Southern Union and Panhandle under their respective notes, debentures and bonds at the dates indicated:

	Carrying Value		Fair Value		Carrying Value		Fair Value
	December 31,		December 31,		December 31,		December 31,
	2006		2006		2005		2005
	(In thousands)
Long-Term Debt and Capital Lease Obligations:
Southern Union Company
7.60% Senior Notes due 2024	$	359,765	$	384,948	$	359,765	$	411,931
8.25% Senior Notes due 2029		300,000		371,367		300,000		360,723
2.75% Senior Notes due 2006		-		-		125,000		125,000
6.50% to 10.25% First Mortgage Bonds due 2006		19,500		19,500		111,419		111,165
to 2029
4.375% Senior Notes due 2008		100,000		100,000		100,000		100,000
6.15% Senior Notes due 2008		125,000		125,655		-		-
Junior Subordinated Notes due 2066		600,000		598,572		-		-
Capital lease and other		-		-		71		71
		1,504,265		1,600,042		996,255		1,108,890
Panhandle
2.75% Senior Notes due 2007		200,000		200,000		200,000		200,000
4.80% Senior Notes due 2008		300,000		300,000		300,000		300,000
6.05% Senior Notes due 2013		250,000		251,053		250,000		254,450
6.50% Senior Notes due 2009		60,623		61,721		60,623		63,228
8.25% Senior Notes due 2010		40,500		43,180		40,500		45,135
7.00% Senior Notes due 2029		66,305		71,947		66,305		73,521
Term Loan due 2007		255,626		255,626		255,626		255,626
Term Loan due 2008		465,000		465,000		-		-
Net premiums on long-term debt		9,613		9,613		12,205		12,205
		1,647,667		1,658,140		1,185,259		1,204,165
Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt:
Credit Facilities		100,000		100,000		420,000		420,000
Total consolidated debt and capital lease
obligations		3,251,932	$	3,358,182		2,601,514	$	2,733,055
Less fair value swaps of Panhandle		1,265				5,725
Less current portion of long-term debt
and capital lease (1)		461,011				126,648
Less short-term debt		100,000				420,000
Total consolidated long-term debt and
capital lease obligations	$	2,689,656			$	2,049,141
(1) Includes $1.3 million and $5.7 million of fair value of swaps related to debt classified as current at December 31, 2006
and 2005, respectively.

F-35

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt and Capital Lease Obligations.

Southern Union has $3.15 billion of long-term debt recorded at December 31, 2006, of which $461 million is current. Debt of $2.23 billion, including net premiums of $9.6 million, is at fixed rates ranging from 4.38 percent to 9.44 percent. Southern Union also has floating rate debt, including notes payable, totaling $1.02 billion bearing an average interest rate of 6.11 percent as of December 31, 2006. The variable rate bank loans are unsecured.

As of December 31, 2006, the Company has scheduled debt payments as follows:

											2012 and
	2007		2008		2009		2010		2011		thereafter
	(In thousands)
Southern Union Company	$	-	$	225,000	$	-	$	-	$	-	$	1,279,265
Panhandle		462,290		758,336		60,623		40,500		-		316,305
Total	$	462,290	$	983,336	$	60,623	$	40,500	$	-	$	1,595,570

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, and no debt is cross-collateralized.

LNG Holdings Term Loan. In connection with the December 1, 2006 closing on the transactions contemplated by the Redemption Agreement, LNG Holdings, an indirect wholly-owned subsidiary of the Company, as borrower, and PEPL and CrossCountry Citrus, LLC, each an indirect wholly-owned subsidiary of the Company, as guarantors, entered into a $465 million unsecured term loan facility due April 4, 2008 (2006 Term Loan). The interest rate under the 2006 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 the Company’s unsecured senior funded debt. At December 31, 2006, the interest rate was 6.22 percent, including a credit spread of 87.5 basis points over LIBOR. The proceeds of the 2006 Term Loan were used to repay the approximately $455 million of indebtedness of Transwestern Holding Company, LLC (Transwestern Holding), a wholly-owned subsidiary of CrossCountry Energy, LLC, and certain other obligations of Transwestern Holding.

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. The outstanding Sid Richardson Bridge Loan balance of approximately $525 million was retired using the proceeds from the debt offering and the remaining approximately $65 million of debt offering proceeds were used 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.

F-36

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Remarketing Obligation. In June 2003, the Company issued $125 million aggregate principal amount of 2.75% senior notes due August 16, 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 on August 16, 2006 at a price based on the preceding 20-trading day average closing price subject to a minimum conversion price per share of $13.82 (in which case 9.044 million shares would be issued) and a maximum conversion price of $16.86 (in which case 7.413 million shares would be issued). On August 16, 2006, the Company remarketed the 2.75% senior notes, which are now due August 16, 2008.

As part of the remarketing, the interest rate on the senior notes was reset to 6.15 percent. The senior notes will pay interest in arrears on each February 16 and August 16, commencing on February 16, 2007. The senior notes will mature on August 16, 2008. The senior notes are unsecured and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness from time to time outstanding.

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

Credit Facilities.On September 29, 2005, Southern Union entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400 million (Long-Term Facility). The Long-Term Facility has a five-year term and matures on May 28, 2010. The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount. Borrowings under the Long-Term Facility are available for Southern Union’s working capital and letter of credit requirements and for other general corporate purposes. The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (Senior Notes). As of December 31, 2006, the commitment fees were an annualized 0.15 percent. The Company has additional availability under uncommitted line of credit facilities with various banks.

Balances of $100 million and $420 million were outstanding under the Company’s credit facilities at effective interest rates of 6.02 percent and 4.73 percent at December 31, 2006 and December 31, 2005, respectively. As of February 16, 2007, there was a balance of $129 million outstanding under the Company’s credit facilities, with an effective interest rate of 6.0 percent.

Sid Richardson Bridge Loan. On March 1, 2006, Southern Union acquired Sid Richardson Energy Services 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. 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.

Interest expense totaling $49.2 million related to the Sid Richardson Bridge Loan was incurred during 2006 at an average interest rate of 5.72 percent. Debt issuance costs totaling $9.2 million were incurred in connection with the financing of the acquisition, of which $7.8 million was related to the Sid Richardson Bridge Loan and $1.4 million was related to the placement of permanent financing. The Company fully amortized the $7.8 million of the Sid Richardson Bridge Loan debt issuance cost to interest expense during 2006.

Other Debt Activity.

In conjunction with the Company’s sale of the assets of its PG Energy natural gas distribution division, $15 million of the Company’s First Mortgage Bonds were repaid. National Grid USA assumed $77 million of the Company’s First Mortgage Bonds in conjunction with its purchase of the Rhode Island operations of the Company’s New England Gas Company natural gas distribution division. See Note 19 - Discontinued Operations for related information.

F-37

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On July 14, 2005, the Company amended an existing short-term bank note to increase the principal amount thereunder from $15 million to $65 million in order to provide additional liquidity. The note is repayable upon demand. The Company borrowed $50 million under the note on July 19, 2005 at an initial interest rate of 4.54 percent, which was based on LIBOR plus 70 basis points. The Company repaid the $50 million additional principal amount on April 17, 2006.

On April 29, 2005, Panhandle refinanced LNG Holdings’ outstanding bank loans of $255.6 million (2005 Term Loan) for the same principal amount and extended the maturity date from January 31, 2007 to March 15, 2007. The 2005 Term Loan has substantially the same terms as the old notes with the exception of the following primary differences: (i) the assets of Trunkline LNG are not pledged as collateral; (ii) PEPL and Trunkline LNG each severally provided a guarantee for the notes; and (iii) the interest rate is tied to the rating of PEPL’s unsecured funded debt.

On November 17, 2004, an indirect, wholly-owned subsidiary of the Company entered into a $407 million bridge loan (CCE Holdings Bridge Loan) with a group of three banks in order to provide a portion of the funding for the Company’s investment in CCE Holdings. The CCE Holdings Bridge Loan had a maturity date of May 17, 2005 and bore interest at LIBOR plus 1.25 percent. The effective interest rate under the bridge loan agreement during the period was 3.50 percent. The Company repaid the CCE Holdings Bridge Loan in full during February 2005 from the proceeds of the Company’s common equity offering and the sale of its equity units on such dates, as required under the terms of the bridge loan agreement.

On March 12, 2004, Panhandle issued $200 million principal amount of its 2.75% Senior Notes due 2007, the proceeds of which were used to fund the redemption of the remaining $146.1 million principal amount of its 6.125% Senior Notes due 2004 that matured on March 15, 2004 and to provide working capital to the Company. A portion of the remaining net proceeds was also used to repay the remaining $52.5 million principal amount of Panhandle’s 7.875% Senior Notes due 2004 that matured on August 15, 2004.

In July 2003, Panhandle announced a tender offer for any and all of the $747.4 million outstanding principal amount of five of its series of senior notes then outstanding (Panhandle Tender Offer) and also called for redemption of all of the $134.5 million in principal amount of its two series of debentures then outstanding (Panhandle Calls). Panhandle repurchased approximately $378.3 million in principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396.4 million plus accrued interest through the purchase date. Panhandle also redeemed approximately $134.5 million of debentures through the Panhandle Calls for total consideration of $139.4 million, plus accrued interest through the redemption dates. As a result of the Panhandle Tender Offer, the Company recorded a pre-tax gain on the extinguishment of debt of $6.4 million during the year ended June 30, 2004. In August 2003, Panhandle issued $300 million of its 4.80% Senior Notes due 2008 and $250 million of its 6.05% Senior Notes due 2013, principally to refinance the repurchased notes and redeemed debentures. Also in August and September 2003, Panhandle repurchased $3.2 million in principal amount of its senior notes on the open market through two transactions for total consideration of $3.4 million, plus accrued interest through the repurchase date.

Panhandle Acquisition. In connection with the acquisition of Panhandle in June 2003, the Company added a principal amount of $1.16 billion in debt, which had a fair value of $1.21 billion as of the June 11, 2003 acquisition date. The debt included senior notes and debentures with interest rates ranging from 6.125 percent to 8.25 percent and floating rate debt totaling $275.4 million, all of which is non-recourse to Southern Union.

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. Certain 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.

F-38

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Long-Term Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent.
(b)	Under the Company’s Long-Term Facility, the Company must maintain an EBITDA 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.
(d)	All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $3 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 occurrence 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 cash management program; and limitations on the Company’s ability to prepay debt.

Retirement of Debt Obligations

The Company plans to refinance its debt coming due in March 2007 with proceeds from a $455 million multi-year bank term loan to LNG Holdings (2007 Expected TLNG Term Loan). The Company is near the final stages of consummating this refinancing, which is expected to close on or about March 12, 2007. The Company will use Wachovia Capital Markets and UniCredit Markets and Investment Banking as lead arrangers for the 2007 Expected TLNG Term Loan, which will be guaranteed by PEPL and Trunkline LNG. Borrowings based on the current term sheet under the 2007 Expected TLNG Term Loan will bear interest at LIBOR, plus a credit spread based on the senior unsecured credit ratings by Standard & Poor’s and Moody’s Investors Service for PEPL. Should the Company not be successful in the aforementioned refinancing effort, the Company would implement alternative refinancing plans, including a combination of drawing down on its existing revolving credit facility, utilizing cash from operations and additional commitments from third-party lenders, which are subject to material adverse change clauses and other customary terms and conditions, to repay the March 2007 obligations at maturity in the event the 2007 Expected TLNG Term Loan is not completed in the required timeframe.

The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital 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 these obligations under acceptable terms within the required timeframes. However, there can be no assurance the Company will be successful in its implementation of these refinancing plans and the Company’s inability to do so would cause a material adverse change to the Company’s financial condition.

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. At the beginning of 2006, the Company had eight pension plans. Effective August 24, 2006, the Company’s responsibility for benefit obligations under five of these 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.

F-39

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company has postretirement health care and life insurance plans (other postretirement plans) which cover substantially all Distribution and Transportation and Storage segment 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. At the beginning of 2006, the Company had six other postretirement plans. Effective August 24, 2006, the Company’s responsibility for benefit obligations under two of these plans was relieved upon the transfer of the plans to the buyer of the Rhode Island operations of New England Gas Company.

Due to the change in year end to December 31, effective with the transition period ended December 31, 2004, the Company now uses a September 30 measurement date for the majority of its plans. The Company previously used March 31 as its measurement date for the year ended June 30, 2004.

The following tables summarize the impact of the adoption of Statement No. 158, after recognition of the current period change in additional minimum liabilities (AML) under Statement No. 87, on the Company’s pension plans and other postretirement plans reported in the Consolidated Balance Sheet at December 31, 2006:

	Pension Plans
	Pre-SFAS 158						Pre-SFAS 158			SFAS 158
	without AML			AML			with AML			adoption			Post-SFAS
	adjustment			adjustment			adjustment			adjustment			158
	(in thousands)
Intangible asset (included in Deferred charges)	$	4,883		$	(1,085	)	$	3,798		$	(3,798	)	$	-
Pension liabilities, current (included in Other
current liabilities)		-			-			-			13			13
Pension liabilities, noncurrent (included in
Deferred credits)		58,062			(12,016	)		46,046			7,066			53,112
Accumulated deferred income taxes (benefit)		(16,234	)		4,128			(12,106	)		(4,107	)		(16,213	)
Accumulated other comprehensive income (loss), net of tax		(26,711	)		6,803			(19,908	)		(6,770	)		(26,678	)
Accumulated other comprehensive income (loss), pre-tax		(42,945	)		10,931			(32,014	)		(10,877	)		(42,891	)

	Other Postretirement Plans
	Pre-SFAS 158				Pre-SFAS 158		SFAS 158
	without AML		AML		with AML		adoption			Post-SFAS
	adjustment		adjustment		adjustment		adjustment			158
	(in thousands)
Prepaid postretirement costs (included in Deferred
charges)	$	-	$	-	$	-	$	248		$	248
Postretirement liabilities, current (included in Other
current liabilities)		-		-		-		87			87
Postretirement liabilities, noncurrent (included in
Deferred credits)		57,258		-		57,258		(29,402	)		27,856
Accumulated deferred income taxes		-		-		-		6,750			6,750
Accumulated other comprehensive income (loss), net of tax		-		-		-		22,813			22,813
Accumulated other comprehensive income (loss), pre-tax		-		-		-		29,563			29,563

F-40

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The adoption of Statement No. 158 had no effect on the Consolidated Statement of Operations for the year ended December 31, 2006, or for any prior period presented, has not negatively impacted any financial covenants, and is not expected to affect the Company’s operating results in future periods.

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table represents a reconciliation of the Company’s pension and other postretirement plans at December 31, 2006 and 2005.

							Other
	Pension Benefits At						Postretirement Benefits At
	December 31,						December 31,
	2006			2005			2006			2005
	(In thousands)
Change in Benefit Obligation:
Benefit obligation at beginning of period	$	415,338		$	398,516		$	115,148		$	168,953
Service cost		7,443			7,614			2,507			3,631
Interest Cost		20,889			22,396			5,556			7,594
Benefits paid		(19,668	)		(20,816	)		(4,418	)		(5,121	)
Actuarial (gain) loss and other		(24,347	)		19,956			(9,925	)		(31,701	)
Plan amendments		-			-			972			(28,208	)
Curtailment recognition		(28,119	)		103			(2,250	)		-
Settlement recognition (1)		(208,581	)		(12,431	)		(33,508	)		-
Benefit obligation at end of period	$	162,955		$	415,338		$	74,082		$	115,148
Change in Plan Assets:
Fair value of plan assets at beginning of period	$	298,289		$	276,835		$	45,509		$	37,962
Return on plan assets and other		17,187			35,936			3,203			1,487
Employer contributions		28,399			18,765			14,926			11,181
Benefits paid		(19,668	)		(20,816	)		(4,418	)		(5,121	)
Settlement recognition (1)		(215,574	)		(12,431	)		(12,987	)		-
Fair value of plan assets at end of period	$	108,633		$	298,289		$	46,233		$	45,509
Funded Status:
Funded status at measurement date	$	(54,322	)	$	(117,049	)	$	(27,849	)	$	(69,639	)
Contributions subsequent to measurement date		1,197			1,184			154			3,787
Funded status at end of period	$	(53,125	)		(115,865	)	$	(27,695	)		(65,852	)
Unrecognized net actuarial loss					128,930						9,404
Unrecognized prior service cost					9,085						(23,940	)
Net amounts recognized				$	22,150					$	(80,388	)
Amounts recognized in the Consolidated Balance Sheet (2):
Prepaid benefit cost	$	-		$	29,456		$	248		$	-
Accrued benefit liability		(53,125	)		(100,838	)		(27,943	)		(80,388	)
Intangible asset		-			8,249			-			-
Accumulated other comprehensive loss		-			85,283			-			-
Net asset (liability) recognized	$	(53,125	)	$	22,150		$	(27,695	)	$	(80,388	)
______________________
(1) Effective August 24, 2006, the Company transferred five pension plans and two other postretirement plans to the buyers
of the assets of the Company's PG Energy natural gas distribution division and the Rhode Island operations of its New England
Natural Gas Company natural gas distribution division.
(2) As of December 31, 2006, the Company’s pension plans had current liabilities of $13,000, noncurrent liabilities of $53.1 million and no noncurrent assets. The         Company's other postretirement plans had current liabilities of $87,000, noncurrent liabilities of $27.9 million and noncurrent assets of $248,000.

F-41

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The pre-tax amounts in Accumulated other comprehensive loss at December 31, 2006 that have not yet been recognized in net periodic benefit cost consist of:

			Other
	Pension Benefits		Postretirement Benefits
	(In thousands)
Net actuarial loss (gain)	$	39,093	$	(11,128	)
Prior service cost (credit)		3,798		(18,435	)
Total amount recognized	$	42,891	$	(29,563	)

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 2007 are $8 million and $500,000, 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 2007 are $(800,000) and $(3.0) million, respectively. No plan assets are expected to be returned to the Company during 2007.

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,			December 31,		December 31,
	2006		2005			2006		2005
	(In thousands)
Projected benefit obligation	$	162,955	$	379,474		N/A		N/A
Accumulated benefit obligation		155,876		348,593	$	68,033	$	115,148
Fair value of plan assets		108,633		246,571		39,937		45,509

The weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were as follows:

	Pension Benefits												Other Postretirement Benefits
							Six Months			Year									Six Months			Year
	Years Ended						Ended			Ended			Years Ended						Ended			Ended
	December 31,						December 31,			June 30,			December 31,						December 31,			June 30,
	2006			2005			2004			2004			2006			2005			2004			2004
Discount rate		5.77	%		5.50	%		5.75	%		6.00	%		5.78	%		5.50	%		5.75	%		6.00	%
Rate of compensation increase
(average)		3.24	%		3.24	%		3.40	%		3.60	%		N/A			N/A			N/A			N/A
Health care cost trend rate		N/A			N/A			N/A			N/A			11.00	%		12.00	%		13.00	%		13.00	%

F-42

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the assumed health care cost trend rates in measuring the accumulated postretirement benefit obligation:

	December 31,									June 30,
	2006			2005			2004			2004
Health care cost trend rate assumed for next year		11.00	%		12.00	%		13.00	%		13.00	%
Ultimate trend rate		4.80	%		4.65	%		4.75	%		4.75	%
Year that the rate reaches the ultimate trend rate		2013			2012			2012			2012

Net periodic benefit cost for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 includes the components noted in the table below. The table has been reclassified for all periods 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, $7.9 million, $3.5 million and $9.3 million for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively. Net periodic other postretirement benefit costs for discontinued operations totaled $(13.8) million, $2.9 million, $2.5 million and $4.3 million for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively. See Note 19 - Discontinued Operations for additional related information.

	Pension Benefits												Other Postretirement Benefits
							Six Months			Year									Six Months			Year
	Years Ended						Ended			Ended			Years Ended						Ended			Ended
	December 31,						December 31,			June 30,			December 31,						December 31,			June 30,
	2006			2005			2004			2004			2006			2005			2004			2004
	(In thousands)
Service cost	$	2,599		$	2,550		$	1,185		$	2,018		$	1,890		$	2,908		$	1,615		$	3,164
Interest cost		8,899			9,355			4,847			9,674			3,615			4,908			2,889			5,419
Expected return on plan assets		(8,909	)		(8,728	)		(4,525	)		(7,988	)		(1,871	)		(1,375	)		(509	)		(587	)
Prior service cost amortization		584			782			544			839			(3,011	)		(551	)		223			149
Recognized actuarial (gain) loss		7,236			5,364			2,022			3,331			(145	)		(163	)		(179	)		(575	)
Curtailment recognition		-			3,172			-			-			-			-			-			-
Settlement recognition		-			(644	)		(386	)		(445	)		-			-			-			-
Sub-total		10,409			11,851			3,687			7,429			478			5,727			4,039			7,570
Regulatory adjustment		(7,710	)		(7,521	)		-			-			2,665			2,665			1,332			2,665
Net periodic benefit cost	$	2,699		$	4,330		$	3,687		$	7,429		$	3,143		$	8,392		$	5,371		$	10,235

In the Distribution segment, the Company recovers certain qualified pension plan and other postretirement plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of pension costs be based on the Employee Retirement Income Security Act (ERISA) or other utility commission specific guidelines. The difference between these amounts and pension expense calculated pursuant to Statement No. 87 is deferred as a regulatory asset or liability and amortized to expense over periods promulgated by the applicable utility commission in which this difference will be recovered in rates.

F-43

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were as noted in the table below. The table has been reclassified for all periods 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
							Six Months			Year									Six Months			Year
	Years Ended						Ended			Ended			Years Ended						Ended			Ended
	December 31,						December 31,			June 30,			December 31,						December 31,			June 30,
	2006			2005			2004			2004			2006			2005			2004			2004
Discount rate		5.50	%		5.75	%		6.00	%		6.50	%		5.50	%		5.75	%		6.00	%		6.50	%
Expected return on assets -
tax exempt accounts		8.75	%		9.00	%		9.00	%		9.00	%		7.00	%		7.00	%		7.00	%		7.00	%
Expected return on assets -
taxable accounts		N/A			N/A			N/A			N/A			5.00	%		5.00	%		5.00	%		5.00	%
Rate of compensation increase		3.24	%		3.40	%		3.60	%		4.00	%		N/A			N/A			N/A			N/A
Health cost trend rate		N/A			N/A			N/A			N/A			11.00	%		13.00	%		13.00	%		13.00	%

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 check for reasonableness and appropriateness.

The following summarizes the assumed health care cost trend rates used in determining the net periodic benefit cost for the periods presented:

	December 31,									June 30,
	2006			2005			2004			2004
Health care cost trend rate assumed for next year		11.00	%		13.00	%		13.00	%		13.00	%
Ultimate trend rate		4.65	%		4.75	%		4.75	%		5.00	%
Year that the rate reaches the ultimate trend rate		2012			2012			2012			2011

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

		One Percentage Point		One Percentage Point
		Increase in Health Care		Decrease in Health Care
		Trend Rate		Trend Rate
		(In thousands)
Effect on total service and interest cost components	$	733	$	(588	)
Effect on accumulated post-retirement benefit obligation	$	7,092	$	(5,763	)

F-44

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Discount Rate Selection. The discount rate for each measurement date has been determined consistent with the discount rate selection guidance in Statement No. 87 and Statement No. 106 (as amended by Statement No. 158) 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 Plan Asset Information. 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.

Postretirement Health Care and Life Insurance Plans’ Asset Information. The assets of the postretirement health care and life insurance 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 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 postretirement plans are positioned to generate current income and exhibits 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 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 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 structure 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 September 30,						At September 30,
Asset Category	2006			2005			2006			2005
Equity securities		76	%		74	%		24	%		15	%
Debt securities		10	%		19	%		66	%		37	%
Other - cash equivalents		14	%		7	%		10	%		48	%
Total		100	%		100	%		100	%		100	%

No Company common stock is included in the equity securities at December 31, 2006. Equity securities included Company common stock in the amount of $22.4 million at December 31, 2005.

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.

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.

F-45

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The Company expects to contribute approximately $20.3 million to its pension plans and approximately $10.8 million to its other postretirement plans in 2007. The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

The estimated benefit payments, which reflect expected future service, as appropriate, projected to be paid are as follows:

			Other		Other
			Postretirement		Postretirement
			Benefits		Benefits
	Pension		(Gross, Before		(Medicare Part D
Years	Benefits		Medicare Part D)		Subsidy)
	(In thousands)
2007	$	10,613	$	4,454	$	535
2008		10,152		4,501		606
2009		10,670		4,243		680
2010		10,801		4,562		760
2011		10,735		4,824		651
2012-2016		59,146		33,433		4,256

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 to the participant’s compensation paid into the Savings Plan. Company con-tributions 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 is 100 percent vested after six years of continuous service. Company contributions to the Savings Plan during the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were $5.1 million, $4.5 million, $2.4 million and $4.1 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 2.5 percent to 11 percent. Company contributions to Retirement Power Accounts during the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004 were $5.1 million, $4.8 million, $2.9 million and $5.1 million, respectively.

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, 2006 and December 31, 2005, 863,458 and 826,348 shares, respectively, of common stock were held by various rabbi trusts for certain of those Company’s benefit plans.

Benefit Plan Termination. Effective June 30, 2005, the Company terminated its 1997 Supplemental Retirement Plan (Supplemental Plan), which was a non-contributory cash balance retirement plan for certain current and former executive employees of the Company. As a result, the Company had an estimated pension net loss of $1.3 million comprised of a $1.6 million loss on pension curtailment, recognized in the second quarter of 2005, and a $251,000 gain on pension settlement, recognized in the third quarter of 2005. Prior to the termination of the Supplemental Plan, the Company also recorded a $1.1 million loss on pension curtailment in the second quarter of 2005 that was triggered by pension payments made to a former executive of the Company under this plan.

F-46

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Also effective June 30, 2005, the Company terminated its 2000 Executive Deferred Stock Plan, which was a defined contribution deferred compensation plan for certain management and highly compensated employees. The plan’s assets were held in a rabbi trust and were distributed to participants during the fourth quarter of 2005. The termination of this plan did not have a material effect on the Company’s consolidated financial statements.

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:

					Six Months			Year
	Years Ended				Ended			Ended
	December 31,				December 31,			June 30,
Income Tax Expense	2006		2005		2004			2004
	(In thousands)
Current:
Federal	$	19,798	$	168	$	1,692		$	(15,677	)
State		2,251		1,062		(221	)		(2,224	)
		22,049		1,230		1,471			(17,901	)
Deferred:
Federal		74,563		43,110		7,143			51,372
State		12,635		5,712		1,292			8,582
		87,198		48,822		8,435			59,954
Total income tax expense from
continuing operations	$	109,247	$	50,052	$	9,906		$	42,053

F-47

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,				December 31,
Deferred Income Tax Analysis	2006				2005
	(In thousands)
Deferred income tax assets:
Alternative minimum tax credit	$	8,178		$	26,089
Post-retirement benefits		17,673			21,198
Pension benefits		13,810			34,017
Unconsolidated investments		11,530			11,345
Other		27,936			42,544
Total deferred income tax assets		79,127			135,193
Deferred income tax liabilities:
Property, plant and equipment		(624,797	)		(448,359	)
Unconsolidated investments-Citrus/CCE Holdings		(19,462	)		(7,961	)
Goodwill		(14,592	)		(19,365	)
Regulatory liability		(2,989	)		(14,620	)
Other		(34,976	)		(31,943	)
Total deferred income tax liabilities		(696,816	)		(522,248	)
Net deferred income tax liability		(617,689	)		(387,055	)
Less current income tax assets (liabilities)		(512	)		9,435
Accumulated deferred income taxes	$	(617,177	)	$	(396,490	)

Deferred creditsin the accompanying Consolidated Balance Sheet includes $133,000 and $4.7 million of unamortized deferred investment tax credit as of December 31, 2006 and December 31, 2005, respectively.

The Company completed an analysis of its deferred tax accounts in 2005. As a result of this analysis, income tax expense for the years ending December 31, 2006 and 2005 was decreased $8.4 million and $6.4 million, respectively, primarily due to adjustments related to bad debt reserves and PP&E. The decrease in income tax expense for the years ending December 31, 2006 and 2005 is comprised of federal income taxes of $7.5 million and $4.8 million, respectively, and state income taxes of $900,000 and $1.6 million, respectively.

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.

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. The Company paid $12.6 million of income tax in November 2006 and expects to receive a $1 million refund of income tax and pay $2.2 million of accrued interest in 2007 with respect to this settlement. The Company estimates the additional state liability to be approximately $1.9 million, plus interest to be paid in 2007. 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.

F-48

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Year			Year			Six Months			Year
	Ended			Ended			Ended			Ended
	December 31,			December 31,			December 31,			June 30,
Effective Income Tax Rate Analysis	2006			2005			2004			2004
	(In thousands)
Computed statutory income tax expense
from continuing operations at 35%	$	114,215		$	71,102		$	5,934		$	37,264
Changes in income taxes resulting from:
Valuation allowance		-			(11,942	)		11,942			-
Dividend received deduction		(10,696	)		(8,732	)		(9,800	)		-
Executive compensation, non deductible		5,063			-			-			-
State income taxes, net of federal income tax benefit		9,411			4,403			696			4,133
Analysis of deferred tax accounts		(7,490	)		(4,757	)		-			-
Other		(1,256	)		(22	)		1,134			656
Actual income tax expense from continuing operations	$	109,247		$	50,052		$	9,906		$	42,053

16. Regulation and Rates

Panhandle. Trunkline LNG Company, LLC’s (Trunkline LNG) Phase I expansion project was placed into service on April 5, 2006 with a total project cost of $141 million, plus capitalized interest. The expanded vaporization capacity portion of the project was placed into service on September 18, 2005. Phase II went into service on July 8, 2006. The final cost of Phase II was $79 million, plus capitalized interest. The expansions increased sustainable send-out capacity from .63 billion cubic feet per day (Bcf/d) to 1.8 Bcf/d, and storage increased from 6.3 Bcf to 9.0 Bcf. BG LNG Services has contracted for all of the capacity at the facility through 2028 with a rate moratorium through 2015. Approximately $671,000 and $102 million of costs are included in the line item Construction work-in-progress for the expansion projects at December 31, 2006 and 2005, respectively.

On February 11, 2005, Trunkline received approval from FERC to construct, own and operate a 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal. The pipeline creates additional transport capacity in association with the Trunkline LNG expansion and also includes new and expanded delivery points with major interstate pipelines. The new 36-inch pipeline was placed into service on July 22, 2005.

The Company has received approval from FERC and commenced construction of an additional enhancement at its Trunkline LNG terminal. This infrastructure enhancement project, which is expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. The project is expected to be in operation in 2008. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements through 2028, representing a five-year extension. Approximately $40.8 million and $9.4 million of costs are included in the line item Construction work-in-progress at December 31, 2006 and 2005, respectively.

The Company has received approval from FERC to modernize and replace various compression facilities on PEPL. Such replacements will be made at 12 different compressor stations and are expected to be installed by the end of 2009. The estimated cost of these replacements is approximately $290 million, which includes the compression component of a PEPL east end project already under construction. The Company has also filed for FERC approval to replace approximately 32 miles of existing pipeline on the east end of the PEPL system at an estimated cost of approximately $60 million, which would further improve system integrity. The project is planned to be completed in late 2007. Approximately $11.6 million and $46.3 million of costs, related to the compression modernization and east end enhancement projects, respectively, are included in the line item Construction work-in-progress at December 31, 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Trunkline Gas Company, LLC (Trunkline) has announced a field zone expansion project, which includes adding capacity to its pipeline system in Texas and Louisiana to increase deliveries to Henry Hub. The field zone expansion project includes the previously announced north Texas expansion as well as additional capacity to Henry Hub. Trunkline will increase the capacity along existing rights of way from Kountze, Texas, to Longville, Louisiana, by approximately 510 million cubic feet per day with the construction of approximately 45 miles of 36-inch diameter pipeline. The project includes horsepower additions and modifications at existing compressor stations. Trunkline also will create 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 will provide capacity of 475 million cubic feet per day from Kaplan, Louisiana to Henry Hub. Trunkline filed the project with FERC on September 11, 2006 with an anticipated in-service date during the fourth quarter of 2007. The cost estimate has been revised to approximately $200 million plus capitalized interest, including a $40 million contribution in aid of construction (CIAC) to a subsidiary of Energy Transfer toward construction costs to be incurred by Energy Transfer to move its delivery point to a location near Buna, Texas, increasing the field zone project capacity by up to 330,000 dekatherms per day. The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer, additional capacity created, and sale by Trunkline of the additional capacity. Approximately $12.5 million of costs for this project are included in the line item Construction work-in-progress at December 31, 2006.

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 Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage) requesting that FERC initiate an investigation into Southwest Gas Storage’s rates, terms and conditions of 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 Storage filed a cost and revenue study with FERC on February 20, 2007, with a hearing scheduled for August 27, 2007. The ultimate resolution of the Southwest Gas Storage matter has many variables and potential outcomes and it is impossible to predict its timing or materiality at this time.  No proceeding has been initiated against PEPL, but any potential rate reductions from such a proceeding would be expected to be mitigated by the impact of significant ongoing capital spending at PEPL for pipeline integrity, safety, environmental (including air emissions), compression modernization and other requirements.

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 regulation 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 rank the risk of their pipeline segments containing HCAs and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. While identification and location of all the HCAs has been completed, it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections. Therefore, the costs of implementing the requirements of this regulation are impossible to determine with certainty at this time. The required modifications and inspections are estimated to range from approximately $21 - $28 million per year, inclusive of remediation costs.

Missouri Gas Energy. On September 21, 2004, the Missouri Public Service Commission (MPSC) issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22.4 million, effective October 2, 2004. Missouri Gas Energy filed various appeals related to this matter seeking increased base revenues in addition to those contained in the MPSC’s order on grounds that the capital structure and 10.5 percent return on equity used by the MPSC in determining such increase did not provide an adequate rate of return. On April 11, 2006, the Missouri Supreme Court denied a hearing on this matter, effectively concluding the Company’s appeal. Missouri Gas Energy accounts for its revenues based upon the September 21, 2004 MPSC rate order.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. A hearing on this matter with the MPSC was held in January 2007, and the MPSC is expected to issue a ruling in the first quarter of 2007.

Through filings made on various dates, the staff of the MPSC has recommended that the MPSC disallow a total of approximately $47.7 million in gas costs incurred during the period July 1, 1997 through June 30, 2005. Missouri Gas Energy disputes the basis of $35.3 million of the total proposed disallowance, which appears to be the same as was rejected by the MPSC through an order dated March 12, 2002, applicable to the period July 1, 1996 through June 30, 1997. No date for a hearing in this matter has been set and it appears unlikely, based upon a ruling of the Missouri Supreme Court issued on January 30, 2007, that the $35.3 million disallowance will be pursued by the MPSC. Missouri Gas Energy also disputes the basis of $3.9 million of the total proposed disallowance, applicable to the period July 1, 2000 through June 30, 2001, which was the subject of a hearing concluded in November 2003, and is presently awaiting decision by the MPSC. In addition, Missouri Gas Energy disputes the basis of $4.1 million of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003; a hearing was held in August 2006. Finally, Missouri Gas Energy disputes the basis of $4.4 million of the proposed disallowance for the period of July 1, 2004 through June 30, 2005 (which appears to be the same as or very similar to the basis of the disallowance considered at the August 2006 hearing); this matter has not yet been set for hearing. 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.

New England Gas Company. On June 15, 2006, the New England Gas Company filed a notice of intent to file rate schedules for its Massachusetts operations with the MDTE. Such notice is a requirement in advance of filing for an increase in base gas rates. The Company has been engaged in settlement discussions with the Massachusetts Attorney General’s office regarding a rate increase and hopes to file a settlement with the MDTE in the first quarter of 2007.

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: 2007— $18.4 million; 2008—$13.6 million; 2009—$12.6 million; 2010— $11.4 million; 2011—$11.1 million and thereafter $24 million. Rental expense was $18.7 million, $20.1 million, $9.5 million and $17.8 million for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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, 2006 and December 31, 2005 to cover probable environmental response actions:

	December 31,		December 31,
	2006		2005
	(In thousands)
Current	$	5,098	$	6,541
Noncurrent		18,632		27,274
Total Environmental Liabilities	$	23,730	$	33,815

During the year ended December 31, 2006, the Company had $7 million of expenditures related to environmental cleanup programs.

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems.Panhandle is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted from the past use of lubricants containing polychlorinated biphenyls (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 recently discovered on the painted surfaces of equipment in a building that is outside of the scope of the compressed air system program and the existing PCB impacted paint program. The estimated cost to remediate the painted surfaces at this location is approximately $300,000. An assessment program is being developed to determine whether this condition exists at any of the other 78 similar buildings on the PEPL and Trunkline systems. Until the results of the assessment program are available, the costs associated with remediation of the painted surfaces cannot be reasonably estimated at this time.

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 potentially responsible parties. 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 financial position, results of operations or cash flows.

PEPL and Trunkline, together with other non-affiliated parties, have been 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. The notice demanded reimbursement to the U.S. EPA for costs incurred to date in the amount of approximately $1.8 million and encouraged each potentially responsible party (PRP) to voluntarily negotiate an administrative settlement agreement with the U.S. EPA within certain limited time frames providing for the PRPs to conduct or finance the response activities required at the site.  The demand was declined in a joint letter dated December 15, 2005 by the major PRPs including PEPL and Trunkline. 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 financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 16, 2005, PEPL experienced a release of liquid hydrocarbons near Pleasant Hill, Illinois. The release occurred in the form of a mist at a valve that was in use to reduce the pressure in the pipeline as part of maintenance activities. The hydrocarbon mist affected several acres of adjacent agricultural land and a nearby marina. Approximately 27 gallons of hydrocarbons reached the Mississippi River. PEPL contacted appropriate federal and state regulatory agencies and the U.S. 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 Illinois Environmental Protection Agency (Illinois EPA) 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. On December 14, 2005, the Illinois EPA notified PEPL that the matter might be considered for referral to the Office of the Attorney General, the State’s Attorney or the U.S. EPA for formal enforcement action and the imposition of penalties. By letter dated November 22, 2006, PEPL received a follow-up information request from the Illinois EPA on the status of certain measures PEPL had agreed to undertake in connection with the original responses to the violation notice. The Company believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

On July 10, 2006, PEPL identified the possible subsurface release of approximately 745 gallons of methanol from a tank located at the Howell compressor station. Subsequent testing of the tank and associated piping confirmed that a release had taken place. Impacted soils were excavated in accordance with state specific regulatory requirements. The impacted soils were transported to an authorized disposal facility. The appropriate federal and state environmental agencies were notified of this release. The Michigan Department of Environmental Quality (MDEQ) conducted an inspection of the remediation effort on October 17, 2006 and indicated that an appropriate response and remediation action had been implemented. A final remediation report was submitted to the MDEQ and U.S. EPA on January 25, 2007.

Air Quality Control. The U.S. EPA issued a final rule on regional ozone control (NOx SIP Call) in April 2004 that impacts Panhandle in two midwestern states, Indiana and Illinois. Based on a U.S. EPA guidance document negotiated with gas industry representatives in 2002, Panhandle is required in states that follow the EPA guidance to reduce nitrogen oxide (NOx) emissions by 82 percent on the identified large internal combustion engines and will be able to trade off engines within Panhandle in an effort to create a cost effective NOx reduction solution. The final implementation date is May 2007. The rule will affect 20 large internal combustion engines on Panhandle’s system in Illinois and Indiana with an approximate cost of $22.3 million for capital improvements through 2007, based on current projections. Approximately $21.6 million of the $22.3 million of capital expenditures have been incurred as of December 31, 2006. Indiana has promulgated state regulations to address the requirements of the NOx SIP Call rule that essentially follow the EPA guidance.

The Illinois EPA has distributed several draft versions of a rule to control NOx emissions from reciprocating engines and turbines statewide. The latest draft requires controls on engines regulated under the U.S. EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2011. The state is requiring the controls to comply with U.S. EPA rules regarding the NOx SIP Call, ozone non-attainment and fine particulate standards. The Illinois EPA has held multiple meetings with industry representatives to discuss the draft rule and is expected to propose the rule in the first quarter of 2007. The rule is currently being reviewed for potential impact to Panhandle. As currently drafted, the rule applies to all PEPL and Trunkline stations in Illinois and significant expenditures in addition to the $22.3 million associated with NOx reductions described above would be required for emission control.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2002, the Texas Commission on Environmental Quality enacted the Houston/Galveston SIP regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and requires the installation of emission controls. New regulations also require certain grandfathered facilities in Texas to enter into the new source permit program which may require the installation of emission controls at one additional facility owned by Panhandle. Management estimates capital improvements of $16.9 million will be needed at the two affected Texas locations. Approximately $16.1 million of the $16.9 million of capital expenditures have been incurred as of December 31, 2006.

The U.S. EPA promulgated various Maximum Achievable Control Technology rules in February 2004. The rules require that PEPL and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources. Most PEPL and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for PEPL and Trunkline is formaldehyde. As promulgated, the rule seeks to reduce formaldehyde emissions by 76 percent from these engines. Catalytic controls will be required to reduce emissions under these rules with a final implementation date of June 2007. PEPL and Trunkline could have up to 20 internal combustion engines subject to the rules. Management expects that compliance with these regulations will necessitate an estimated expenditure of $410,000 for capital improvements, based on current projections.

Spill Control. Environmental regulations were recently modified for U.S. EPA’s Spill Prevention, Control and Countermeasures (SPCC) program. The Company is currently reviewing the impact to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions 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.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems.Southern Union Gas Services is responsible for environmental remediation at certain sites on its gathering and processing systems. The contamination results primarily from releases of hydrocarbons. Southern Union Gas Services 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, Southern Union Gas Services submitted information to the Texas Commission on Environmental Quality (TCEQ) in connection with a request to permit the Grey Ranch, Texas facility to continue its current level of emissions. The State of Texas requires all previously grandfathered emission sources to obtain permits or to shut down by March 1, 2008. As the facility operator with a 50 percent interest in the site, Southern Union Gas Services is currently in negotiations with the TCEQ to finalize permit requirements for the Grey Ranch facility. Although Southern Union Gas Services is requesting that no control measures be required at this time, there can be no assurance such control measures will not be required. Costs associated with emission controls, if any, cannot be estimated with certainty at this time as a final permit has not been issued, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Spill Control. Environmental regulations were recently modified for U.S. EPA’s SPCC program. Southern Union Gas Services is currently reviewing the impact of these modifications on its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Distribution Segment Environmental Matters.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former manufactured gas plants (MGPs) and sites associated with the operation and disposal activities from 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 vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility, and 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 potentially responsible parties, 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 Massachusetts Department of Environmental Protection (MADEP) 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 has not been able to obtain access to a number of these off-site properties to complete the investigation and is working with MADEP to obtain access. The most recent reports filed with MADEP in September 2006 propose a temporary remedy for the upland portion of the site by means of an engineered barrier, construction of which is anticipated to start in 2007. Completion of the investigation and any necessary future remediation are contingent upon obtaining access to the off-site properties. It has recently been estimated that the Company will spend approximately $8.9 million 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, the Rhode Island Department of Environmental Management (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. The Case Management Order in that proceeding calls for the completion of discovery by May 11, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood. 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. The Court entered a scheduling order setting a deadline for completion of discovery by November 15, 2007. The Company will continue to vigorously defend itself against all four lawsuits. Parts of the Tiverton neighborhood appear to have been built on fill placed there at various times and include one or more historic waste disposal sites. Research is therefore underway by the Company to identify other PRPs associated with the fill materials and the waste disposal. Under the terms of the Purchase and Sale Agreement between the Company and National Grid USA, the potential obligation for the matters described above remains with the Company. Based upon its current understanding of the facts, the Company does not believe the outcome of these matters will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Mercury Release. The Company has completed an investigation of an incident involving the release of mercury stored in a New England Gas Company facility in Pawtucket, Rhode Island. On October 19, 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. State and federal authorities are also investigating the incident. The Company is discussing with the authorities New England Gas Company’s compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and communication requirements. The Company received and complied with a subpoena requesting documents relating to this matter. On January 12, 2007, the Company received another document subpoena in this matter. The Company is aware that the government continues to present evidence to a grand jury on this matter. The U.S. Attorney’s office in Rhode Island has advised the Company that this incident may give rise to unspecified criminal charges against the Company. While the Company believes any such charges would be unfounded, the Company now expects that criminal charges will be brought against the Company. The Company would vigorously defend any such action.

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 argued on June 9, 2006 and a hearing was held on February 16, 2007; no ruling on the motion has been made. In addition, an attorney for unspecified residents of the neighboring apartment complex who are not associated with the filed litigation has made a demand upon New England Gas Company. Under the terms of the Purchase and Sale Agreement between the Company and National Grid USA, the potential obligation for the matters described above remains with the Company. 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.

Hope Land.Hope Land Mineral Corporation (Hope Land) contends that it owns the storage rights to property that contains a portion of the Company’s Howell storage field. During June 2003, the Michigan Court of Appeals reversed the trial court’s previous order, which had granted summary judgment in favor of the Company and dismissed the case. The Company filed an appeal of the Court of Appeals order with the Michigan Supreme Court, which was denied in December of 2003. In April 2005, Hope Land filed trespass and unjust enrichment complaints against the Company to prevent running of the statute of limitations. The Company then filed an action for condemnation to obtain the storage rights from Hope Land. Pursuant to a pre-filing settlement with Hope Land, the Company obtained legal title to the storage rights upon the filing of the condemnation action. The unjust enrichment claims were dismissed and then reinstated on December 6, 2006. Trial is scheduled for April, 2007. The Company does not believe the outcome of this case will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of 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. 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 (Southwest). All of these actions eventually were transferred to the U.S. District Court for the District of Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of summary judgments granted, there were no claims allowed against the Company. 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. After the District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages, former Commissioner Irvin appealed to the Ninth Circuit Court of Appeals (Ninth Circuit). On July 25, 2005, the Ninth Circuit denied former Commissioner Irvin’s motions to set aside the verdict and affirmed the judgment against him for compensatory damages. The Ninth Circuit also determined that punitive damages against former Commissioner Irvin were appropriate but found that the $60 million punitive damage award against him was excessive. Accordingly, the Ninth Circuit remanded that issue to the District Court for further action. 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 has filed another notice of appeal. 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.

Mineral Management Service. In 1993, the U.S. Department of the Interior announced its intention to seek, through its Mineral Management Service (MMS), additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements and buyouts and buydowns of gas sales contracts with natural gas pipelines. PEPL and Trunkline, with respect to certain producer contract settlements, may be contractually required to reimburse or, in some instances, to indemnify producers against such royalty claims. The potential liability of the producers to the government and of the pipelines to the producers involves complex issues of law and fact, which are likely to take substantial time to resolve. If required to reimburse or indemnify the producers, PEPL and Trunkline may file with FERC to recover these costs from pipeline customers. The Company believes these commitments and contingencies will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies.

Hurricane-Related Expenditures. Late in the third quarter of 2005, after coming through the Gulf of Mexico, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast. These hurricanes caused damage to property and equipment owned by Sea Robin Pipeline Company, LLC (Sea Robin), Trunkline, and Trunkline LNG. Based on the latest damage assessments, there are revenue, expense and capital impacts resulting from Hurricanes Katrina and Rita in 2005 and 2006, mostly impacting Sea Robin and Trunkline LNG. During 2006 and 2005, revenue reductions resulting from the hurricanes were approximately $3 million for each year, not including lost opportunity revenues, and expense of approximately $2 million and $7 million was incurred in 2006 and 2005, respectively. As of December 31, 2006, the Company has incurred $30.8 million of capital expenditures related to the hurricanes primarily for replacement or abandonment of damaged property and equipment and construction project delays at the Trunkline LNG terminal.

F-57

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from Hurricane Rita in excess of its $5 million deductible. Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1 billion total limit on payout per claim. As of December 31, 2006, the Company has received payments of $1.6 million from the insurance carriers. No receivables due from the insurance carriers have been recorded as of December 31, 2006.

In addition, after the 2005 hurricanes, the MMS mandated inspections by leaseholders and pipeline operators along the hurricane tracks. The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be recovered to comply with applicable regulations. As a result, there was approximately $1.3 million of inspection-related expense recorded in 2006. Capital expenditures are estimated at $4.8 million, $1.1 million of which had been incurred as of December 31, 2006. The Company will seek recovery of these expense and capital amounts as part of the hurricane related claims.

Panhandle Capital Expenditures. The Company estimates expenditures associated with its Trunkline field zone expansion and LNG terminal enhancement projects to be approximately $450 million, with approximately $300 million to be incurred in 2007, plus capitalized interest. These estimates were developed for budgeting purposes and are subject to revision.

Energy Transfer Commitment. In November 2006, PEPL provided a guaranty to a subsidiary of Energy Transfer, a non-affiliate, for the full performance by Trunkline of a $40 million CIAC obligation related to a modification of a field zone expansion project. The CIAC would be made by Trunkline upon movement of Energy Transfer’s delivery point to a location near Buna, Texas, expected to be completed in late 2007. The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer, additional capacity created, and sale by Trunkline of the additional capacity.

Purchase Commitments. At December 31, 2006, 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 $1.4 billion. The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased. The Company has purchase 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 purchase gas tariffs.

TIF Debt Guarantee. The Company has a guaranty with a bank whereby the Company unconditionally guaranteed payment of financing obtained for the development of PEI Power Park. In March 1999, the Borough of Archbald, the County of Lackawanna, and the Valley View School District (collectively the Taxing Authorities) approved a Tax Incremental Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan requires that: (i) the Redevelopment Authority of Lackawanna County raise $10.6 million of funds to be used for infrastructure improvements of the PEI Power Park; (ii) the Taxing Authorities create a tax increment district and use incremental tax revenues generated from new development to service the $10.6 million debt; and (iii) PEI Power Corporation, a subsidiary of the Company, guarantee the debt service payments. In May 1999, the Redevelopment Authority of Lackawanna County borrowed $10.6 million from a bank under a promissory note (TIF Debt), which was refinanced and modified in May 2004. Beginning May 15, 2004 the TIF Debt bears interest at a variable rate equal to three-quarters percent (.75 percent) lower than the National Prime Rate of Interest with no interest rate floor or ceiling. The TIF Debt matures on June 30, 2011. Interest-only payments were required until June 30, 2003, and semi-annual interest and principal payments are required thereafter. As of December 31, 2006, the balance outstanding on the TIF Debt was $5.8 million with an interest rate of 7.5 percent. Estimated incremental tax revenues are expected to cover approximately 39 percent of the 2007 annual debt service. Based on information available at this time, the Company believes that the $3.1 million amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2006.

F-58

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $11.6 million in 2006 related to this program and estimates incurring approximately $135.8 million over the next 13.5 years, after which all service lines, representing about 50 percent of the annual safety program investment, will have been replaced.

Other. Effective May 1, 2004, the Company agreed to five-year contracts with each bargaining-unit representing Missouri Gas Energy employees.

Effective May 28, 2006, PEPL agreed to a three-year contract with a bargaining unit representing its employees.

Of the Company’s employees represented by unions, Missouri Gas Energy employs 61 percent, New England Gas Company employs 10 percent and Panhandle employs 29 percent. No employees of Southern Union Gas Services are currently represented by bargaining units.

The Company had standby letters of credit outstanding of $8.7 million and $8 million at December 31, 2006 and December 31, 2005, 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, subject to certain working capital adjustments. 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 subject to certain working capital adjustments.

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.

Earnings 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 PP&E 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 plant, property 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.

F-59

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

See Note 7 - Goodwill and Intangibles for information related to the $175 million goodwill impairment charge recorded in 2005 related to the Company’s discontinued operations.

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			Year Ended			Six Months Ended		Year Ended
	December 31,			December 31,			December 31,		June 30,
	2006  (2)			2005			2004		2004
	(In thousands,except per share amounts)
Operating revenues	$	512,935		$	752,549		$	276,489	$	650,506
Operating income (loss)		54,662			(106,073	)		13,986		78,007
Net earnings (loss) from
discontinued operations (1)		(152,952	)		(132,413	)		7,723		49,610
Net earnings (loss) available from
discontinued operations per share:
Basic	$	(1.33	)	$	(1.21	)	$	0.09	$	0.62
Diluted	$	(1.30	)	$	(1.17	)	$	0.09	$	0.61
__________________
(1)     Net earnings (loss) from discontinued operations do not include any allocation of corporate interest expense or other corporate costs.
(2)  Represents results of operations for year 2006 through August 24, 2006.

20. Asset Retirement Obligations

Statement No. 143 requires an ARO to be recorded when a legal obligation to retire the 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 an expected present value technique. This technique reflects 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, has an indeterminate life. In reaching this conclusion, management considered its intent for operating the pipeline system, the economic life of the underlying assets, its past practices and industry practice.

The Company intends to operate the pipeline system indefinitely as a going concern. Individual component assets have been and will continue to be replaced, but the pipeline system will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities and current estimates of recoverable reserves, management expects supply and demand to exist for the foreseeable future.

F-60

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets on the pipeline system may be replaced, the pipeline system itself will remain intact indefinitely. AROs generally do not arise unless a pipeline system (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, 2006.

	In Service
ARO Description	Date		Long-Lived Assets		Amount
					(In thousands)
Retire offshore lateral lines		Various		Offshore lateral lines	$	3,962
Other		Various		Mainlines, compressors and gathering plants		1,385

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

	Year Ended			Year Ended			Six Months Ended			Year Ended
	December 31,			December 31,			December 31,			June 30,
	2006			2005			2004			2004
	(In thousands)
Beginning balance	$	8,200		$	5,657		$	6,407		$	6,757
Addition from Sid Richardson
Energy Services acquisition		885			-			-			-
Incurred		1,189			2,371			-			395
Settled		(414	)		(285	)		(999	)		(1,373	)
Accretion expense		675			457			249			628
Ending balance	$	10,535		$	8,200		$	5,657		$	6,407

21. Reportable Segments

The Company’s operating segments are aggregated into reportable business segments 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.

The Transportation and Storage segment operations are conducted through Panhandle and the investment in Citrus. Through Panhandle, the Company is primarily engaged in the interstate transportation and storage 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 provides LNG terminalling and regasification services. Through its investment in Citrus, the Company has an interest in and operates Florida Gas. Florida Gas is primarily engaged in the interstate transportation of natural gas from 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.

The Company acquired Sid Richardson Energy Services on March 1, 2006, which represents the new Gathering and Processing reportable segment. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. (See Note 3 - Acquisition of Sid Richardson Energy Services.)

F-61

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The Company’s discontinued operations relate to its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division. During the first quarter of 2006, the Company entered into definitive agreements to sell 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. The Company completed the sales in August 2006. See Note 19 - Discontinued Operations.

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 earnings before interest and taxes (EBIT), which is 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 from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes;

·   income taxes;

·   interest; and

·   dividends on 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 operating cash flow.

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, 2006 and 2005, the six months ended December 31, 2004 or the year ended June 30, 2004.

The following table sets forth certain selected financial information for the Company’s segments for the years ended December 31, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004. Financial information for the Transportation and Storage segment reflects the Company’s ownership interest in CCE Holdings beginning on its acquisition date of November 17, 2004. Financial information for the Gathering and Processing segment reflects operations of Southern Union Gas Services 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. Segment information presented for expenditures of long-lived assets and total asset amounts by segment for all periods presented prior to year 2006 has not been adjusted for discontinued operations.

F-62

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year			Year			Six Months			Year
	Ended			Ended			Ended			Ended
	December 31,			December 31,			December 31,			June 30,
Segment Data	2006			2005			2004			2004
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	577,182		$	505,233		$	242,743		$	490,883
Gathering and Processing		1,090,216			-			-			-
Distribution		668,721			752,699			273,597			655,696
Total segment operating revenues		2,336,119			1,257,932			516,340			1,146,579
Corporate and other		4,025			8,950			1,509			2,689
	$	2,340,144		$	1,266,882		$	517,849		$	1,149,268
Depreciation and amortization:
Transportation and Storage	$	72,724		$	62,171		$	30,159		$	59,988
Gathering and Processing		47,321			-			-			-
Distribution		30,353			29,447			16,527			26,582
Total segment depreciation and amortization		150,398			91,618			46,686			86,570
Corporate and other		1,705			944			707			1,165
	$	152,103		$	92,562		$	47,393		$	87,735
Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	141,310		$	70,618		$	4,761		$	200
Gathering and Processing		(188	)		-			-			-
Corporate and other		248			124			(16	)		-
	$	141,370		$	70,742		$	4,745		$	200
Other income (expense), net:
Transportation and Storage	$	3,354		$	571		$	89		$	7,210
Gathering and Processing		1,571			-			-			-
Distribution		(2,130	)		(2,598	)		(1,397	)		(1,920	)
Total segment other income (expense), net		2,795			(2,027	)		(1,308	)		5,290
Corporate and other		37,123			(6,214	)		(17,830	)		(4,966	)
	$	39,918		$	(8,241	)	$	(19,138	)	$	324
Segment performance:
Transportation and Storage EBIT	$	417,536		$	281,344		$	94,971		$	200,912
Gathering and Processing EBIT		62,630			-			-			-
Distribution EBIT		41,883			61,698			4,266			39,611
Total segment EBIT		522,049			343,042			99,237			240,523
Corporate and other		14,324			(11,424	)		(20,686	)		(12,679	)
Interest		210,043			128,470			61,597			121,376
Federal and state income taxes		109,247			50,052			9,906			42,053
Net earnings from continuing operations		217,083			153,096			7,048			64,415
Earnings (loss) from discontinued operations before income taxes		(2,369	)		(111,588	)		11,744			76,660
Federal and state income taxes (benefit)		150,583			20,825			4,021			27,050
Net earnings (loss) from discontinued operations		(152,952	)		(132,413	)		7,723			49,610
Net earnings		64,131			20,683			14,771			114,025
Preferred stock dividends		17,365			17,365			8,683			12,686
Net earnings available for common stockholders	$	46,766		$	3,318		$	6,088		$	101,339

F-63

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year		Year		Six Months		Year
	Ended		Ended		Ended		Ended
	December 31,		December 31,		December 31,		June 30,
Segment Data	2006		2005		2004		2004
	(In thousands)
Total assets:
Transportation and Storage	$	3,874,318	$	3,155,549	$	2,348,354	$	2,197,289
Gathering and Processing		1,722,055		-		-		-
Distribution		1,016,491		2,490,164		2,448,750		2,231,970
Total segment assets		6,612,864		5,645,713		4,797,104		4,429,259
Corporate and other		169,926		191,106		771,185		143,199
Total consolidated assets	$	6,782,790	$	5,836,819	$	5,568,289	$	4,572,458
Expenditures for long-lived assets:
Transportation and Storage	$	244,821	$	189,415	$	111,886	$	131,378
Gathering and Processing		35,101		-		-		-
Distribution		47,954		84,896		56,442		78,791
Total segment expenditures for
long-lived assets		327,876		274,311		168,328		210,169
Corporate and other		4,798		2,306		10,109		15,884
Total consolidated expenditures for
long-lived assets	$	332,674	$	276,617	$	178,437	$	226,053

F-64

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Significant Customers and Credit Risk. The following tables provide summary information of significant customers for Panhandle and Southern Union Gas Services by applicable segment and on a consolidated basis for the periods presented.

	Percent of									Percent of
	Transportation and									Consolidated
	Storage Segment									Company Total
	Revenues									Operating Revenues
							For Six									For Six
	Years Ended						Months Ended			Years Ended						Months Ended
	December 31,						December 31,			December 31,						December 31,
Customer	2006			2005			2004			2006			2005			2004
BG LNG Services		24	%		17	%		16	%		6	%		4	%		5	%
ProLiance		12			16			17			3			4			5
Ameren Corp		10			11			11			3			3			3
Other top 10 customers		19			14			14			5			4			5
Remaining customers		35			42			42			8			10			13
Total percentage		100	%		100	%		100	%		25	%		25	%		31	%

	Percent of		Percent of
	Gathering and		Consolidated
	Processing Segment		Company Total
	Revenues		Operating Revenues
	Year Ended		Year Ended
Customer	December 31, 2006		December 31, 2006
ConocoPhillips Company	22	%	10	%
BP Energy Company	11		5
Constellation Power Source	10		5
Other top 10 customers	22		10
Remaining customers	35		17
Total percentage	100	%	47	%

F-65

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

22. Accumulated Other Comprehensive Loss

The table below provides an overview of Comprehensive income (loss) for the periods indicated:

							Six Months			Year
	Year Ended						Ended			Ended
	December 31,						December 31,			June 30,
Other Comprehensive Income (Loss)	2006			2005			2004			2004
	(In thousands)
Net Earnings	$                      64,131			$                      20,683			$                      14,771			$                    114,025
Other Comprehensive Income (loss) Adjustments:
Unrealized gain (loss) on interest rate hedges, net of tax of $(745),
$73, $2,031 and $4,293 respectively		(49	)		108		2,154			7,084
Reclassification of unrealized gain (loss) on interest rate hedges
into earnings, net of tax of $608, $608, $(2,089) and $(3,331),
respectively		967			967		(2,216	)		(5,497	)
Reversal of minimum pension liability related to disposition, net
of tax of $16,004, $0, $0 and $0, respectively		26,331			-		-			-
Minimum pension liability adjustment, net of tax of $4,128, $1,064,
$(8,328) and $6,526, respectively		6,803			1,771		(8,832	)		10,768
Change in fair value of commodity hedges, net of tax of $7,466,
$0, $0 and $0, respectively		12,360			-		-			-
Reclassification of unrealized gain (loss) on commodity hedges
into earnings, net of tax of $(4,266), $0, $0 and $0		(7,084	)		-		-			-
Total other comprehensive income (loss)		39,328			2,846		(8,894	)		12,355
Total comprehensive income	$	103,459		$	23,529	$	5,877		$	126,380

The table below provides an overview of the components in Accumulated other comprehensive loss as of the periods indicated:

	December 31,			December 31,
	2006			2005
	(In thousands)
Interest rate hedges, net	$	(2,312	)	$	(3,227	)
Commodity hedges, net		5,276			-
Benefit Plans:
Minimum pension liability, net		-			(53,045	)
Net actuarial loss and prior service costs, net - pensions		(26,678	)		-
Net actuarial gain and prior service credit, net - other postretirement benefits		22,813			-
Accumulated other comprehensive loss, net of tax	$	(901	)	$	(56,272	)

23.  Related Party Transactions

On November 5, 2005, 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 - CCEHoldings Transactions.

Pursuant to the Management Agreement, Southern Union billed CCE Holdings $4.3 million in 2005 for management fees. No billings were made for management fees in 2004 and 2006 under the Management Agreement. In addition, transition costs of $6 million were charged to CCE Holdings by PEPL during 2004. This amount, representing mainly severance and related costs, was recorded as a liability by PEPL with an offsetting amount recorded in Accounts receivable - related parties. In years 2006, 2005 and 2004, Southern Union billed CCE Holdings $14 million, $12 million and $1.8 million, respectively, 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.

F-66

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 1, 2006 and December 30, 2005, CCE Holdings paid CCE Acquisition LLC, a wholly-owned subsidiary of the Company, distributions totaling $48.8 million and $15 million, respectively. Such distributions were reflected as a return of investment by the Company.

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. After adoption of Statement No. 123R, the Company records 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. Prior to adoption, the Company used the intrinsic value method of accounting for stock-based compensation awards in accordance with APB No. 25, which generally resulted in no compensation expense for employee stock options with an exercise price no less than fair value on the date of grant. 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 stock appreciation rights generally vest over a three-, four- or five-year period from the date of grant and expire ten years after the date of grant. As of December 31, 2005, outstanding stock options totaled 2,549,134, of which 1,503,161 were vested. The remaining 1,045,973 stock options at December 31, 2005 vest over future periods and are used to determine compensation expense pursuant to the transition provisions of Statement No. 123R. The Company attributes the requisite service period to the vesting period. The adoption of Statement No. 123R 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.

F-67

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and other factors. 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. The Company’s estimate of the forfeiture rate was based primarily upon historical experience of employee turnover. To the extent that the Company revises this estimate in the future, the share-based compensation could be materially impacted in the quarter of revision, as well as in the following quarters. 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 Company expects to refine the method of deriving the expected term no later than January 1, 2008. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. The following table represents the Black-Scholes estimated ranges under the Company plans for grants issued in the following periods:

	Years ended				Year ended
	December 31,				June 30,
	2006		2005		2004
Expected volatility	32.90%		20.57% to 37.61%		36.75%
Expected dividend yield		1.43%		1.67%		0.00%
Risk-free interest rate		4.69%		3.76% to 4.63%		4.95%
Expected life		6.00 years		0.75 to 6.50 years		6.00 years
Note: There were no grants during the six month period ended December 31, 2004.

F-68

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2006 and 2005, the six months ended December 31, 2004 and the year ended June 30, 2004:

	Second Amended 2003 Plan				1992 Plan
	Shares			Average	Shares		Average
	Under			Exercise	Under		Exercise
	Option			Price	Option		Price
Outstanding July 1, 2003	-		$	-	3,142,935	$	$ 12.41
Granted	765,779			16.83	-		-
Exercised	-			-	(370,128)		9.44
Forfeited	(2,206)			16.83	(6,134)		14.65
Outstanding June 30, 2004	763,573		$	16.83	2,766,673	$	12.81
Granted	-			-	-		-
Exercised	-			-	(357,081)		12.69
Forfeited	(65,051)			16.83	(18,887)		14.63
Outstanding December 31, 2004	698,522		$	16.83	2,390,705	$	12.81
Granted	731,349			23.52	136,608		12.75
Exercised	(62,976)			16.83	(794,105)		12.47
Forfeited	(77,385)			16.83	(473,584)		12.45
Outstanding December 31, 2005	1,289,510		$	20.62	1,259,624	$	13.15
Granted	-	(1)		-	-		-
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
Exercisable June 30, 2004	-		$	-	2,132,852	$	12.52
Exercisable December 31, 2004	22,050			16.83	2,122,795		12.67
Exercisable December 31, 2005	355,259			21.85	1,147,902		13.06
Exercisable December 31, 2006	533,363			22.38	715,196		12.60
__________________________
(1) Excludes 133,610 stock appreciation rights (SARs) which vest in equal increments on December 27, 2007 through 2009. Each
SAR entitles the holder to shares of the Company's common stock equal to the fair market value of the Company's common stock in
excess of $28.07 for each SAR on the applicable vesting date.

At December 31, 2006 and 2005, no options were outstanding under the Pennsylvania Option Plan and the Pennsylvania Incentive Plan. At December 31, 2004, 466,127 and 231,668 shares were exercisable at weighted average exercise prices of $8.77 and $10.19 under the Pennsylvania Option Plan and the Pennsylvania Incentive Plan, respectively. At June 30, 2004, 466,127 and 228,451 shares were exercisable at weighted average exercise prices of $8.77 and $10.14 under the Pennsylvania Option Plan and the Pennsylvania Incentive Plan, respectively.

F-69

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2006:

	Second Amended 2003 Plan						1992 Plan
	Options Outstanding						Options Exercisable
			Weighted Average		Weighted					Weighted
Range of	Number of		Remaining		Average		Number of			Average
Exercise Prices	Options		Contractual Life		Exercise Price		Options			Exercise Price
Second Amended 2003 Plan:
16.82 - 22.49	316,427		7.09 years		$                      16.83		93,105		$	16.83
22.50 - 28.07		694,052		7.39 years		24.22		440,258		23.56
		1,010,479						533,363
1992 Plan:
9.69 - 12.49		146,945		0.49 years	$	9.70		146,945	$	9.70
12.50 - 14.66		568,251		2.56 years		13.35		568,251		13.35
		715,196						715,196

The weighted average remaining contractual life of options and SARs outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2006 was 8.38 and 2.13 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, 2006 was 8.35 and 2.13 years, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2006 was $17.6 million and $13.9 million, respectively.

As of December 31, 2006, there was $4.9 million of total unrecognized compensation cost related to non-expired 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, 2006 was $8.3 million. Compensation expense recognized related to stock options and SARs totaled $2.4 million ($1.9 million, net of tax) for the year ended December 31, 2006.

The intrinsic value of options exercised during the year ended December 31, 2006 was approximately $7 million, and the Company realized an additional tax benefit of approximately $1 million 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 Company’s 2006 Consolidated Statement of Cash Flows.

Restricted Stock. The Company’s Second Amended 2003 Plan also provides for grants of restricted stock and restricted stock units. The restrictions associated with a grant of restricted stock under the Second Amended 2003 Plan generally expire equally over a period of three or four 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 units expire equally over a period of three years and are payable in cash at the vesting date.

F-70

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of the status of nonvested restricted stock awards as of December 31, 2006 and changes during the year ended December 31, 2006, is presented below:

	Number of				Weighted-Average
	Restricted Shares				Grant-Date
Nonvested Restricted Stock	Outstanding				Fair-Value
Nonvested restricted shares at January 1, 2005	-			$	-
Granted	209,903				24.15
Vested		-			-
Forfeited		-			-
Nonvested restricted shares at December 31, 2005		209,903		$	24.15
Granted		137,036	(1)		26.50
Vested		(146,335	)		24.17
Forfeited		(31,820	)		24.44
Nonvested restricted shares at December 31, 2006		168,784		$	25.98
______________________
(1) Excludes 108,869 equity-based units (Cash Restricted Units), which vest in equal increments on December 27,
2007 through 2009. Each Cash Restricted Unit entitles the holder to a cash payment equal to the closing price of
the Company’s common stock on the applicable vesting date.

As of December 31, 2006, there was $4.6 million of total unrecognized compensation cost related to non-vested, restricted stock and Cash Restricted Units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 2 years. The total fair value of restricted shares that vested during the year ended December 31, 2006 was $3.5 million. Compensation expense recognized related to restricted stock and Cash Restricted Units totaled $4.3 million ($2.7 million, net of tax) for the year ended December 31, 2006.

The intrinsic value of restricted stock that vested during the year ended December 31, 2006 was approximately $3.6 million.

F-71

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

25. Quarterly Operations (Unaudited)

The following table presents the operating results for each quarter of the year ended December 31, 2006:

	Quarters Ended
	March 31		June 30			September 30			December 31
	(In thousands, except per share amounts)
Operating revenues	$	547,166	$	552,355		$	564,418		$	676,205
Operating income		102,847		69,792			69,961			112,485
Net earnings from continuing operations		73,418		16,321			11,829			115,515
Net earnings (loss) from discontinued operations		24,529		(2,587	)		(174,473	)		(421	)
Net earnings (loss) available for common
stockholders		93,606		9,393			(166,985	)		110,752
Diluted net earnings (loss) per share
available for common stockholders:
Continuing operations	$	0.60	$	0.10		$	0.06		$	0.92
Available for common stockholders	$	0.82	$	0.08			($1.42	)	$	0.92

The following table presents the operating results for each quarter of the year ended December 31, 2005:

	Quarters Ended
	March 31		June 30			September 30			December 31
	(In thousands, except per share amounts)
Operating revenues	$	452,100	$	195,236		$	186,480		$	433,066
Operating income		101,855		32,124			46,518			88,620
Net earnings from continuing operations		56,394		17,642			26,078			52,982
Net earnings (loss) from discontinued operations		35,802		(1,967	)		(6,487	)		(159,761	)
Net earnings (loss) available for common
stockholders		87,855		11,335			15,249			(111,121	)
Diluted net earnings (loss) per share
available for common stockholders:
Continuing operations	$	0.48	$	0.12		$	0.19		$	0.42
Available for common stockholders	$	0.81	$	0.10		$	0.13		$	(0.97	)

The sum of earnings per share 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-72

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

of Southern Union Company:

We have completed integrated audits of Southern Union Company’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, the six-month period ended December 31, 2004 and the year ended June 30, 2004 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 of financial statements 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.

As discussed in Note 14 to the consolidated financial statements, 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 Statement No. 87, 88, 106 and 132(R)", as of December 31, 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides 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.

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.

As described in Management's Report on Internal Control Over Financial Reporting, management has excluded Southern Union Gas Services from its assessment of internal control over financial reporting as of December 31, 2006 because it was acquired by the Company in a purchase business combination during 2006. We have also excluded Southern Union Gas Services from our audit of internal control over financial reporting. Southern Union Gas Services comprises the gathering and processing segment of the Company and has total assets and total revenues which represent 25 percent and 47 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 1, 2007

F-73

Citrus Corp. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2006, 2005 and 2004

with Report of Independent Registered Public accounting Firm

F-74

Consolidated Financial Statements
Years ended December 31, 2006, 2005 annd 2004
TABLE OF CONTENTS
		Page
Report of Independent Registered Public Accounting Firm		F-76
Audited Consolidated Financial Statements
	Consolidated Balance Sheets	F-77
	Consolidated Statements of Income	F-78
	Consolidated Statements of Stockholders' Equity	F-79
	Consolidated Statements of Comprehensive Income	F-79
	Consolidated Statements of Cash Flows	F-80
	Notes to Consolidated Financial Statements	F-81

F-75

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Stockholders of Citrus Corp. and Subsidiaries:

In our opinion, the accompanying consolidated balance sheetsand the related consolidated statements of income, of stockholders’ equity, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with the accounting principles generally accepted in the United States of America. These consolidated 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.

As discussed in Notes 2 and 6 to the consolidated financial statements, 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)," as of December 31, 2006.

/s/  PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2007

F-76

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
	December 31,			December 31,
	2006			2005
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	15,267		$	21,406
Accounts receivable - net of allowance for doubtful accounts of $282 and $23		45,049			41,072
Income tax receivable		-			872
Materials and supplies		2,954			3,077
Exchange gas receivable		-			508
Other		1,025			1,184
Total Current Assets		64,295			68,119
Property, Plant and Equipment, at Cost
Plant in service		4,163,082			4,118,518
Construction work in progress		85,746			9,693
Less - accumulated depreciation and amortization		(1,304,133	)		(1,211,663	)
Property, Plant and Equipment, Net		2,944,695			2,916,548
Other Assets
Unamortized debt expense		4,687			5,735
Regulatory assets		19,260			24,092
Other		88,176			74,893
Total Other Assets		112,123			104,720
Total Assets	$	3,121,113		$	3,089,387
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Long-term debt due within one year	$	84,000		$	14,000
Accounts payable - trade and other		37,741			21,325
Accounts payable - affiliated companies		2,823			5,501
Accrued interest		14,805			15,091
Accrued income taxes		2,375			-
Accrued taxes, other than income		9,332			9,090
Exchange gas payable		24,225			5,182
Other		16,040			6,161
Total Current Liabilities		191,341			76,350
Deferred Credits
Deferred income taxes		777,404			758,775
Regulatory liabilities		14,256			9,049
Other		8,129			33,070
Total Deferred Credits		799,789			800,894
Long-Term Debt		836,882			922,355
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		(10,524	)		(13,162	)
Retained earnings		669,353			668,678
Total Stockholders' Equity		1,293,101			1,289,788
Total Liabilities and Stockholders' Equity	$	3,121,113		$	3,089,387

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

F-77

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Revenues
Transportation of natural gas	$	485,189		$	476,049		$	467,422
Gas Sales		-			-			44,996
Total Revenues		485,189			476,049			512,418
Costs and Expenses
Natural gas purchased		-			-			48,921
Operations and maintenance		77,941			78,829			81,306
Depreciation and amortization		98,653			91,125			68,053
Taxes, other than income taxes		34,765			34,306			29,565
Total Costs and Expenses		211,359			204,260			227,845
Operating Income		273,830			271,789			284,573
Other Income (Expense)
Interest expense and related charges, net		(76,428	)		(79,290	)		(93,771	)
Other, net		4,633			6,531			15,262
Total Other Income (Expense)		(71,795	)		(72,759	)		(78,509	)
Income Before Income Taxes		202,035			199,030			206,064
Income Tax Expense		75,960			75,086			79,220
Net Income	$	126,075		$	123,944		$	126,844

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

F-78

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(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 Income
Balance, beginning of period		(13,162	)		(15,800	)		(17,247	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,638			2,638			1,447
Balance, end of period		(10,524	)		(13,162	)		(15,800	)
Retained Earnings
Balance, beginning of period		668,678			665,934			679,090
Net income		126,075			123,944			126,844
Dividends		(125,400	)		(121,200	)		(140,000	)
Balance, end of period		669,353			668,678			665,934
Total Stockholders' Equity	$	1,293,101		$	1,289,788		$	1,284,406
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
		2006			2005			2004
	(In thousands)
Net income	$	126,075		$	123,944		$	126,844
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,638			2,638			1,447
Total Comprehensive Income	$	128,713		$	126,582		$	128,291

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

F-79

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Cash flows provided by operating activities
Net income	$	126,075		$	123,944		$	126,844
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		98,653			91,125			68,053
Amortization of hedge loss in other comprehensive income		2,638			2,638			1,447
Amortization of discount and swap hedge loss in long term debt		527			530			535
Amortization of regulatory assets and other deferred charges		3,274			3,380			5,205
Amortization of debt costs		1,048			1,053			922
Deferred income taxes		18,629			12,740			69,694
Price risk management fair market valuation revaluation		-			-			10,980
Price risk gain on buy out of gas contracts		-			-			(19,884	)
Allowance for funds used during construction		(1,630	)		(1,441	)		(1,136	)
Gain on sale of assets		-			(1,236	)		-
Changes in operating assets and liabilities:
Accounts receivable		(3,327	)		403			(1,762	)
Accounts payable		(3,316	)		(10,567	)		(17,258	)
Accrued interest		(286	)		(324	)		(3,639	)
Accrued income tax		3,247			(7,204	)		5,183
Other current assets and liabilities		18,749			3,234			(9,680	)
Price risk management assets and liabilities		-			-			(23,162	)
Other assets and liabilities		(24,627	)		36,140			2,169
Net cash provided by operating activities		239,654			254,415			214,511
Cash flows used in investing activities
Capital expenditures		(106,023	)		(37,610	)		(48,982	)
Allowance for funds used during construction		1,630			1,441			1,136
Proceeds from sale of assets		-			1,715			-
Net cash used in investing activities		(104,393	)		(34,454	)		(47,846	)
Cash flows used in financing activities
Dividends		(125,400	)		(121,200	)		(140,000	)
Net (payments) borrowings on the revolving credit facility		(2,000	)		(75,000	)		117,000
Long-term debt finance costs		-			-			(746	)
Payments on long-term debt		(14,000	)		(14,000	)		(256,500	)
Net cash used in financing activities		(141,400	)		(210,200	)		(280,246	)
Net increase (decrease) in cash and cash equivalents		(6,139	)		9,761			(113,581	)
Cash and cash equivalents, beginning of period		21,406			11,645			125,226
Cash and cash equivalents, end of period	$	15,267		$	21,406		$	11,645
Supplemental disclosure of cash flow information
Interest paid (net of amounts capitalized)	$	72,067		$	74,714		$	95,770
Income tax paid	$	56,814		$	66,954		$	4,432

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

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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 (FGT), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2006 the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of Southern Natural Gas Company (Southern), and 50 percent byCrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry).Southern’s 50 percent ownership had previously been contributed by its parent, El Paso Corporation (El Paso) in March 2003. CrossCountry was a wholly-owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies. Effective November 17, 2004, CrossCountry became a wholly-owned subsidiary of CCE Holdings, LLC (CCE Holdings), which was a joint venture owned by subsidiaries of Southern Union Company (Southern Union) (50 percent), GE Commercial Finance Energy Financial Services (GE) (approximately 30 percent) and four minority interest owners (approximately 20 percent in the aggregate).

On December 1, 2006, a series of transactions were completed which resulted in Southern Union increasing its indirect ownership interest in Citrus from 25 percent to 50 percent. On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer), an unaffiliated company, entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings from GE 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 interest in Transwestern Pipeline Company, LLC (TW) (Redemption Agreement). Upon closing of the Redemption Agreement on December 1, 2006, Southern Union became the indirect owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus, with the remaining 50 percent of Citrus continuing to be owned by EPCH.

FGT, an interstate 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).

On September 1, 2006, FGT converted its legal entity type from a corporation to a limited liability company, pursuant to the Delaware Limited Liability Company Act.

  (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.

Regulatory Accounting - FGT’s accounting policies generally conform to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States for non-regulated entities. FGT is subject to regulation by the FERC.

Revenue Recognition - Revenues consist primarily of fees earned from gas transportation services. Reservation revenues on firm contracted capacity are recognized ratably over the contract period. 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 FGT 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. FGT establishes reserves for such

potential refunds, as appropriate. There were no potential rate refund reserves at December 31, 2006 and 2005, respectively.

Derivative Instruments - The Company was previously engaged in price risk management activities for both trading and non-trading activities and accounted for those contracts under SFAS No. 133,

Accounting for Derivative Instruments and Hedging Activities (Note 4). Instruments utilized in connection with trading activities

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

were accounted for on a mark-to-market basis and were reflected at fair value as Assets and Liabilities from Price Risk Management Activities in the Consolidated Balance Sheets. The Company classified price risk management activities as either current or non-current assets or liabilities based on their anticipated settlement date. Earnings from revaluation of price risk management assets and liabilities were included in Other Income (Expense). Cash flow hedge accounting is utilized for non-trading purposes to hedge the impact of interest rate fluctuations associated with the Company’s debt. Unrealized gains and losses from cash flow hedges, to the extent such amounts are effective, are recognized as a component of other comprehensive income, and subsequently recognized in earnings in the same periods as the hedged forecasted transaction affects earnings. The ineffective component from cash flow hedges is recognized in Other Income (Expense) each period. In instances where the hedge no longer qualifies as being effective, hedge accounting is terminated prospectively and the accumulated gain or loss is recognized in earnings in the same periods during which the hedged forecasted transaction affects earnings. Where fair value hedge accounting is appropriate, the offset that is attributed to the risk being hedged is recorded as an adjustment to the carrying amount of the hedged item and is recognized in earnings (Note 4). In the Company’s cash flow statement, cash inflows and outflows associated with the settlement of the price risk management activities are recognized in operating cash flows, and any receivables and payables resulting from these settlements are reported as trade receivables or payables on the balance sheet.

Property, Plant and Equipment(Note 10) - Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. FGT capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component (see second following paragraph). Costs of replacements and renewals of units of property are capitalized.  The original costs of units of property retired are charged to the accumulated depreciation, net of salvage and removal costs. FGT 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 FGT and other subsidiaries which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percentbased upon the estimated remaining useful life of the pipeline system.

FGT has provided for depreciation of assets net of estimated salvage value, on a straight-line basis, at an annual composite rate of 2.78 percent, 2.56 percent and 1.74 percent for the years ended December 31, 2006, 2005 and 2004, respectively. The increase was due to higher depreciation reflecting the settlement of FGT’s rate case effective April 1, 2005.

The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the 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 gross up, totaled $3.4 million, $1.4 million and $1.1 million for the years ended December 31, 2006, 2005 and 2004, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statements of income.

The Company applies the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations 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, Accounting for Asset Retirement Obligations, 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, FGT recorded an increase in plant in service and a liability for an

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 FGT’s pipeline system. The ARO asset at December 31, 2006 had a net book value of $0.5 million.

The table below provides a reconciliation of the carrying amount of the ARO liability for the period indicated.

	Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Beginning balance	$	493		$	-
Incurred		-			493
Settled		(36	)		-
Accretion Expense		24			-
Ending balance	$	481		$	493

The Company applies the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets to account for asset impairments. Under this standard, an asset is evaluated for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which an asset was intended to be used, decisions to sell an asset, and adverse changes in the legal or business environment such as adverse actions by regulators.

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 FGT’s tariff, and generally do not impact earnings.

Environmental Expenditures - 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 based on the nature of the cost incurred. Liabilities are recorded when environmental assessments and/or clean ups are probable and the cost can be reasonably estimated (Note 13).

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments with original maturities of three months or less. 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.

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.

Income Taxes (Note 5) - The Company accounts for income taxes under the provisions of SFAS No. 109,Accounting for Income Taxes. SFAS No. 109 provides for an asset and liability approach to accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 collectibility. Unrecovered accounts receivable charged against the allowance for doubtful accounts were $0.3 million, $0.0 million and $0.0 million in the years ended December 31, 2006, 2005 and 2004, respectively.

Use of Estimates- The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)”: Issued by the FASB in September 2006, the Statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. The Statement also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The recognition and disclosure provisions of the Statement, which is effective for fiscal years ending after December 15, 2006, was adopted by the Company effective December 31, 2006. The measurement provisions of the Statement are effective for fiscal years ending after December 15, 2008. (Note 6)

SEC Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006, the SEC provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB No. 108 did not materially impact the Company’s consolidated financial statements.

Accounting Principles Not Yet Adopted

FIN 48,” Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109” (FIN 48 or the Interpretation): Issued by the Financial Accounting Standards Board (FASB) in July 2006, this Interpretation 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. The Company has evaluated this guidance and does not believe its consolidated financial statements will be materially impacted.

FASB Statement No. 157, “Fair Value Measurements” (FASB Statement No. 157 or the Statement): Issued by the FASB in September 2006, this Statement 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 generally accepted accounting principles. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

  (3)Long Term Debt

The table below sets forth the long-term debt of the Company as of the dates indicated.

	Years		December 31, 2006					December 31, 2005
	Due		Book Value			Fair Value		Book Value			Fair Value
			(In thousands)
Citrus
8.490% Senior Notes		2007-2009	$	90,000		$	95,011	$	90,000		$	95,624
FGT
9.750% Senior B Notes		1999-2008		13,000			13,663		19,500			20,139
10.110% Senior C Notes		2009-2013		70,000			82,773		70,000			85,513
9.190% Senior Notes		2005-2024		135,000			167,004		142,500			182,012
7.625% Senior Notes		2010		325,000			348,137		325,000			353,940
7.000% Senior Notes		2012		250,000			271,893		250,000			275,737
Revolving Credit Agreement		2007		40,000			40,000		42,000			42,000
Total debt outstanding				923,000		$	1,018,481		939,000		$	1,054,965
Unamortized Debt Discount and Swap Loss				(2,118	)				(2,645	)
Total debt				920,882					936,355
Current portion of long-term debt				(84,000	)				(14,000	)
Total long-term debt			$	836,882				$	922,355

Annual maturities of long-term debt outstanding as of the date indicated were as follows:

	December 31,
	2006
Year	(In thousands)
2007	$	84,000
2008		44,000
2009		51,500
2010		346,500
2011		21,500
Thereafter		375,500
	$	923,000

On August 13, 2004 FGT entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50.0 million. Effective November 15, 2004 the commitment level was increased by $125.0 million to $175.0 million. Since that time, FGT has routinely utilized the 2004 Revolver to fund working capital needs. On December 31, 2006 and 2005 the amounts drawn under the 2004 Revolver were $40.0 millionand $42.0 million, respectively, with a weighted average interest rate of 6.08 percent and 5.11 percent (based on LIBOR plus 0.70 percent), respectively. Additionally, a commitment fee of 0.15 percent is payable quarterly on the unused commitment balance. The debt issuance costs accumulated for the 2004 Revolver at December 31, 2006 and 2005 were $0.2 million and $0.4 million, respectively. The Revolving Credit Agreement will terminate in August 2007. It is anticipated that a new revolving credit agreement will be entered into with similar terms and purpose, but there can be no assurance that management will be successful in renegotiating the revolving credit agreement.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The book value of the 2004 Revolver approximates its market value given the variable rate of interest. 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, 2006 and 2005 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

The agreements relating to FGT’s debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants, including a required ratio of consolidated funded debt to total capitalization. As of December 31, 2006 and 2005, FGT was in compliance with both affirmative and restrictive covenants of the note agreements.

Under the terms of its debt agreements, FGT may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and FGT’s 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 FGT have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or FGT 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 FGT to be accelerated.

Management believes that cash flow from operations and its ability to refinance its existing revolver provides the Company adequate liquidity to meet its working capital needs through December 31, 2007.  Should the Company not be successful in its refinancing efforts, the Company would implement alternative plans that include obtaining other liquidity sources, including new borrowings from third parties, deferring certain capital spending and deferring dividends to its partners.  While the Company believes that it could successfully complete the alternative plans, if necessary, there can be no assurance the Company would be successful in its implementation of such plans.

  (4)Derivative Instruments

The Company determined that its gas purchase contracts for resale and related gas sales contracts were derivative instruments and recorded these at fair value as price risk management assets and liabilities under SFAS No. 133, as amended. The valuation wascalculated using a discount rate adjusted for the Company’s borrowing premium of 250 basis points, which created an implied reserve for credit and other related risks. The Company estimated the fair value of all derivative instruments based on quoted market prices, current market conditions, estimates obtained from third-party brokers or dealers, or amounts derived using internalvaluation models. The Company performed a quarterly revaluation on the carrying balances that were reflected in current earnings. The impact to earnings from revaluation, mostly due to price fluctuations, was a loss of $11.0 million for the year ended December 31, 2004 and was included in Other Expenses. During the fourth quarter of 2004 the Company sold its remaining derivative contract without a material impact on the consolidated statements of income.

Trading ceased all trading activities effective the fourth quarter of 1997. It subsequently sold its remaining contracts and no longer has any gas purchase or gas sale contracts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

  (5)Income Taxes

The principal components of the Company's net deferred income tax liabilities as of the dates indicated were as follows:

	December 31, 2006		December 31, 2005
	(In thousands)
Deferred income tax asset
Regulatory and other reserves	$	8,595	$	8,841
Other		-		176
		8,595		9,017
Deferred income tax liabilities
Depreciation and amortization		742,566		728,444
Deferred charges and other assets		27,981		27,972
Regulatory costs		9,298		4,901
Other		6,154		6,475
		785,999		767,792
Net deferred income tax liabilities	$	777,404	$	758,775

Total income tax expense for the periods indicated was as follows:

	Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
	(In thousands)
Current Tax Provision
Federal	$	52,135	$	53,526	$	7,561
State		5,196		8,820		1,965
		57,331		62,346		9,526
Deferred Tax Provision
Federal		15,863		11,079		60,808
State		2,766		1,661		8,886
		18,629		12,740		69,694
Total income tax expense	$	75,960	$	75,086	$	79,220

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
	(In thousands)
Statutory federal income tax provision	$	70,712		$	69,661		$	72,122
State income taxes, net of federal benefit		5,176			6,813			7,053
Other		72			(1,388	)		45
Income tax expense	$	75,960		$	75,086		$	79,220
Effective Tax Rate		37.6	%		37.7	%		38.4	%

The Company had an alternative minimum tax (AMT) credit of $8.8 million which was used to offset regular income taxes payable in 2005. The AMT credit had an indefinite carry-forward period. For financial statement purposes, the Company had recognized the benefit of the AMT credit carry-forward as a reduction of deferred tax liabilities. The credit was fully utilized in 2005.

The Company files a consolidated federal income tax return separate from that of its parents.

  (6)Employee Benefit Plans

The employees of the Company were covered under Enron’s employee benefit plans until November 2004.

Certain retirees of FGT were covered under a deferred compensation plan managed and funded by Enron subsidiaries, one previously sold and the other now in bankruptcy. This matter has been included as part of the claim filed by FGT against Enron and another affiliated bankrupt company. FGT and Enron agreed in principle to a settlement, resulting in an allowed claim by FGT of approximately $3.4 million against Enron for the deferred compensation plan. Documents were approved by the bankruptcy court in May 2005. As a result of this settlement FGT assumed a deferred compensation plan liability of $1.8 million, which was recorded in 2004. The balances at December 31, 2006 and 2005 were $1.4 million and $1.8 million, respectively, and were reported in Other Current Liabilities ($0.3 million and $0.4 million, respectively) and in Other Deferred Credits ($1.1 million and $1.4 million, respectively) (Note 12). The anticipated proceeds from Enron for the bankruptcy claim described above were $0.5 million and were recorded as a long term receivable at December 31, 2004. In 2005 FGT assigned its claim to a third party and in June 2005 a payment of $0.8 million was received and recorded against the receivable. The excess $0.3 million was recorded as Other Income in the year ended December 31, 2005 (Note 8).

Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in the United States and certain employees in foreign countries. The basic benefit accrual was 5 percent of eligible annual base pay. Pension expense charged to the Company by Enron was $0.3 million for the year ended December 31, 2004. This excludes the Cash Balance termination amount discussed below.

In 2003 the Company recognized its portion of the expected Cash Balance Plan settlement by recording a $9.6 million current liability, which was cash settled in 2005 (Note 8), and a charge to operating expense. In 2004, with the settlement of the rate case (Note 9), FGT recognized a regulatory asset for its portion, $9.3

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million, with a reduction to operating expense. Per the rate case settlement FGT will amortize, over five years retroactive to April 1, 2004, its allocated share of costs to fully fund and terminate the Cash Balance Plan. Amortization recorded was $1.8 million, $1.9 million and $1.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006 and 2005 the remaining regulatory asset balance was $4.2 million and $6.0 million, respectively (Note 11). Based on the current status of the Cash Balance Plan termination cost and the amount expected to be allocated to the Company as its proportionate share of the plan’s termination liability, the Company continues to believe its accruals related to this matter are adequate. Although there can be no assurance that amounts ultimately allocated to and paid by the Company will not be materially different, we do not believe that the ultimate resolution of these matters will have a materially adverse effect on the Company’s consolidated financial position or cash flows, but it could have significant impact on the results of operations in future periods.

Effective November 1, 2004 all employees of the Company were transferred to an affiliated entity, CrossCountry Energy Services, LLC (CCES) and during November 2004, employee insurance coverage migrated (without lapse) from Enron plans to new CCES welfare and benefit plans. Effective March 1, 2005 essentially all such employees were transferred to FGT and became eligible at that time to participate in employee welfare and benefit plan adopted by FGT.

Effective March 1, 2005 FGT adopted the Florida Gas Transmission Company 401(k) Savings Plan (the Plan). All employees of FGT are eligible to participate and, within one Plan, 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 FGT to make discretionary profit sharing contributions for the benefit of all participants. FGT matches 50 percent of participant contributions under this Plan up to a maximum of 4% of eligible compensation. 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 were immediately vested. Administrative costs of the Plan and certain asset management fees are paid from Plan assets. FGT’s expensed its contribution of $0.4 million and $0.3 million for the years ended December 31, 2006 and 2005, respectively.

Other Post - Employment Benefits

Prior to December 1, 2004 FGT was a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986, as amended (Tax Code), which provided certain post-retirement medical, life insurance and dental benefits to employees of FGT and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. Enron filed a motion in the Enron bankruptcy proceedings on July 22, 2003 which was stayed and then refiled and amended on June 17, 2005 and again refiled and amended on December 1, 2006 which provides that each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust. On June 7, 2005 a class action suit captioned Lou Geiler et al v. Robert W. Jones, et al., was filed in United States District Court for the District of Nebraska by, among others, former employees of Northern Natural Gas Company (Northern) on behalf of the participants in the Northern Medical and Dental Plan for Retirees and Surviving Spouses against former and present members of the Trust Committee, the Trustee and the participating employers of the Trust, including FGT, claiming the Trust Committee and the Trustee have violated their fiduciary duties under ERISA and seeking a declaration from the Court binding on all participating employers of an accounting and distribution of the assets held in the Trust and a complete and accurate listing of the individuals properly allocated to Northern from the Enron Plan. On the same date essentially the same group filed a motion in the Enron bankruptcy proceedings to strike the Enron motion from further consideration. On February 6, 2006 the Nebraska action was dismissed. The plaintiffs filed an appeal of the dismissal on March 8, 2006. An agreement was reached on the conditions of the partition of the Trust among the VEBA participating employers, Enron and the Trust Committee and approved by the Enron

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

bankruptcy court on December 21, 2006. As a result the Nebraska action appeal was dismissed on January 25, 2007.

The net periodic post-retirement benefit cost charged to the Company by Enron was $0.6 million for the year ended December 31, 2004. Substantially all of this amount relates to FGT and was recovered through rates.

During the period December 1, 2004 through February 28, 2005, following FGT’s November 17, 2004 acquisition by CCE Holdings, coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits. FGT continues to provide certain retiree benefits through employer contributions to a qualified contribution plan, with the amounts generally varying based on age and years of service.

Effective March 1, 2005 such benefits are provided under an identical plan sponsored by FGT as a single employer post-retirement benefit plan.

With regard to its sponsored plan, FGT has entered into a VEBA trust (the “VEBA Trust”) agreement with JPMorgan Chase Bank Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, health, accident and other benefits. The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of the Company. FGT contributed $1.2 million and $1.5 million to the VEBA Trust for the years ended December 31, 2006 and 2005, respectively. Upon settlement of the Trust, any distribution of assets FGT receives from the Trust, estimated to be approximately $6.3 million per the Enron filing described above will be contributed to the VEBA Trust.

Prior to 2005, FGT’s general policy was to fund accrued post-retirement health care costs as allocated by Enron. As a result of FGT’s change in 2005 from a participant in a multi employer plan to a single employer plan, FGT now accounts for its OPEB liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits. At December 31, 2005 FGT recognized its OPEB liability by recording a deferred credit of $2.2 million (Note 12) and a corresponding regulatory asset of $2.2 million (Note 11).

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

Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of Statement No. 158. Statement No. 158 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. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive income in stockholder’s equity. Effective for years beginning after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date. The Company has not yet adopted the measurement provisions of Statement No. 158.

Prior to adoption of the recognition provisions of Statement No. 158, the Company accounted for its defined benefit postretirement plans under Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Statement No. 106 required that the liability recorded should represent the actuarial present value of all future benefits attributable to an employee’s service rendered to date. Under Statement No. 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 postretirement benefit plans. The Company's plan is in an overfunded position as of December 31, 2006.  As the plan assets are derived through rates charged to customers, under Statement No. 71, to the extent the Company has collected amounts in excess of what is required to fund the plan, the Company has an obligation to refund the excess amounts to customers through rates.  As such, the Company recorded the previously unrecognized

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changes in the funded status (i.e., actuarial gains) as a regulatory liability and not as an adjustment to accumulated other comprehensive income.

The following table summarizes the impact of adopting Statement No. 158 on the Company’s postretirement plan reported in the Consolidated Balance Sheet at December 31, 2006:

	Pre-SFAS 158			SFAS 158 adoption adjustment			Post-SFAS 158
	(in thousands)
Prepaid postretirement benefit cost (non-current) (Note 11)	$	(721	)	$	3,423		$	2,702
Regulatory asset		1,951			(1,951	)		-
Regulatory liability		-			(1,472	)		(1,472	)

The adoption of SFAS No. 158 had no effect on the Consolidated Statement of Operations for the year ended December 31, 2006, or for any prior period presented, does not affect any financial covenants, and will not affect the Company’s operating results in future periods.

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Postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table represents a reconciliation of FGT’s OPEB plan for the periods indicated.

	Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Change in Benefit Obligation
Benefit obligation at the beginning of period (1)	$	6,665		$	9,872
Service cost		46			71
Interest cost		312			490
Actuarial gain		(691	)		(3,522	)
Retiree premiums		427			757
Benefits paid		(964	)		(1,003	)
Benefit obligation at end of year		5,795			6,665
Change in Plan Assets
Fair value of plan assets at the beginning of period (1) (2)		7,840			6,240
Return on plan assets		(37	)		352
Employer contributions		1,231			1,494
Retiree premiums		427			757
Benefits paid		(964	)		(1,003	)
Fair value of plan assets at end of year		8,497			7,840
Funded Status
Funded status at the end of the year	$	2,702		$	1,175
Unrecognized net actuarial gain					(3,348	)
Net liability recognized				$	(2,173	)
Amount recognized in the Consolidated Balance Sheet
Regulatory assets (Note 11)	$	-		$	2,173
Other assets - other (Note 11)		2,702			-
Regulatory liability (Note 12)		(1,472	)
Deferred credits - other (Note 12)		-			(2,173	)
Net asset (liability) recognized	$	1,230		$	-

(1) For the purpose of this reconciliation, the plan adoption date is considered to be the same as the beginning period, January 1, 2005.

(2) Plan assets at December 31, 2006 and 2005 include the amount of assets expected to be received from the Enron Trust of $6.3 million.

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The weighted-average assumptions used to determine FGT’s benefit obligations for the periods indicated were as follows:

	Year Ended  December 31, 2006			Year Ended December 31, 2005
Discount rate		5.68	%		5.50	%
Health care cost trend rates		11.00	%		12.00	%
		graded to 4.85%by 2013			graded to 4.65% by 2012

FGT’s net periodic (benefit) costs for the periods indicated consisted of the following:

	Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Service cost	$	46		$	71
Interest cost		312			490
Expected return on plan assets		(402	)		(352	)
Recognized actuarial gain		(223	)		(174	)
Net periodic (benefit) cost	$	(267	)	$	35

The weighted-average assumptions used to determine FGT’s net periodic benefit costs for the periods indicated were as follows:

	Year Ended December 31, 2006			Year Ended December 31, 2005
Discount rate		5.50	%		5.75	%
Rate of compensation increase		N/A			N/A
Expected long-term return on plan assets		5.00	%		5.00	%
Health care cost trend rates		12.00	%		12.00	%
		graded to 4.65% by 2012			graded to 4.75% by 2012

FGT employs a building block approach in determining the expected long-term rate on return on plan assets. 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. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

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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 Point Increase		One Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	14	$	(13	)
Effect on postretirement benefit obligation	$	274	$	(245	)

Discount Rate Selection - The discount rate for each measurement date is selected via a benchmark approach that reflects comparative changes in the Moody’s Long Term Corporate Bond Yield for AA Bond ratings with maturities 20 years and above and the Citigroup Pension Liability Index Discount Rate.

The result is compared for consistency with the single rate determined by projecting the aggregate employer provided benefit cash flows from each plan for each future year, discounting such projected cash flows using annual spot yield rates published as the Citigroup Pension Discount Curve on the Society of Actuaries website for each measurement date and determining the single discount rate that produces the same discounted value. The result is rounded to the nearest multiple of 25 basis points.

Plan Asset Information - The plan assets shall be invested in accordance with sound investment practices that emphasize long-term investment fundamentals. An investment objective of income and growth for the plan has been adopted. 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 plan is positioned to generate current income and exhibits 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 plan 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 (iv) 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, this plan is 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 structure in a manner consistent with the investment policy.

FGT’s OPEB weighted-average asset allocation by asset category for the $2.0 million and $1.2 million of assets actually in the VEBA Trust at December 31, 2006 and 2005, respectively, was as follows:

	December 31, 2006			December 31, 2005
Equity securities		0	%		0	%
Debt securities		0	%		0	%
Cash and cash equivalents		100	%		100	%
Total		100	%		100	%

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Based on the postretirement plan objectives, asset allocations should be maintained 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 ten 10 percent.

The above referenced asset allocations for postretirement benefits are based upon guidelines established by FGT’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 versus these guidelines as a result of administrative oversight by the Investment Committee.

FGT expects to contribute approximately $0.5 million to its post-retirement benefit plan net of Medicare Part D subsidies in 2007.

The estimated benefit payments, which reflect expected future service, as appropriate, that are projected to be paid are as follows:

Years	Expected Benefits  Before Effect of Medicare Part D	Payments Medicare Part D	Net
(in thousands)
2007	$                                                                                    539	$                                                               89	$                                                             450
2008	583	93	490
2009	615	95	520
2010	622	96	526
2011	621	95	526
2012 - 2016	2,961	426	2,535

  (7)Major Customers and Concentration of Credit Risk

Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues for the periods indicated were approximately as listed below, and in total represented 58%, 54% and 50% of total revenue, respectively.

	Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
	(In thousands)
Florida Power & Light Company	$	200,592	$	181,486	$	189,500
Teco Energy, Inc.	$	80,192	$	76,059	$	68,971

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The Company had the following transportation receivables from these customers at the dates indicated:

	December 31, 2006		December 31, 2005
	(In thousands)
Florida Power & Light Company	$	15,065	$	15,153
Teco Energy, Inc.	$	6,161	$	5,365

The Company has a concentration of customers in the electric and gas utility industries. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. FGT sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.6 million and $1.2 million, and prepaymentsof $0.2 million and $0.5 million at December 31, 2006 and 2005, respectively. The Company's Management believes that the portfolio of FGT’s receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.

  (8)Related Party Transactions

In December 2001 Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy court. At December 31, 2004 FGT and Trading had aggregate outstanding claims with the Bankruptcy Court against Enron and affiliated bankrupt companies of $220.6 million. Of these claims, FGT and Trading filed claims totaling $68.1 and $152.5 million, respectively. FGT and Trading claims pertaining to contracts rejected by ENA were $21.4 and $152.3 million, respectively. In March 2005, ENA filed objections to Trading’s claim. In September 2006 the judge issued an order rejecting certain of Trading's arguments and ruling that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order is a reduction in the allowable amount of Trading's initial claim to $22.7 million. The parties have reached a settlement in principle on the matter which is awaiting a hearing with the Bankruptcy Court for approval (Note 15).

FGT’s claims against ENA on transportation contracts were reduced by approximately $21.2 million when a third party took assignment of ENA’s transportation contracts. In 2004 FGT settled the amount of all of its claims (including the deferred compensation retiree claim (Note 6)) against Enron and a subsidiary debtor. Total allowed claims (including debtor set-offs) were $13.3 million. After approval of the settlement by the Bankruptcy Court, in June 2005 FGT sold its claims, received $3.4 million and recorded Other Income of $0.9 million.

FGT had a construction reimbursement agreement with ENA under which amounts owed to FGT were delinquent. These obligations totaled approximately $7.4 million and were included in FGT’s filed bankruptcy claims. These receivables were fully reserved by FGT prior to 2003. Under the Settlement filed by FGT on August 13, 2004 and approved by the FERC on December 21, 2004 FGT will recover the under-recovery on this obligation by rolling in the costs of the facilities constructed, less the recovery from ENA, in its tariff rates (see Note 9). As part of the June 2005 sale of its claims, FGT received $2.1 million for this part of the claim.

The Company provided natural gas sales and transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these transportation services were approximately $1.0 million, $4.5 million and $3.7 million in the years ended December 31, 2006, 2005 and 2004, respectively. The Company’s gas sales were immaterial in the years ended December 31, 2006, 2005 and 2004. The Company also purchased gas from affiliates of Enron of approximately $0.0 million,

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$0.0 million and $5.8 million, and from affiliatesof El Paso of approximately $0.0 million, $0.0 million and $19.5 million in the years ended December 31, 2006, 2005 and 2004, respectively. FGT also purchased transportation services from Southern in connection with its Phase III Expansion completed in early 1995. FGT contracted for firm capacity of 100,000 Mcf/day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extension thereof. The amount expensed for these services totaled $6.6 million, $6.3 million and $6.5 million in the years ended December 31, 2006, 2005 and 2004, respectively.

FGT entered into a 20-year compression service agreement with Enron Compression Services Company (ECS) in March 2000, as amended, service under which commenced on April 1, 2002. This agreement required FGT to pay ECS to provide electric horsepower capacity and related horsepower hours to be used to operate an electric compressor unit within Compressor Station No. 13A. Amounts paid to ECS in the year ended December 31, 2004 totaled $2.4 million. Under related agreements, ECS was required to pay FGT an annual lease fee and a monthly operating and maintenance fee to operate and maintain the facilities. Amounts received from ECS in the year ended December 31, 2004 for these services totaled $0.4 million. A Netting Agreement, effective November 1, 2002, was executed with ECS, providing for the netting of payments due under each of the O&M, lease, and compression service agreements with ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services and related agreements to Paragon ECS Holdings, LLC, a non-affiliated entity.

Related to Enron’s bankruptcy, the Bankruptcy Court authorized an overhead expense allocation methodology on November 25, 2002. In compliance with the authorization, recipient companies subject to regulation and rate base constraints may limit amounts remitted to Enron to an amount equivalent to 2001, plus quantifiable adjustments. The Company invoked this regulation and rate base constraint limitation in the calculation of expenses accrued for January 1 through March 31, 2004. Effective April 1, 2004 services previously provided by bankrupt Enron affiliates to the Company pursuant to the allocation methodology ordered by the Bankruptcy Court were covered and charged under the terms of the Transition Services Agreement / Transition Supplemental Services Agreement (TSA/TSSA). This agreement between Enron and CrossCountry was administered by CrossCountry Energy Services, LLC (CCES), a subsidiary of CCE Holdings, which allocated to the Company its share of total costs. Effective November 17, 2004 an Amended TSA/TSSA agreement was put into effect. This agreement expired on July 31, 2005. The total costs are not materially different from those previously charged. The Company expensed administrative expenses from Enron and affiliated service companies of approximately $8.4 million, including insurance cost of approximately $6.7 million in the year ended December 31, 2004. The amount expensed for the seven months period ended July 31, 2005 was approximately $1.5 million.

On November 5, 2004, CCE Holdings entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a Delaware limited partnership and a wholly-owned subsidiary of Southern Union. Pursuant to the ASA, Manager was responsible for the operations and administrative functions of the enterprise, CCE Holdings and Manager shared certain operations of Manager and its affiliates, and CCE Holdings was obligated to bear its share of costs of the Manager and its affiliates. Costs are allocated by Manager and its affiliates to the operating subsidiaries and investees, based on relevant criteria, including time spent, miles of pipe, total assets, labor allocations, or other appropriate methods. The Manager provided services to CCE Holdings from November 17, 2004 to December 1, 2006. Following the closing of the Redemption Agreement on December 1, 2006, services continue to be provided by Southern Union affiliates to FGT, and costs allocated using allocation methods consistent with past practices.

The Company has related party activities for operational and administrative services performed by CCES, Panhandle Eastern Pipeline Company, LP (a subsidiary of Southern Union) and other related parties, on behalf of the Company, and corporate service charges from Southern Union.  Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies.  Amounts expensed by the Company were $20.6 million, $20.2 million and $15.6 million in the years ended December 31, 2006, 2005 and 2004, respectively, and included corporate service charges from Southern Union of $4.0 million, $1.6 million and $0.0 million in the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006 and 2005, the Company had current accounts payable to affiliated companies of $2.8 million and $5.5 million, respectively, relating to these services.

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In 2005, the Company paid a subsidiary of CCE Holdings $9.6 million to settle the Cash Balance Plan obligation, which CCE Holdings effectively paid in conjunction with the 2004 acquisition of the Company.

The Company paid cash dividends to its shareholders of $125.4 million, $121.2 million and $140.0 million in the years ended December 31, 2006, 2005, and 2004, respectively.

  (9)Regulatory Matters

On August 13, 2004 FGT filed a Stipulation and Agreement of Settlement ("Rate Case Settlement") in its Section 4 rate proceeding in Docket No. RP04-12, which established settlement rates and resolved all issues. The settlement rates were approved and became effective on April 1, 2004 for all FGT services and again on April 1, 2005 for Rate Schedule FTS-2 when the basis for rates on FGT’s incremental facilities changed from a levelized cost of service to a traditional cost of service.

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 regulation defines as “high consequence areas” (“HCA”). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify 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 risk rank their pipeline segments containing HCAs, and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to in excess of $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. While identification and location of all the HCAs has been completed, it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections. Therefore, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to be in the range of approximately $16-$20 million per year, inclusive of remediation costs. Pursuant to the August 13, 2004 Rate Case Settlement, FGT has the right to make limited sections 4 filings to recover, via a surcharge during the settlement’s term, depreciation and return on up to approximately $40 million in security, integrity assessment and repair costs, and Florida Turnpike relocation and modification costs. Costs incurred for such projects in service through December 31, 2006 are expected to create a surcharge of $0.02 per MMBtu effective on April 1, 2007.

In June 2005 FERC issued an order Docket No. AI05-1-000 that expands on the accounting guidance in the proposed accounting release issued in November 2004 on mandated pipeline integrity programs. The order interprets the FERC’s existing accounting rules and standardizes classifications of expenditures made by pipelines in connection with an integrity management program. The order is effective for integrity management expenditures incurred on or after January 1, 2006. FGT capitalizes all pipeline assessment costs based on its August 13, 2004 Rate Case Settlement. The Rate Case Settlement contained no reference to the FERC Docket No. AI05-1-000 regarding pipeline assessment costs and provided that the final FERC order approving the Rate Case Settlement constituted final approval of all necessary authorizations to effectuate its provisions. The Rate Case Settlement provisions became effective on March 1, 2005 and new tariff sheets to implement these provisions were filed on March 15, 2005. FERC issued an order accepting the tariff sheets on May 20, 2005. In the year to December 31, 2006, FGT completed and capitalized $6.7 million on pipeline assessment projects, as part of the integrity programs.

On October 5, 2005 FGT filed an application with FERC for the Company’s proposed Phase VII expansion project. The proposed project will expand FGT’s existing pipeline infrastructure in Florida and provide the growing Florida energy market access to additional natural gas supply from the Southern LNG Elba Island liquefied natural gas import terminal near Savannah, Georgia. The Phase VII project calls for FGT to build approximately 33 miles of 36-inch diameter pipeline looping in several segments along an existing right of way and install 9,800 horsepower of compression to be constructed in two phases. The expansion will provide about 160 million cubic feet per day of additional capacity to transport natural gas from a connection

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

with Southern Natural Gas Company’s proposed Cypress Pipeline project in Clay County, Florida. The project’s two phases are expected to be in service in May 2007 and May 2009. The estimated cost of expansion is up to approximately $104 million. The FERC issued an order approving the project on June 15, 2006 and construction commenced on November 6, 2006.

On October 20, 2005, FGT filed an application with FERC for the Company’s State Road 91 Relocation Project. The proposed project will consist of the abandonment of approximately 11.15 miles of 18-inch diameter pipeline and 10.75 miles of 24-inch diameter pipeline in Broward, County Florida. The replacement pipeline will consist of approximately 11.15 miles of 36-inch diameter pipeline. The abandonment and replacement is being performed to accommodate the widening of State Road 91 by the Florida Department of Transportation/Florida Turnpike Enterprise (FDOT/FTE). The estimated cost of the pipeline relocation project is estimated at $110.5 million and FGT is seeking recovery of the construction costs from the FDOT/FTE. The FERC issued an order approving the project on May 3, 2006. FGT has requested authorization to commence construction on February 21, 2007.

  (10)Property, Plant and Equipment

The principal components of the Company's property, plant and equipment at the dates indicated were as follows:

	December 31, 2006			December 31, 2005
	(In thousands)
Transmission plant	$	2,859,920		$	2,812,586
General plant		24,970			26,383
Intangible plant		25,726			27,083
Construction work-in-progress		85,746			9,693
Acquisition adjustment		1,252,466			1,252,466
		4,248,828			4,128,211
less: Accumulated depreciation and amortization		(1,304,133	)		(1,211,663	)
Property, Plant and Equipment, net	$	2,944,695		$	2,916,548

  (11)Other Assets

The principal components of the Company's regulatory assets at the dates indicated were as follows:

	December 31,		December 31,
	2006		2005
	(In thousands)
Ramp-up assets, net (1)	$	11,928	$	12,240
Cash balance plan settlement (Note 6)		4,185		6,047
Other post employment benefits (Note 6)		-		2,173
Environmental non-PCB clean-up cost (Note 13)		1,000		1,000
Other miscellaneous		2,147		2,632
Total Regulatory Assets	$	19,260	$	24,092

(1) Ramp-up assets are regulatory assets which FGT was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company's other assets at the dates indicated were as follows:

	December 31,		December 31,
	2006		2005
	(In thousands)
Long-term receivables	$	71,648	$	72,570
Fuel tracker		11,747		-
Other post employment benefits (Note 6)		2,702		-
Other miscellaneous		2,079		2,323
Total Other Assets - other	$	88,176	$	74,893

  (12)Deferred Credits

The principal components of the Company's regulatory liabilities at the dates indicated were as follows:

	December 31,		December 31,
	2006		2005
	(In thousands)
Balancing tools (1)	$	12,154	$	9,049
Other post employment benefits (Note 6)		1,472		-
Other miscellaneous		630		-
Total Regulatory liabilities	$	14,256	$	9,049

(1) Balancing tools are a regulatory method by which FGT recovers the costs of operational balancing of the pipeline’s system. The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.

The principal components of the Company's other deferred credits at the dates indicated were as follows:

	December 31,		December 31,
	2006		2005
	(In thousands)
Post construction mitigation costs	$	2,073	$	2,600
Construction prepayments		-		4,536
Customer deposits (Note 7)		-		1,249
Fuel tracker		-		14,477
Deferred compensation (Note 6)		1,090		1,425
Environmental non-PCB clean-up cost reserve (Note 13)		1,423		1,631
Tax contingency		1,664		2,594
Asset retirement obligation (Note 2)		481		493
Other post employment benefits (Note 6)		-		2,173
Other miscellaneous		1,398		1,892
Total Deferred Credits - other	$	8,129	$	33,070

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  (13)Environmental Reserve

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments resulted in increased operating expenses. These increased operating expenses did not have a material impact on the Company’s consolidated financial statements.

FGT conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities. The anticipated costs over the next five years are: 2007 - $0.2 million, 2008 - $0.3 million, 2009 - $0.1 million, 2010 - $0.2 million and 2011 - 0.3 million. The expenditures thereafter are estimated to be $0.5 million for soil and groundwater remediation. The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.6 million and $1.7 million at December 31, 2006 and 2005, respectively. Costs of $0.1 million, $0.8 million and $0.3 million were expensed during the years ended December 31, 2006, 2005 and 2004, respectively. FGT recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.0 million and $1.0 million at December 31, 2006 and 2005, respectively (Note 11), as a regulatory asset based on the probability of recovery in rates in its next rate case.

Prior to December 31, 2005, no such liability was recognized since it was previously estimated to be less than $1 million, and therefore, considered not to be material. Amounts incurred for environmental assessment and remediation were expensed as incurred.

  (14)Accumulated Other Comprehensive Income

Deferred gains and (losses) in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income. Such amounts are being amortized over the terms of the hedged debt.

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

	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Interest rate lock on 7.625% $325 million note due 2010	$	1,872		$	1,872		$	1,872
Interest rate swap loss on 7.0% $250 million note due 2012		1,228			1,228			1,229
Interest rate swap gain on 9.19% $150 million note due 2005-2024		(462	)		(462	)		(1,654	)
	$	2,638		$	2,638		$	1,447

F-101

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides an overview of the components in accumulated other comprehensive income at the dates indicated.

	Termination Date		Amortization Period		Original Gain/(Loss)			December 31, 2006			December 31, 2005
					(In thousands)
Interest rate lock on 7.625% $325 million note due 2010		December 2000		10 years	$	(18,724	)	$	(7,334	)	$	(9,206	)
Interest rate swap loss on 7.0% $250 million note due 2012		July 2002		10 years		(12,280	)		(6,807	)		(8,035	)
Interest rate swap gain on 9.19% $150 million note due 2005-2024		November 1994		20 years		9,236			3,617			4,079
								$	(10,524	)	$	(13,162	)

  (15)Commitments and Contingencies

From time to time, in the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. Where appropriate, Citrus has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters. Management believes the final disposition of these matters will not have a material adverse effect on the Company’s’ results of operations or financial position.

The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages that may, over the next ten years, impact one or more of FGT’s mainline pipelines co-located in FDOT/FTE rights-of-way. FGT is currently considering its options relating to the first phase of the turnpike project, which include replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida. Estimated cost of such replacement would be $110 million. FGT is also in discussions with the FDOT/FTE related to additional projects that may affect FGT’s 18- and 24-inch pipelines within FDOT/FTE right-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 right-of-way costs, cannot be determined at this time.

Under certain conditions, existing agreements between FGT and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for FGT to pay for rearrangement or relocation costs. Under certain other conditions, FGT may be entitled to reimbursement for the costs associated with relocation, including construction and right-of-way costs. On April 8, 2005, FGT filed a complaint in the Ninth Judicial Circuit, Orange County, Florida seeking a declaratory judgment order finding, among other things, that FGT has a compensable property interest in certain easements and agreements with the FDOT/FTE, and that FGT is entitled to recover: (i) compensation for any of FGT’s right-of-way to be taken, (ii) costs incurred and to be incurred by FGT for relocation of its pipeline in connection with FDOT/FTE’s changes to State Road 91; and (iii) $5.5 million in expenditures related to a prior relocation project (for which an invoice was presented to FDOT/FTE that FDOT/FTE refused to pay). FGT also sought an order declaring that FDOT/FTE has a duty to avoid conflict at FGT facilities when reasonably possible and to provide sufficient rights-of-way to allow FGT to fully operate, relocate and maintain its facilities in a manner contemplated by the agreements or pay compensation for the loss of FGT’s property rights. On August 15, 2006, FGT also filed a motion for temporary injunction seeking to halt construction pending the trial date, which motion was denied by the court on October 11, 2006. On November 2, 2006, FGT filed to dismiss the action without prejudice. On January 25, 2007, FGT filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, which seeks relief with respect to three specific sets of FDOT widening projects in Broward County.  The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. Should FGT 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 borrowing. FGT expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the

F-102

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FDOT/FTE to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT 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 FGT for its costs.

FGT and Trading previously filed bankruptcy-related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Of these claims, FGT and Trading filed claims totaling $68.1 and $152.5 million, respectively. FGT and Enron agreed on the amount of the claim at $13.3 million, and FGT assigned its claims to a third party and received $3.4 million in June 2005. Trading’s claim is for rejection damages on two physical/financial swaps and a gas sales contract, as well as certain delinquent amounts owed pre-petition. In March 2005, Enron North America Corp. (ENA) filed objections to Trading’s claim. In September 2006 the judge issued an order which rejected certain of Trading's arguments and ruled that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order is a reduction in the allowable amount of Trading's initial claim to $22.7 million. The parties have reached a settlement in principle on the amount of the allowed claim which is awaiting a hearing with the Bankruptcy Court for approval.  

On March 7, 2003, Trading filed a declaratory order action, involving a contract between it and Duke Energy LNG Sales, Inc. (Duke). Trading requested that the court declare that Duke breached the parties’ natural gas purchase contract by failing to provide sufficient volumes of gas to Trading. The suit sought damages and a judicial determination that Duke had not suffered a “loss of supply” under the parties’ contract, which could, if it continued, have given rise to the right of Duke to terminate the contract at a point in the future. On April 14, 2003, Duke sent Trading a notice that the contract was terminated as of April 16, 2003 (due to Trading’s alleged failure to timely increase the amount of a letter of credit); although it disagreed with Duke’s position, Trading increased the letter of credit on April 15, 2003. Duke answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit, and that it had breached a “resale restriction” on the gas. Trading disputed that it had breached the agreement, or that any event had given rise to a right to terminate by Duke. On June 2, 2003, Trading notified Duke that, because Duke had defaulted and failed to cure, Trading was terminating the agreement effective as of June 5, 2003. On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187 million, and recorded a receivable of $75 million (subsequently reduced by $6.5 million to $68.5 million to provide for a related settlement, see below). Trading moved for summary judgment and Duke cross-moved on the central issue of whether Duke’s failure to perform was justified under the letter of credit requirements of the agreements. The judge denied the motions from both parties in his ruling dated August 23, 2005 and subsequently ordered the parties to attempt to narrow the scope of the issues to be tried. Pre-trial conferences were held in January 2007, a jury was selected and opening arguments were scheduled. Following the judge’s rulings on certain matters, on January 29, 2007 Citrus reached a settlement with Spectra Energy LNG Sales, Inc, formerly known as Duke Energy LNG Sales, Inc, and its parent company Spectra Energy Corp. (collectively “Spectra”), whereby Spectra agreed to pay $100 million to Citrus. This transaction will result in an approximately $23 million pre-tax ($14 million after-tax) gain realized and subsequently to be recorded in the first quarter 2007.

Prior to the Enron bankruptcy, Enron North America Corp. (ENA) was the principal counterparty to Trading’s gas purchase and sale agreements (including swaps). ENA has rejected these contracts in bankruptcy. A pre-petition gas purchase payable to ENA of $12.4 million was reversed in 2003 when it was determined that the Company had a right of offset against claims for pre-petition receivables. Pursuant to an existing operating agreement which was rejected by ENA in 2003 but under which an El Paso affiliate performed, an affiliate of El Paso was required to buy gas, purchased from a significant third party that exceeded the requirements of Trading’s existing sales contracts. Under this third party contract, gas was purchased primarily at rates based upon an indexed oil price formula. This gas was then sold primarily at market rates. On April 16, 2003 the significant third party supplier terminated the supply contract. Trading then only purchased the requirements to fulfill existing sales contracts from third parties at market rates. As a result of these developments, the cash flow stream was dependent on variable pricing, whereas before Enron’s bankruptcy, the cash flow stream was fixed (under certain swaps). In June 2004 the Company paid $16.2 million and recorded an accrual for a contingent obligation of up to $6.5 million to terminate a gas sales contract with a third-party, resulting in a net gain totaling $19.9 million. The contingent obligation was extinguished with a payment to the third-party on February 6, 2007 of $6.5 million from proceeds resulting from the settlement of the Duke Energy LNG Sales, Inc. (Duke) litigation.

F-103

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Name State or Country of Incorporation

Panhandle Eastern Pipe Line Company, LP	Delaware
Trunkline Gas Company, LLC	Delaware
Trunkline LNG Company, LLC	Delaware
Pan Gas Storage, LLC	Delaware
CCE Holdings, LLC	Delaware
Southern Union Gas Services, Ltd.	Texas
Southern Union Gas Energy, Ltd.	Texas
Sea Robin Pipeline, LLC	Delaware
PEI Power Corporation	Pennsylvania

Note:Certain wholly-owned subsidiaries of Southern Union Company are not named above. Considered in the aggregate as a single subsidiary, these unnamed entities would not constitute a "significant subsidiary" at the end of the year covered by this report. Additionally, the Company has other subsidiaries that conduct no business except to the extent necessary to maintain their corporate name or existence.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-37261, 33-69596, 33-69598, 33-61558, 333-79443, 333-08994, 333-42635, 333-89971, 333-36146, 333-36150 and 333-112527) and Form S-3 (File No. 333-137998) of Southern Union Company of our report dated March 1, 2007 relating to the consolidated financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 1, 2007

EX-24

Exhibit 24

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears below constitutes and appoints Richard N. Marshall and Robert M. Kerrigan, III, or either of them, acting individually or together, as such person's true and lawful attorney(s)-in-fact and agent(s), with full power of substitution and revocation, to act in any capacity for such person and in such person's name, place and stead in any and all capacities, to sign the Annual Rerport on Form 10-K for the year ended December 31, 2006 of Southern Union Company, a Delaware corporation, and any amendments thereto, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission and the New York Stock Exchange.

Dated: March 1, 2007

/s/ GEORGE L. LINDEMANN George L. Lindemann	/s/ KURT A. GITTER, M.D. Kurt A. Gitter, M.D.
/s/ DAVID BRODSKY David Brodsky	/s/ THOMAS N. McCARTER, III Thomas N. McCarter, III
/s/ FRANK W. DENIUS Frank W. Denius	/s/ GEORGE ROUNTREE, III George Rountree, III
/s/ HERBERT H. JACOBI Herbert H. Jacobi	/s/ ALLAN D. SCHERER Alan D. Scherer
/s/ ADAM M. LINDEMANN Adam M. Lindemann

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

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

I, George L. Lindemann, certify that:

(1)I have reviewed this Report on Form 10-K of Southern Union Company;

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

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

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

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

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

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

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

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

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

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

Date: March 1, 2007

/s/ GEORGE L. LINDEMANN

George L. Lindemann

Chairman of the Board, President and

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

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

I, Richard N. Marshall, certify that:

(1)I have reviewed this Report on Form 10-K of Southern Union Company;

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

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

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

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

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

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

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

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

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

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

Date: March 1, 2007

/s/ RICHARD N. MARSHALL

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-K of Southern Union Company (the “Company”) for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George L. Lindemann, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ GEORGE L. LINDEMANN

George L. Lindemann

Chairman of the Board, President and

Chief Executive Officer

March 1, 2007

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

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-K of Southern Union Company (the “Company”) for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard N. Marshall, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RICHARD N. MARSHALL

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

March 1, 2007

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

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

EX-10.P

Exhibit 10(p)

CAPITAL STOCK AGREEMENT

In Connection With The

CAPITAL STOCK OF CITRUS CORP.

June 30, 1986

SONAT INC.

ENRON CORP.

HOUSTON NATURAL GAS CORPORATION

CITRUS CORP.

TABLE OF CONTENTS

	Page
SECTION 1 - DEFINITIONS...................................................................................................................................................................................................................................................................................	2
SECTION 2 - INVESTMENT REPRESENTATION..............................................................................................................................................................................................................................................	8
SECTION 3 - CAPITAL STOCK OF CITRUS.......................................................................................................................................................................................................................................................	8
(a) Ownership and Original Issuance.....................................................................................................................................................................................................................................	8
(b)Transfers of Shares Between Principals and Their Subsidiaries.....................................................................................................................................................................................................................................................	8
(c)Disposition of Shares.........................................................................................................................................................................................................................................................	10
(d) Sale of Shares......................................................................................................................................................................................................................................................................	11
(e)Pledge of Shares and Rights under this Agreement….................................................................................................................................................................................................	14
(f)Opinion of Counsel.............................................................................................................................................................................................................................................................	15
(g)Legend on Certificates.......................................................................................................................................................................................................................................................	16
(h)Limitations...........................................................................................................................................................................................................................................................................	16
SECTION 4 - BOARD OF DIRECTORS................................................................................................................................................................................................................................................................	17
SECTION 5 - CHAIRMAN OF THE BOARD......................................................................................................................................................................................................................................................	18
SECTION 6 - INFORMAL MEETINGS OF PRINCIPALS.................................................................................................................................................................................................................................	19
SECTION 7 - PERFORMANCE OF AGREEMENTS..........................................................................................................................................................................................................................................	19
SECTION S - PRINCIPAL OFFICE OF CITRUS.................................................................................................................................................................................................................................................	19
SECTION 9 - AUDITORS.....................................................................................................................................................................................................................................................................................	19
SECTION 10 - INSPECTION; BOOKS AND RECORDS..................................................................................................................................................................................................................................	20
SECTION 1l-OPERATING AGREEMENT..........................................................................................................................................................................................................................................................	20
SECTION 12 - PIPELINE EXPANSION..............................................................................................................................................................................................................................................................	20
SECTION 13 - FINANCING.................................................................................................................................................................................................................................................................................	21
SECTION 14 - VOTING SECURITIES OF THE PRINCIPALS........................................................................................................................................................................................................................	21
SECTION 15 - BUY-SELL RIGHTS.....................................................................................................................................................................................................................................................................	23
SECTION 16 - CHANGE OF CONTROL............................................................................................................................................................................................................................................................	26
SECTION 17 - TERM OF AGREEMENT............................................................................................................................................................................................................................................................	31
SECTION 18 - NOTICE.........................................................................................................................................................................................................................................................................................	32
SECTION 19 - GOVERNING LAW......................................................................................................................................................................................................................................................................	33
SECTION 20 - HEADINGS...................................................................................................................................................................................................................................................................................	33
SECTION 21 - SUCCESSORS BOUND...............................................................................................................................................................................................................................................................	33
SECTION 22 - NO WAIVER................................................................................................................................................................................................................................................................................	34
SIGNATURES........................................................................................................................................................................................................................................................................................................	34

ii.

CAPITAL STOCK AGREEMENT

THIS AGREEMENT dated June 30, 1986, among SONAT INC. ("Sonat"), a Delaware corporation, ENRON CORP. ("Enron"), a Delaware corporation, formerly named InterNorth, Inc., HOUSTON NATURAL GAS CORPORATION ("HNG"), a Texas corporation and wholly owned subsidiary of Enron, and CITRUS CORP. ("Citrus"), a Delaware corporation.

WITNESSETH:

WHEREAS, Citrus has, at the date of this Agreement, an authorized capital stock of 1,000 shares of Common Stock, $1 par value ("Common Stock"), consisting of 500 shares of Class A Common Stock ("Class A Common Stock") and 500 shares of Class B Common Stock ("Class B Common Stock"); and

WHEREAS, at the date of this Agreement, the shares of capital stock of Citrus which are issued and outstanding are 500 shares of Class A Common Stock, which are owned and held by Sonat, and 500 shares of Class H Common Stock, which are owned and held by HNG; and

WHEREAS, Citrus has two wholly owned subsidiaries, Florida Gas Transmission Company ("Florida Gas"), a Delaware corporation, and Florida Intrastate Pipeline Company ("Florida Intrastate"), a Florida corporation; and

WHEREAS, Sonat and HNG wish to make certain representations in connection with the shares of Common Stock now owned by them; and

WHEREAS, the parties hereto wish to enter into certain agreements relating to the ownership and disposition of the capital stock of Citrus, certain business arrangements regarding the management of Citrus and related matters;

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto agree as follows:

1. Definitions. For the purposes of this Agreement:

(a)"Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as in effect on the date of this Agreement.

(b)A Person shall be deemed the "Beneficial Owner" of and shall be deemed to "beneficially own” any securities:

(i)which such Person or any of such Person's Affiliates or Associates beneficially owns, directly or indirectly;

(ii)which such Person or any of such Person's Affiliates or Associates, directly or indirectly, has (A) the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding, or upon the exercise of

2.

conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the "Beneficial Owner" of, or to "beneficially own," securities tendered pursuant to a tender or exchange offer made by or on behalf of such Person or any of such Person's Affiliates or Associates until such tendered securities are accepted for purchase; or (B) the right to vote or dispose of pursuant to any agreement, arrangement or understanding; provided, however, that a Person shall not be deemed the "Beneficial Owner" of, or to “beneficially own," any security under this clause (B) as a result of an agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (1) arises solely from a revocable proxy given to such Person in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable rules and regulations of the Exchange Act and (2) is not also then reportable on Schedule 13D under the Exchange Act (or any comparable or successor report); or

(iii) which are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such

3.

Person or any of such Person's Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (B) of subparagraph (ii) of this paragraph (b)} or disposing of any securities of a Principal.

(c)"Capital Stock" means the Common Stock and any class of capital stock of Citrus hereafter authorized and includes any security of Citrus convertible into such stock and any right to purchase or acquire any such stock or any security convertible into such stock.

(d)A "Change of Control" of a Principal shall be deemed to have occurred if (i) any Person shall become the Beneficial Owner of securities representing 50%or more of the aggregate voting power of such Principal's outstanding Voting Securities or (ii) there shall occur a change in the composition of a majority of the Board of Directors of such Principal that shall not have received the prior approval of the Continuing Directors of such Principal; provided, however, that neither of the foregoing events shall be deemed to be a Change of Control if such event has been approved by the Continuing Directors of the Principal prior to such Person (or any Affiliate or Associate of such Person) becoming the Beneficial

4.

Owner of 20% or more of the aggregate voting power of such Principal's outstanding Voting Securities.

(e) A "Continuing Director" of a Principal means each member of such Principal's Board of Directors as of March 27, 1986 and any successor of a Continuing Director who is recommended to succeed a Continuing Director by a majority of the Continuing Directors then in office.

(f) "Expansion" means the construction of necessary pipeline, compression and appurtenant facilities to increase Florida Gas's capability to deliver gas along its main pipeline system, generally from Compressor Station 8 in West Baton Rouge Parish, Louisiana, to Compressor Station 20 in St. Lucie County, Florida, and all gas purchase, transportation and sale agreements relating to the increased capacity resulting from the expansion. Said Expansion, which may be accomplished in phases, is projected to be an increase in delivery capacity of Florida Gas's main pipeline system of approximately 200,000 MCFD and is intended to serve existing and new customers along Florida Gas's system in peninsular Florida.

(g) "Formula Price” shall equal the Purchase Price as determined in and paid pursuant to the Stock Purchase Agreement minus one-half of the decrease or plus one-half of the increase (as the case may be) in the Net Worth of Citrus from

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the end of the month in which the closing referred to in the Stock Purchase Agreement occurs until the end of the second month preceding the closing referred to in Section 16.

(h) "Net Worth of Citrus” means the consolidated net worth of Citrus and its subsidiaries determined in accordance with the generally accepted accounting principles followed by Citrus, applied on a consistent basis.

(i) "Operating Agreement" means the Operating Agreement of even date herewith between Citrus and HNG Interstate Pipeline Company.

(j)"Parent" means, with respect to a Subsidiary, its ultimate corporate parent, Sonat or Enron, as the case may be.

(k)"Person" means any individual, corporation, partnership, joint venture, association, joint stock company, trust, unincorporated organization or government or any agency or political organization thereof and shall include any successor by merger or otherwise of such Person.

(1) "Principals" means Sonat and Enron and their respective successors and assigns.

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(m)"Stock Purchase Agreement" means the Stock Purchase Agreement dated March 27, 1985 among Sonat, Enron and HNG.

(n)"Subsidiary" means a corporation all of the voting shares (that is, shares entitled to vote for the election of directors, but excluding shares entitled so to vote only upon the happening of some contingency unless such contingency shall have occurred) of which shall be owned by a Principal or by one or more Subsidiaries or by a Principal and one or more Subsidiaries.

(o)"Voting Securities" of a Principal means all outstanding securities of such Principal entitled under ordinary circumstances to vote for the election of directors.

(p)“Synergy Agreements" means the following agreements, all dated of even date herewith:

(i)Gas Supply Agreement between SW Trading Inc. and Florida Gas;

(ii)Interconnection Agreement between South Georgia Natural Gas Company and Florida Gas;

(iii)Agreement for the Sale and Purchase of Natural Gas between Southern Natural Gas Company ("Southern Natural") and Florida Gas; and

(iv)Capacity and Expansion Agreement between Southern Natural and Florida Gas.

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2.Investment Representation. Each of Sonat and HNG hereby represents that the shares of Common Stock now owned by it have been acquired for its own account, for investment and not with a view to the distribution thereof.

3.Capital Stock of Citrus.

(a)Ownership and Original Issuance. Unless otherwise agreed to by the Principals in writing and except as otherwise expressly permitted by the provisions of this Agreement, at all times during the term of this Agreement (i) Sonat or one of its Subsidiaries shall own 100% of the Class A Common Stock and Enron or one of its Subsidiaries shall own 100% of the Class B Common Stock, (ii) no Capital Stock shall be issued to or owned or held by a Person who is not a Principal or a Subsidiary of a Principal and (iii) no Capital Stock shall be issued after the date hereof to a Subsidiary of a Principal unless such Subsidiary enters into an agreement with the other Principal, satisfactory in form and substance to such other Principal, pursuant to which it agrees to be bound by all the terms and provisions of this Agreement applicable to its Parent.

(b)Transfers of Shares Between Principals and Their Subsidiaries. Notwithstanding any other provisions of this Agreement, Capital Stock issued to or owned or held by a Principal or Subsidiary thereof may be transferred by such Principal or Subsidiary, as the

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case may be, to any Subsidiary of such Principal or, in the case of Capital Stock issued to or owned or held by such Subsidiary, to such Principal, provided that (i) all such Capital Stock shall then be held solely by such Principal or Subsidiary, (ii) notice of such transfer is given to the other Principal by the Principal making such transfer or whose Subsidiary is making such transfer, (iii) any Subsidiary of any Principal to which any Capital Stock is to be transferred enters into an agreement with the other Principal, satisfactory in form and substance to such other Principal, pursuant to which it agrees to be bound by all the terms and provisions of this Agreement applicable to its Parent, and (iv) prior to the occurrence of any Subsidiary which owns Capital Stock ceasing to be a Subsidiary of a Principal, such Subsidiary shall transfer and such Principal shall acquire all such Capital Stock.

(c) Disposition of Shares. Neither Principal nor any Subsidiary of a Principal (nor any pledgee or mortgagee of a Principal or Subsidiary thereof) may directly or indirectly (including without limitation any sale of a Subsidiary that owns Capital Stock) sell or transfer or otherwise dispose of any Capital Stock owned or held by it except with the written consent of the other Principal or as expressly permitted by

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this Section 3 or by Sections 15 or 16 of this Agreement. No Capital Stock owned or held by either Principal or any Subsidiary of such Principal may be sold or transferred pursuant to the provisions of the following Section 3(d) unless all such stock held by such Principal or Subsidiary is sold and transferred at the same time at a fixed price, payable in cash, to a single purchaser, all as hereinafter provided. No Capital Stock may be offered for sale or sold under the provisions of Section 3(d) if the terms of the proposed sale by the Selling Principal (as hereinafter defined) require the proposed purchaser to undertake any obligations or liabilities other than payment of the purchase price in cash, the filing and prosecution of any necessary notices to, and applications for any necessary approvals of, regulatory authorities, and compliance with the provisions of this Agreement.

As used herein, the term *sell, transfer or otherwise dispose of" does not include any transfer pursuant to a sale or lease of all or substantially all the assets of either Principal or any merger or consolidation of either Principal, provided that any transferee or successor (and, if applicable, the ultimate parent of any such transferee or successors) shall, by

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agreement or operation of law, be bound by the terms and provisions of this Agreement as a Principal.

(d) Sale of Shares. Subject to the limitations set forth in Section 3(h), in the event that either Principal desires to sell or cause to be sold all the Capital Stock owned by it or its Subsidiary to a third party for cash, such Principal or its Subsidiary (the "Selling Principal") shall first offer or cause to be offered such stock for sale to the other Principal (the Purchasing Principal") at the same price as that provided for in any bona fide offer received by the Selling Principal for the purchase of such stock which the Selling Principal is prepared to accept, in accordance with the following provisions of this Section 3(d):

(i)The Selling Principal shall give notice in writing to the Purchasing Principal stating that the Selling Principal desires to sell or cause to be sold all the Capital Stock held by the Selling Principal, specifying the price and the party from which such offer has been received, offering such stock to the Purchasing Principal and attaching a copy of such offer.

(ii)Within 60 days from the receipt of such notice, the Purchasing Principal shall deliver a notice to the Selling Principal stating whether the

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Purchasing Principal accepts the offer of the Selling Principal; if the Purchasing Principal fails to deliver such notice within such 60-day period, the Purchasing Principal shall be deemed conclusively to have delivered a notice stating that the Purchasing Principal does not accept such offer.

(iii)In the event that, within 60 days from the receipt of the notice of the Selling Principal referred to in Section 3(i) above, the Purchasing Principal delivers a notice to the Selling Principal to the effect that such Purchasing Principal accepts the offer of the Selling Principal, delivery of such notices shall constitute an agreement binding on the Selling Principal and the Purchasing Principal to sell and purchase all of the Capital Stock to be sold by the Selling Principal, subject to the approval of any regulatory authority having jurisdiction, at the price stated in the offer of the Selling Principal.

(iv)If the Purchasing Principal declines the offer or fails to accept the offer of the Selling Principal within the period specified in Section 3(d)(ii), the Selling Principal shall be free until the expiration of the six-month period referred to in paragraph (v) below to sell

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such Capital Stock to the purchaser at the price specified in the notice referred to in Section 3(d)(1), provided that the purchaser shall, before such sale, have entered into an agreement with the other Principal, in form and substance reasonably satisfactory to the other Principal, whereby such purchaser assumes the same obligations and becomes entitled to the same benefits as the Selling Principal under the terms of this Agreement.

(v)In the event that the Selling Principal does not complete such a sale within a period of six months from the date upon which the Selling Principal gave notice to the Purchasing Principal of its desire to sell the Capital Stock, all the provisions of this Section 3(d) shall apply to any future sale or offer for sale of the Capital Stock held by the Selling Principal.

(vi)Each transaction of purchase and sale pursuant to the foregoing provisions of this Section 3(d) shall be completed by payment of the purchase price to the Selling Principal in immediately available funds against delivery of the certificates for the Capital Stock duly endorsed in blank, free and clear of all liens, claims or encumbrances and with requisite transfer taxes, if any, fully paid. Any such transaction

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of purchase and sale pursuant to Section 3(d)(iii) shall be closed at such time and place as shall be agreed upon by the Purchasing and Selling Principals or, if no such agreement is reached, during normal business hours at the principal office of Citrus on the 120th day following the date the Purchasing Principal delivers notice accepting the offer of the Selling Principal or, if such day shall not be a business day, on the first business day thereafter during normal business hours.

(vii) In the event that Sonat or a Subsidiary shall purchase the Capital Stock owned by Enron or its Subsidiary pursuant to this Section 3(d), the Operating Agreement shall thereupon terminate. In the event that the Capital Stock owned by Enron or its Subsidiary shall be sold to a third party pursuant to this Section 3(d) and the Operating Agreement shall not be assigned to such third party, the Operating Agreement shall thereupon terminate.

(e) Pledge of Shares and Rights under this Agreement. The provisions of subsections (a), (c) and (d) of this Section 3 shall not apply to any pledge or mortgage by any Principal or any Subsidiary thereof of the Capital Stock owned or held by it or its rights under this

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Agreement if such pledge or mortgage is required or provided for under the terms of any mortgage, trust indenture or other agreement or amendment thereto now in effect or hereafter executed pursuant to which any indebtedness for borrowed money or securities of such Principal or Subsidiary may be issued and outstanding, and any such pledge or mortgage may be made at any Lime without the consent of the other Principal; provided, however, that any disposition of such stock upon foreclosure of such pledge or mortgage shall be governed by the provisions of this Agreement, including the provisions of subsections (c) and (d) of this Section 3.

(f) Opinion of Counsel. The parties hereto understand that the shares of Common Stock which are owned by HNG and the shares of Common Stock which have been acquired by Sonat have not been and will not be registered under the Securities Act of 1933 pursuant to an exemption from the registration provisions of such Act. Each of the Principals hereby agrees (on behalf of itself and of its Subsidiaries) that the Common Stock which has been acquired by it and any other Capital Stock hereafter acquired by it pursuant to an exemption from the registration provisions of such Act shall not be sold, transferred, pledged or hypothecated unless there is furnished an opinion of counsel satisfactory toCitrus that

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registration of such stock under such Act is not required. The provisions of this subsection (f) shall remain in effect until, in the opinion of counsel for Citrus, they are no longer required.

(g)Legend on Certificates. As long as this Agreement shall continue in effect, the following legend shall be written, printed or stamped on all certificates for shares of Capital Stock: "The transfer of shares of stock represented by this certificate is restricted by the terms and conditions of an agreement dated June 30, 1986, among Sonat Inc., Enron Corp., Houston Natural Gas Corporation and Citrus Corp. A copy of said Agreement is on file at the office of Citrus Corp.”

(h)Limitations. Capital Stock may only be sold or transferred pursuant to Section 3(d) if the notice referred to in Section 3(d)(i) pursuant to which such sale is made, either to a third party or to the Purchasing Principal, is given by the Selling Principal to the Purchasing Principal during one of the following time periods: (i) the period of 180 days following the fifth anniversary of the date of this Agreement, (ii) the period of 180 days following the tenth anniversary of the date of this Agreement, or (iii) any time after the fifteenth anniversary of the date of this Agreement. The

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limitations of this Section 3(h) shall not apply to any disposition of Capital Stock upon foreclosure of a pledge or mortgage pursuant to Section 3(e).

4.Board of Directors. As provided in the Restated Certificate of Incorporation of Citrus, the holders of the Class A Common Stock shall be entitled to elect three members of the Board of Directors of Citrus, designated Class A Directors, and the holders of the Class B Common Stock shall be entitled to elect three members of the Board of Directors, designated Class B Directors. As provided in Article III of the Bylaws, any "Important Matter" (as defined therein) of Citrus shall be submitted to, and require the approval of, the Board of Directors of Citrus and any "Important Matter" of a subsidiary of Citrus shall be submitted to, and require the approval of, Citrus as its sole stockholder. The Principals acknowledge that although all necessary approvals by the Principals and the Boards of Directors of Citrus or its subsidiaries have been duly given and received for entering into and performing the Synergy Agreements, further Board approvals may be required with respect to implementation of the Capacity and Expansion Agreement in instances where Florida Gas chooses to construct expansion facilities, and the Interconnection Agreement. The Principals hereby agree, however, that no further approvals by the Principals or the Boards of Directors of Citrus or its subsidiaries are necessary for implementation of the Gas

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Supply Agreement in accordance with its terms, the Agreement for Sale and Purchase of Natural Gas, and expansion under the Capacity and Expansion Agreement in instances where Southern Natural constructs such expansion facilities at its own cost and expense. The Principals further agree that without further approval of the Board of Directors of Citrus, neither Citrus nor its subsidiaries shall enter into any contracts with the Principals or their Affiliates or any amendment of such contracts or amend any contract existing on March 27, 1906 between Citrus or its subsidiaries on the one hand and the Principals or their Affiliates on the other hand except those transportation agreements permitted under the terms of the Bylaws; provided, however, that no further approvals by the Principals or the Boards of Directors of citrus or its subsidiaries are necessary for any action required to implement all contracts between Florida Gas and the Principals or their Affiliates that were in existence on March 27, 1986.

5.Chairman of the Board. Enron shall have the right to nominate the first Chairman of the Board of Directors of Citrus. Thereafter, the right to nominate the Chairman of the Board will alternate annually between Enron and Sonat. Sonat and Enron agree to use their best efforts to cause the election of the persons so nominated.

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6.Informal Meeting of Principals. In the event that, from time to time, the Board of Directors of Citrus shall be unable to reach agreement upon various matters submitted to it, the Principals, acting through their respective executive officers, shall hold informal meetings to discuss and resolve such matters. The Principals will seek to cause any conclusions arrived at during such meetings to be implemented, where necessary, by actions of the Board of Directors of Citrus.

7.Performance of Agreements. Each of the Principals hereby agrees, on behalf of itself and any Subsidiary which is a stockholder of Citrus, that it or such Subsidiary will at all times vote as a stockholder of Citrus, and use all reasonable efforts to cause those individuals whom it or such Subsidiary has elected to the Board of Directors of Citrus to vote as directors of Citrus, in such a manner as to ensure that the terms and intentions of this Agreement and the Bylaws of Citrus are carried out and observed.

8.Principal Office of Citrus. Citrus shall establish and maintain its principal business and operating office at the principal office of Enron in Houston, Texas, until such time as such principal office may be changed by the Board of Directors of Citrus.

9.Auditors. The independent auditors for Citrus shall be selected by the Board of Directors of Citrus.

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10.Inspection; Books and Records. Employees and agents of each principal shall have access to the pipelines and properties of Citrus and its subsidiaries at all times during normal business hours for the purpose of inspecting such pipelines and properties and the operations thereon. Citrus and its subsidiaries shall keep accurate and complete books and records and such books and records shall be available for inspection and review by employees and agents of each Principal at all times during normal business hours. Citrus shall furnish the Principals during normal business hours with such additional information and documents regarding Citrus and its subsidiaries, as the Principals may from time to time reasonably request. The costs and expenses incurred in connection with any inspection or review permitted pursuant to this Section 10 shall be borne by the Principal making such inspection or review.

11.Operating Agreement. Sonat shall have the right to enforce the provisions of the Operating Agreement in the event Citrus shall fail to do so, and to select an arbitrator and prosecute such arbitration in accordance with the procedures set forth in the Operating Agreement.

12.Pipeline Expansion. The entire economic benefits and opportunities of the Expansion will be the benefits and opportunities of Citrus and its subsidiaries. Subject to the approval by the Board of Directors of Citrus of the necessary contracts and

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further subject to receipt of any required regulatory approvals, each Principal agrees to provide or cause to be provided one-half of the required funds necessary for the Expansion, which funds for each Principal shall not exceed $100 millions In addition, each Principal or its designee, shall have the right to furnish one-half of the volume of natural gas required for the expansion to be provided by Florida Gas pursuant to certain agreements relating to the Expansion.

13.Financing. The Principals will cause Citrus to seek long-term borrowings in such amounts and on such terms as the Principals mutually deem most appropriate and economical, and will cause Citrus to execute such instruments and documents as may reasonably be requested in connection with such financing.

14.Voting Securities of the Principals.Each Principal represents and warrants that as of the date hereof neither it nor any of its Affiliates or Associates beneficially owns any Voting Securities of the other Principal or any options or other rights to acquire (through purchaser exchange, conversion or otherwise) any such Voting Securities.

(a)Each principal represents and warrants that as of the date hereof neither it nor any of its Affiliates or Associates beneficially owns any Voting Securities of the other Principal or any options or other rights to acquire (through purchase, exchange, conversion or otherwise) any such Voting Securities.

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(b)Enron agrees that, for a period of fifteen years from the date of this Agreement, without the prior written consent of Sonat, it will not and it will cause each of its Affiliates and Associates controlled by Enron to not, directly or indirectly, alone or in concert with others, (i) acquire, offer to acquire or agree to acquire, by purchase, gift or otherwise, any Voting Securities (or any options or rights to acquire, by purchase, exchange or otherwise, Voting Securities) of Sonat, (ii) make any proposal for or offer of any business combination or purchase or sale of assets involving Sonat, (iii) make, or in any way participate in, any "solicitation" of "proxies" (as such terms are used in the proxy rules of the Securities and Exchange Commission), or seek to advise or influence any person or entity with respect to the voting of, or giving of consents with respect to, any Voting Securities of Sonat, or (iv) otherwise act to seek to control or influence the management, board of directors, policies or affairs of Sonat.

(c) Sonat agrees that, for a period of fifteen years from the date of this Agreement, without the prior written consent of Enron, it will not and it will cause each of its Affiliates and Associates controlled by Sonat to not, directly or indirectly, alone or in concert with others, (i) acquire, offer to acquire or agree to acquire, by purchase, gift or otherwise, any Voting Securities (or any options or rights to acquire, by purchase, exchange or otherwise,

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Voting Securities) of Enron, (ii) make any proposal for or offer of any business combination or purchase or sale of assets involving Enron, (iii) make, or in any way participate in, any "solicitation" of "proxies" (as such terms are used in the proxy rules of the Securities and Exchange Commission), or seek to advise or influence any person or entity with respect to the voting of, or giving of consents with respect to, any Voting Securities of Enron, or (iv) otherwise act to seek to control or influence the management, board of directors, policies or affairs of Enron.

15. Buy-Sell Rights. (a) Subject to Section 15(e), after the fifteenth anniversary of the date of this Agreement, either Principal may offer to purchase all the Capital Stock owned by the other Principal or its Subsidiary. The Principal making such offer to purchase (the "Offeror") shall notify the other Principal (the "Offeree") of such offer to purchase by delivering to the Offeree a written notice of such offer (the "Buy-Sell Notice"). The Buy-Sell Notice shall (i) state the purchase price offered for such Capital Stock, which purchase price shall be payable in cash, (ii) include a certificate of the Offeror to the effect that the Offeror has all requisite corporate power and

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authority, and the financial resources, to consummate the proposed purchase, and (iii) specify a business day for the consummation of the proposed purchase, which day shall not be less than 120 days nor more than 150 days after delivery of the Buy-Sell Notice to the Offeree.

(b) Upon delivery of the Buy-Sell Notice, the Offeree shall, within 60 days thereafter, by written notice elect either (i) to sell to the Offeror all the Capital Stock owned by the Offeree or its Subsidiary ("Offeree Capital Stock") or (ii) to purchase from the Offeror all the Capital Stock owned by the Offeror or its Subsidiary ("Offeror Capital Stock"), in each case in cash at the purchase price stated in the Buy-Sell Notice. If the Offeree elects to purchase the Offeror Capital Stock, its notice of such election shall (i) include a certificate of the Offeree to the effect that the Offeree has all requisite corporate power and authority, and the financial resources, to consummate the proposed purchase, and (ii) specify a business day for the consummation of the proposed purchase by the Offeree, which day shall not be later than the day specified in the Buy-Sell Notice.

(c) If the Offeree shall not have delivered a notice of its election to purchase all the Offeror Capital Stock by the date specified in Section 15(b), the Offeror shall

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purchase from the Offeree or its Subsidiary, and the Offeree shall sell or cause to be sold to the Offeror, all the Offeree Capital Stock in accordance with the Buy-Sell Notice. If the Offeree shall have delivered a notice of its election to purchase all the Offeror Capital Stock by the date specified in Section 15(b) the Offeree shall purchase from the Offeror or its Subsidiary, and the Offeror shall sell or cause to be sold to the Offeree, all the Offeror Capital Stock in accordance with the Offeree's notice of election. In either case, such purchase and sale shall take place at the offices of Citrus during normal business hours on the business day specified in the applicable notice, and the seller shall deliver certificates representing all the Capital Stock owned by it to the purchaser, endorsed in blank, against payment therefor in immediately available funds, free and clear of all liens, claims or encumbrances and with requisite transfer taxes, if any, fully paid. No Capital Stock may be offered for sale or sold under the provisions of this Section 15(c) if the terms of the proposed sale by the Offeror require the Offeree to undertake any obligations or liabilities other than payment of the purchase price in cash, the filing and prosecution of any necessary notices to, and

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applications for any necessary approvals of, regulatory authorities, and compliance with the provisions of this Agreement.

(d)If all requisite approvals in respect of such purchase and sale shall not have been obtained by the specified date of such purchase and sale, despite the reasonable efforts of the Principals to obtain Such approvals, neither Principal shall be obligated to consummate such transactions all offers and elections made pursuant to this Section 15 shall be deemed to have been withdrawn, and this Section 15 shall continue to apply to subsequent offers and elections. Each Principal agrees to use all reasonable efforts to cooperate with the other Principal and Citrus in obtaining any regulatory approvals necessary for the purchase and sale of any Capital Stock pursuant to this Section 15.

(e)A Buy-Sell Notice may not be given pursuant to Section 15(a) during the period of 180 days following the giving of a notice under Section 3(d)(i) with respect to a proposed sale of Capital Stock.

16. Change of Control.(a) If a Principal (the "Non-Electing Principal") suffers a Change of Controls the other Principal (the "Electing Principal") shall thereafter have the option either to (i) purchase all the Capital Stock owned by the

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Non-Electing Principal or its Subsidiary (the "Non-Electing Principal's Shares") !or a cash purchase price equal to either (at the election of the Electing Principal) the Formula Price or the fair market value of the Non-Electing Principal's Shares on the last day of the month preceding the date on which an Election Notice (as defined in Section 16(b) shall be delivered pursuant to Section 16(b), as determined by an appraisal in accordance with Section 16(c), or (ii) require the Non-Electing Principal to purchase all of the shares of Capital Stock owned by the Electing Principal or its Subsidiary (the "Electing Principal's Shares") for a cash purchase price equal to either (at the election of the Electing Principal) the Formula Price or the fair market value of the Electing Principal's Shares on the last day of the month preceding the date on which an Election Notice (as defined in Section 16(b)) shall be delivered pursuant to Section 16(b), as determined by an appraisal in accordance with Section 16(c). Either of such options shall be exercisable at the time and in the manner set forth in Section 16(b).

(b) Each Principal shall give prompt written notice of any Change of Control suffered by it to the other Principal. If the Electing Principal desires to exercise either of its options under Section 16(a)(i) or Section 16(a)(ii), the Electing Principal shall deliver a written notice of its exercise (the "Election

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Notice") to the Non-Electing Principal within 180 days after the later of (i) receipt of a written notice from the Non-Electing Principal of a Change of Control or (ii) the date on which the Electing Principal otherwise becomes aware of such a Change of Control. Such notice shall also contain am election of the method to determine the purchase price for the shares of Capital Stock being bought or sold. The closing of the transaction elected by the Electing Principal shall occur (A) 60 days from the date of its exercise, (B) 10 days after a final determination of the Formula Price or the completion of the appraisal of the fair market value of the shares of Capital Stock in accordance with Section 16(c), as the case may be, or (C) within 10 days following the obtaining of all regulatory approvals (if any) and the expiration of all regulatory waiting periods (if any) necessary to complete such transaction, whichever is latest. The purchase price, however determined, shall be payable by wire transfer of immediately available funds at the closing against delivery of certificates representing such shares duly endorsed in blank, free and clear of all liens, claims or encumbrances and with requisite transfer taxes, if any, fully paid. No Capital Stock may be sold

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under the provisions of this Section 16(b) if the terms of such sale require the proposed purchaser to undertake any obligations or liabilities other than payment of the purchase price in cash, the filing and prosecution of any necessary notices to, and applications for any necessary approvals of, regulatory authorities, and compliance with the provisions of this Agreement.

(c )If the Electing Principal elects to have an appraisal of the fair market value of the shares of the Capital Stock as permitted by Section 16(a) of this Section 16, such fair market value shall be an amount mutually agreed to by the Principals' respective investment bankers, and the Principals agree to engage their respective investment bankers as promptly as practicable for this purpose. If the two investment bankers of the Principals have not mutually agreed to such fair market value within 30 days from the date the Electing Principal exercises its option pursuant to this Section 16, such investment bankers will select a third investment banker to make such fair market value determination. The fair market value determination of the third investment banker shall be rendered within 30 days of such investment banker's selection and shall be conclusive and binding on the Principals. Each Principal shall bear 50% of the cost of employing the third investment banker.

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(d)In the event of a dispute as to the computation of the Formula Price, the Principals shall promptly submit such dispute to the accounting firm which is acting as auditor for Citrus for resolution, and the determination by such firm shall be conclusive and binding on the Principals. Each Principal shall bear 50% of the cost of employing such firm.

(e)If Enron (or any successor to Enron) sells the Capital Stock owned by it or its Subsidiary pursuant to this Section 16 (irrespective of which Principal has suffered a Change of Control), the Operating Agreement shall be assigned to the purchaser.

(f)If Sonat (or any successor to Sonat) sells its Capital Stock pursuant to this Section 16 (irrespective of which Principal has suffered a Change of Control) and the purchase price is the Formula Price, the provisions of the Synergy Agreements with respect to future rights of expansion and other rights of Sonat or its Affiliates in such Synergy Agreements which have not been implemented will thereupon terminate, but in other respects the Synergy Agreements and other agreements which have been implemented pursuant thereto will continue in full force and effect.

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(g) If Sonat (or any successor to Sonat) sells its Capital Stock pursuant to this Section 16 (irrespective of which Principal has suffered a Change of Control) and the purchase price is as determined by appraisal, the provisions of the Synergy Agreements and other agreements which have been implemented pursuant thereto will continue in full force and effect without modification.

17. Term of Agreement. This Agreement shall continue in effect for an initial term of 15 years from the date of this Agreement (unless prior to such date one Principal shall have purchased all of the Capital Stock of the other Principal pursuant to the other provisions hereof) and thereafter for so long as the Capital Stock of Citrus shall be held by two Principals or Subsidiaries thereof. Termination of this Agreement prior to such 15 year term shall not affect the obligations of Sonat and Enron in Section 14 of this Agreement, which shall continue in full force and effect for the remainder of such 15 year period. In the event that a Principal shall sell its Capital Stock pursuant to Section 3, such selling Principal shall cease to be a Principal within the

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meaning of this Agreement and shall no longer be bound by the provisions of this Agreement (except, in the case of Sonat or Enron, for its continuing obligations under Section 14).

18.Notice. Any notice, request, instruction, correspondence or other document to be given hereunder by either party to the other (herein collectively called "Notice) shall be in writing and delivered personally or mailed by certified mail, postage prepaid and return receipt requested, or by telegram or telecopier, as follows:

To Sonat:

Sonat Inc.

    1900 Fifth Avenue North First National - Southern Natural Bldg.

Birmingham, Alabama 35203

Attention: President

Telecopier: 205-325-7490

To Enron:

Enron Corp.

1200 Travis Street Houston, Texas 77002

Attention: President

Telecopier: 713-654-6301

To HNG:

Houston Natural Gas Corporation

1200 Travis Street

Houston, Texas 77002

Attention: President

Telecopier: 713-654-6301

To Citrus:

Citrus Corp.

1200 Travis Street

Houston, Texas 77002

Attention President

Telecopier: 713-654-6301

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Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telegram or telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All Notices by telegram or telecopier shall be confirmed promptly after transmission in writing by certified mail or personal delivery. Any party may change any address to which Notice is to be given to it by giving Notice as provided above of such change of address.

19.Governing Law. The provisions of this Agreement and the documents delivered pursuant hereto shall be governed by and construed in accordance with the laws of the State of Delaware (excluding any conflicts-of-law rule or principle that might refer same to the laws of another jurisdiction), except to the extent that same are mandatorily subject to the laws of another jurisdiction pursuant to the laws of such other jurisdiction.

20.Headings. The headings of the several Sections herein are inserted for convenience of reference only and are not intended to be a part of or to affect the meaning or interpretation of this Agreement.

21.Successors Bound. Except as set forth herein, this Agreement may

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not be assigned by any party without the consent of the other parties. Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

22. No Waiver. No modification or waiver of this Agreement shall be binding unless executed in writing by the party to be bound thereby. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (regardless of whether similar), nor shall any such waiver constitute a continuing waiver unless otherwise expressly provided.

IN WITNESS WHEREOF, Sonat, Enron, HNG and Citrus have caused this Agreement to be signed in multiple originals by their respective officers thereunto duly authorized all as of the date first above written.

SONAT INC.

By /s/William A. Smith

Vice President and

General Counsel

ENRON CORP.

By/s/Richard D. Kinder

Executive Vice President

Law and Corporate Development

34.

HOUSTON NATURAL GAS CORPORATION

By /s/Gary W. Orloff

Vice President and

Associate General Counsel

CITRUS CORP.

By /s/James E. Rogers

President and Chief

Operating Officer

GWO/778

35.

EX-10.Q

Exhibit 10(q)

10003 BOOK 383 PAGE 76 PAGE 1

Office of Secretary of State

I, MICHAEL HARKINS, SECRETARY OF STATE OF THE STATE OF

DELAWARE DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECT

COPY OF THE CERTIFICATE OF RESTATED CERTIFICATE OF INCORPORATION

OF CITRUS CORP. FILED IN THIS OFFICE ON THE TWENTY—FOURTH DAY OF

JUNE, A.D. 1986, AT 10 O’CLOCK A.M.

AUTHENTICATION:  10864158

DATE:  06/25/1986

4.11":":411

111111111111111111111111111111

736175070

Book383 PAGE 77

RESTATED CERTIFICATE OF INCORPORATION OF

CITRUS CORP.

Citrus Corp., a Delaware corporation, the original Certificate of Incorporation of which was filed on March 21, 1986, HEREBY CERTIFIES that this Restated Certificate of Incorporation, restating, integrating and amending its Certificate of Incorporation, was duly proposed by its Board of Directors and adopted by its sole stockholder in accordance with Sections 242 and 245 of the General Corporation Law of the State of Delaware, and that the capital of the Corporation is not being reduced under or by reason of any amendment in this Restated Certificate of Incorporation.

First:The name of the Corporation is Citrus Corp.

Second: The address of its registered office in the State of Delaware is the Corporation Trust Center, 1209 Orange Street in the City of Wilmington, County of New Castle. The name of its registered agent at such address is the Corporation Trust Company.

Third: The nature of the business, objects and purposes to be transacted, promoted or carried on by the corporation are:

To engage in any lawful act or activity for which corporations may be organized under the General Corporation Law of Delaware.

Fourth: The aggregate number of shares which the corporation shall have the authority to issue is One Thousand (1,000) shares of Common Stock and the par value of each of such shares shall be One Dollar ($1.00). The Common Stock shall be divided into two classes, designated as Class A Common Stock and Class B Common Stock. The number of shares of Class A Common Stock authorized to be issued is Five Hundred (500); and the number of shares of Class B Common Stock authorized to be issued is Five Hundred (500). Except as otherwise provided in this Certificate of Incorporation, the shares of each class of Common Stock shall be identical in every respect and each share of each class shall participate equally, share and share alike, in all dividends and other distributions on or with respect to the Corporation's Common Stock, including distributions in liquidation or dissolution, and such dividends or other distributions as may be duly declared by the Board of Directors.

(a) Voting. Except as otherwise provided in this Restated Certificate of Incorporation, each share of each class of Common Stock shall entitle the holder thereof to one vote on all matters upon which the stockholders of the Corporation have the right to vote, and all shares of both classes shall be voted together as one class.

-1-

Book 383PAGE 78

(b)Election of Directors. The number of directors of the Corporation shall be an even number fixed from time to time by, or in the manner provided in, the bylaws of the Corporation, and shall be fixed initially at six and shall not exceed six. The directors shall be divided into two classes, Class A Directors and Class B Directors, consisting of equal numbers. All directors shall be of equal rank and shall have the same rights, powers, duties and obligations. The holders of shares of Class A Common Stock shall exclusively, by affirmative vote of the holders of a majority of the shares of Class A Common Stock at the time outstanding, elect, remove, accept resignations of, and fill vacancies in the office of Class A Directors. Any Class A Director may be removed, either with or without cause, at any time by the affirmative vote of the holders of a majority of the outstanding shares of Class A Common Stock, and thereupon the term of such director shall forthwith terminate. If a vacancy occurs in the Board of Directors with respect to a Class A Director for any reason, the holders of a majority of the shares of Class A Common Stock at the time outstanding may fill such vacancy, and any person so chosen to fill such vacancy shall hold office until the next annual meeting of stockholders and until such director's successor is elected and qualified or until such director's earlier resignation or removal. The holders of shares of Class B Common Stock shall exclusively, by affirmative vote of the holders of a majority of the shares of Class B Common Stock at the time outstanding, elect, remove, accept resignations of, and fill vacancies in the office of Class B Directors. Any Class B Director may be removed, either with or without cause, at any time by the affirmative vote of the holders of a majority of the outstanding shares of Class B Common Stock, and thereupon the term of such director shall forthwith terminate. If a vacancy occurs in the Board of Directors with respect to a Class B Director for any reason, the holders of a majority of the shares of Class B Common Stock at the time outstanding may fill such vacancy, and any person so chosen to fill such vacancy shall hold office until the next annual meeting of stockholders and until such director's successor is elected and qualified or until such director's earlier resignation or removal. Holders of one class of Common Stock, as such, may not vote upon the election, removal, acceptance of resignations, or filling of vacancies in the office of directors of another class of Common Stock.

(c)Voting Powers of Directors. Each class of directors shall have one vote. The presence at any meeting of one Class A Director and one Class B Director shall constitute a quorum for the transaction of business. The transaction of any business at any meeting shall require a quorum and the unanimous vote of both classes of directors. The vote of each class of directors shall be determined by agreement among the directors of such class present at the meeting or, failing such agreement, by the majority vote of such directors.

Fifth: Upon the filing of this Restated Certificate of Incorporation, the previously issued and outstanding Common Stock of the Corporation, consisting of 1,000 shares of the par value of $1.00 per share, shall be ipso facto changed and reclassified into 500 shares of Class A Common Stock of the par value of $1.00 per share and 500 shares of Class B Common Stock of the par value of $1.00 per share.

-2-

BOOK 383PAGE79

Sixth:The name and mailing address of the incorporator is as follows:

Name	Address
Gary W. Orloff	1200 Travis Street Suite 1734 Houston, Texas 77002

Seventh: The names and mailing addresses of the persons who are to serve as directors of the Corporation until the first annual meeting of the stockholders or until their successors are elected and qualified, are as follows:

Name	Mailing Address
CLASS A DIRECTORS
D.H. Gullquist	1200 Travis Street Suite 1600 Houston, Texas 77002
Royston C. Hughes	1200 Travis Street Suite 1600 Houston, Texas 77002
Richard D. Kinder	1200 Travis Street Suite 1600 Houston, Texas 77002
CLASS B DIRECTORS
Keith D. Kern	1200 Travis Street Suite 1600 Houston, Texas 77002
Gary W. Orloff	1200 Travis Street Suite 1600 Houston, Texas 77002
David G. Woytek	1200 Travis Street Suite 1600 Houston, Texas 77002

Election of directors need not be by written ballot.

Eighth: In furtherance and not in limitation of the powers conferred by statute, the Board of Directors is expressly authorized to make, adopt, alter or repeal the bylaws of the Corporation.

Ninth: The Corporation shall have the right, subject to any express

-3-

BOOK 383 PAGE 80

provisions or restrictions contained in the certificate of incorporation or bylaws of the Corporation, from time to time, to amend the certificate of incorporation or any provision thereof in any manner now or hereafter provided by law, and all rights and powers of any kind conferred upon a director or stockholder of the corporation by the certificate of incorporation or any amendment thereof are subject to such right of the Corporation.

IN WITNESS WHEREOF, the Corporation has caused its corporate seal to be affixed hereto and this instrument to be signed in its name by its Vice President and attested to by its Secretary on May 1, 1986.

CITRUS CORP.

                                               By/s/Gary W.Orloff

Vice President

Attest:

By/s/Peggy B. Manchaca

Secretary

[SEAL]

GWO/767

-4-

EX-10.R

Exhibit 10(r)

BYLAWS

OF

CITRUS CORP.

A Delaware Corporation

Restated

June 22, 2005

Table of Contents

			Page
Article I.	Offices
	Section 1.	Registered Office	1
	Section 2.	Other Office	1
Article II.	Stockholders
	Section 1.	Place of Meetings	1
	Section 2.	Voting	1
	Section 3.	Annual Meetings	2
	Section 4.	Special Meetings.	2
	Section 5.	Record Date	2
	Section 6.	Notice of Meetings	3
	Section 7.	Stockholder List	3
	Section 8.	Proxies	3
	Section 9.	Voting; Election; Inspectors	4
	Section 10.	Conduct of Meetings	4
	Section 11.	Treasury Stock	5
	Section 12.	Action without Meeting	5
Article III.	Board of Directors
	Section 1.	Power; Number; Term of Office	5
	Section 2.	Voting Powers of Directors	6
	Section 3.	Place of Meetings; Order of Business	6
	Section 4.	First Meeting	6
	Section 5.	Regular Meetings	6
	Section 6.	Special Meetings	6
	Section 7.	Removal	6
	Section 8.	Vacancies	6
	Section 9.	Compensation	7
	Section 10	Presumption of Assent	7
	Section 11.	Action without a Meeting; Telephone Conference Meeting	7
	Section 12.	Approval or Ratification of Acts or Contracts by Stockholders	7
	Section 13.	Special Corporate Actions by Directors	8

(i)

			Page
Article IV	Officers
	Section 1.	Number, Titles and Term of Office	10
	Section 2.	Salaries	11
	Section 3.	Removal	11
	Section 4.	Vacancies	11
	Section5.	Powers and Duties of the Chief Executive Officer	11
	Section6.	Powers and Duties of the Chairman of the Board	11
	Section7.	Powers and Duties of the President	11
	Section8.	Vice Presidents	11
	Section 9.	Treasurer	12
	Section10.	Assistant Treasurers	12
	Section 11.	Secretary	12
	Section 12.	Assistant Secretaries	12
Article V.	Capital Stock
	Section1.	Certificates of Stock	12
	Section2.	Transfer of Shares	13
	Section 3.	Ownership of Shares	13
	Section4.	Regulations Regarding Certificates	13
	Section 5.	Lost or Destroyed Certificates	13
Article VI.	Miscellaneous Provisions
	Section1.	Fiscal Year	14
	Section2.	Corporate Seal	14
	Section3.	Notice and Waiver of Notice	14
	Section 4.	Resignations	14
	Section 5.	Facsimile Signatures	14
	Section 6.	Reliance upon Books, Reports and Records	14
	Section 7.	Separateness Operation Covenants	15
Article VII.	Amendments		16

(ii)

BYLAWS

of

Citrus Corp.

Article I

Offices

Section 1. Registered Office. The registered office of the Corporation required to be maintained in the state of incorporation of the Corporation shall be the registered office named in the charter documents of the Corporation, or such other office as may be designated from time to time by the Board of Directors in the manner provided by law. Should the Corporation maintain a principal office within the state of incorporation of the Corporation, such registered office need not be identical to such principal office of the Corporation.

Section 2. Other Offices. The Corporation may also have offices at such other places both within and without the state of incorporation of the Corporation as the Board of Directors may from time to time determine or the business of the Corporation may require.

Article II

Stockholders

Section 1. Place of Meetings. All meetings of the stockholders shall be held at the principal office of the Corporation, or at such other place within or without the state of incorporation of the Corporation as shall be specified or fixed in the notices or waivers of notice thereof.

Section 2.Voting.Except as otherwise provided in the charter documents of the Corporation and these Bylaws, each share of each class of common stock shall entitle the holder thereof to one vote on all matters upon which the stockholders of the Corporation have the right to vote, all shares of both classes shall be voted together as one class, and the affirmative vote of a majority of all shares of both classes shall be the act of the stockholders. The holders of shares of Class A common stock shall exclusively, by affirmative vote of the holders of a majority of the shares of the Class A common stock at the time outstanding, elect, remove, accept resignations of, and fill vacancies in the office of Class A directors. The holders of shares of Class B common stock shall exclusively, by affirmative vote of the holders of a majority of the shares of Class B common stock at the time outstanding, elect, remove, accept resignations of, and fill vacancies in the office of Class B directors.

Notwithstanding the other provisions of the charter documents of the Corporation or these Bylaws, the chairman of the meeting or the holders of a majority of the issued and outstanding stock, present in person or represented by proxy, at any meeting of the

- 1 -

stockholders, whether or not a quorum is present, shall have the power to adjourn such meeting from time to time, without any notice other than announcement at the meeting of the time and place of the holding of the adjourned meeting. If the adjournment is for more than thirty (30) days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at such meeting. At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally called.

Section 3. Annual Meetings. An annual meeting of the stockholders, for the election of directors to succeed those whose terms expire and for the transaction of such other business as may properly come before the meeting, shall be held at such place (within or without the state of incorporation of the Corporation), on such date, and at such time as the Board of Directors shall fix and set forth in the notice of the meeting, which date shall be within thirteen (13) months subsequent to the last annual meeting of stockholders.

Section 4. Special Meetings. Unless otherwise provided in the charter documents of the Corporation, special meetings of the stockholders for any purpose or purposes may be called at any time by the Chairman of the Board (if any) or by a majority of the Board of Directors, and shall be called by the Chairman of the Board (if any), by the President or the Secretary upon the written request therefor, stating the purpose or purposes of the meeting, delivered to such officer, signed by the holder(s) of at least ten (10) percent of the issued and outstanding stock entitled to vote at such meeting.

Section 5. Record Date. For the purpose of determining stockholders entitled to notice of or to vote at any meeting of stockholders, or any adjournment thereof, or entitled to express consent to a corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors of the Corporation may fix, in advance, a date as the record date for any such determination of stockholders, which record date shall not be more than sixty (60) days nor less than (10) days before the date of such meeting of stockholders, nor more than sixty (60) days prior to any other action.

If the Board of Directors does not fix a record date for any meeting of the stockholders, the record date for determining stockholders entitled to notice of or to vote at such meeting shall be at the close of business on the day next preceding the day on which notice is given, or, if in accordance with Article VI, Section 3 of these Bylaws notice is waived, at the close of business on the day next preceding the day on which the meeting is held. If, in accordance with Section 12 of this Article II, a corporate action without a meeting of stockholders is to be taken, the record date for determining stockholders entitled to express consent to such corporate action in writing, when no prior action by the Board of Directors is necessary, shall be the day on which the first written consent is expressed. The record date for determining stockholders for any other purpose

- 2 -

shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto.

A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting.

Section 6. Notice of Meetings. Written notice of the place, date and hour of all meetings, and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be given by or at the direction of the Chairman of the Board (if any), the President, the Secretary or the other person(s) calling the meeting to each stockholder entitled to vote thereat not less than ten (10) nor more than sixty (60) days before the date of the meeting. Such notice may be delivered either personally or by mail. If mailed, notice is given when deposited in the United States mail, postage prepaid, directed to the stockholder at such stockholder’s address as it appears on the records of the Corporation.

Section 7. Stockholder List. A complete list of stockholders entitled to vote at any meeting of stockholders, arranged in alphabetical order for each class of stock and showing the address of each such stockholder and the number of shares registered in the name of such stockholder, shall be open to the examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least ten (10) days prior to the meeting, either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or if not so specified, at the place where the meeting is to be held. The stockholder list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any stockholder who is present.

Section 8. Proxies. Each stockholder entitled to vote a meeting of stockholders or to express consent or dissent to a corporate action in writing without a meeting may authorize another person or persons to act for him by proxy. Proxies for use at any meeting of stockholders shall be filed with the Secretary, or such other officer as the Board of Directors may from time to time determine by resolution, before or at the time of the meeting. All proxies shall be received and taken charge of and all ballots shall be received and canvassed by the secretary of the meeting, who shall decide all questions touching upon the qualification of voters, the validity of the proxies, and the acceptance or rejection of votes, unless an inspector or inspectors shall have been appointed by the chairman of the meeting, in which event such inspector or inspectors shall decide all such questions.

No proxy shall be valid after three (3) years from its date, unless the proxy provides for a longer period. Each proxy shall be revocable unless expressly provided therein to be irrevocable and coupled with an interest sufficient in law to support an irrevocable power.

- 3 -

Should a proxy designate two or more persons to act as proxies, unless such instrument shall provide the contrary, a majority of such persons present at any meeting at which their powers thereunder are to be exercised shall have and may exercise all the powers of voting or giving consents thereby conferred, or if only one be present, then such powers may be exercised by that one; or, if an even number attend and a majority do not agree on any particular issue, each proxy so attending shall be entitled to exercise such powers in respect of the same portion of the shares as he is of the proxies representing such shares.

Section 9. Voting; Election; Inspectors. Unless otherwise required by law or provided in the charter documents of the Corporation or these Bylaws, each stockholder shall have one vote for each share of stock entitled to vote which is registered in his name on the record date for the meeting. Shares registered in the name of another corporation, domestic or foreign, may be voted by such officer, agent or proxy as the bylaws (or comparable instrument) of such corporation may prescribe; or in the absence of such provision, as the Board of Directors (or comparable body) of such corporation may determine. Shares registered in the name of a deceased person may be voted by the executor or administrator of such person’s estate, either in person or by proxy.

All voting, except as required by the charter documents of the Corporation or where otherwise required by law, may be by a voice vote; provided, however, upon demand therefor by stockholders holding a majority of the issued and outstanding stock present in person or by proxy at any meeting a stock vote shall be taken. Every stock vote shall be taken by written ballots, each of which shall state the name of the stockholder or proxy voting and such other information as may be required under the procedure established for the meeting. All elections of directors shall be by written ballots, unless otherwise provided in the charter documents of the Corporation.

At any meeting at which a vote is taken by written ballots, the chairman of the meeting may appoint one or more inspectors, each of whom shall subscribe an oath of affirmation to execute faithfully the duties of inspector at such meeting with strict impartiality and according to the best of such inspector’s ability. Such inspector shall receive the written ballots, count the votes and make and sign a certificate of the result thereof. The chairman of the meeting may appoint any person to serve as inspector, except no candidate for the office of director shall be appointed as an inspector.

Cumulative voting for the election of directors shall be prohibited.

Section 10. Conduct of Meetings. The meetings of the stockholders shall be presided over by the Chairman of the Board (if any), or if the Chairman of the Board is not present, by the President, or if neither the Chairman of the Board (if any) nor the President, by a chairman elected at the meeting. The Secretary of the Corporation, if present, shall act as secretary of such meetings, or if the Secretary is not present, an Assistant Secretary shall so act; if neither the Secretary nor an Assistant Secretary is present, then a secretary shall be appointed by the chairman of the meeting. The chairman of any meeting of stockholders shall determine the order of business and the

- 4 -

procedure at the meeting, including such regulation of the manner of voting and the conduct of discussion as seem to him in order. Unless the chairman of the meeting of stockholders shall otherwise determine, the order of business shall be as follows:

(a) Calling of the meeting to order.

(b) Election of a chairman and the appointment of a secretary if necessary.

(c) Presentation of proof of the due calling of the meeting.

(d) Presentation and examination of proxies and determination of a quorum.

(e) Reading and settlement of the minutes of the previous meeting.

(f) Reports of officers.

(g) The election of directors if an annual meeting, or a meeting called for that purpose.

(h) Unfinished business.

(i) New business.

(j) Adjournment.

Section 11. Treasury Stock. The Corporation shall not vote, directly or indirectly, shares of its own stock owned by it and such shares shall not be counted for quorum purposes.

Section 12. Action Without Meeting. Any action permitted or required by law, the charter documents of the Corporation or these Bylaws to be taken at a meeting of stockholders, may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock who would have been entitled to vote on the action if it had been submitted to a meeting of stockholders.

Article III

Board of Directors

Section 1. Power; Number; Term of Office. The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors, and subject to the restrictions imposed by law or the charter documents of the Corporation or these Bylaws, the Board of Directors may exercise all the powers of the Corporation.

The number of directors which shall constitute the whole Board of Directors shall be six (6), and they shall be divided into two classes, namely three (3) Class A directors and three (3) Class B directors, according to the class of common stock that elected or appointed them. Each director shall hold office until the next annual meeting of stockholders, and until such director’s successor shall have been elected and qualified or until such director’s earlier death, resignation or removal.

Unless otherwise provided in the charter documents of the Corporation, directors need not be stockholders or residents of the state of incorporation of the Corporation.

- 5 -

Section 2. Voting Powers of Directors. Each class of directors shall have one vote. The presence at any meeting on one Class A director and one Class B director shall constitute a quorum for the transaction of business. The transaction of any business at any meeting shall require a quorum and the unanimous vote of both classes of directors. The vote of each class of directors shall be determined by agreement among the directors of such class present at the meeting or, failing such agreement, by the majority vote of such directors.

Section 3. Place of Meetings; Order of Business. The Board of Directors may hold their meetings and may have an office and keep the books of the Corporation, except as otherwise provided by law, in such place or places, within or without the state of incorporation of the Corporation, as the Board of Directors may from time to time determine by resolution. At all meetings of the Board of Directors business shall be transacted in such order as shall from time to time be determined by the Chairman of the Board (if any), or in the Chairman of the Board’s absence by the President, or by resolution of the Board of Directors.

Section 4. First Meeting. Each newly elected Board of Directors may hold its first meeting for the purpose of organization and the transaction of business, if a quorum is present, immediately after and at the same place as the annual meeting of stockholders. Notice of such meeting shall not be required. At the first meeting of the Board of Directors in each year at which a quorum shall be present, held next after the annual meeting of stockholders, the Board of Directors shall elect the officers of the Corporation.

Section 5. Regular Meetings. Regular meetings of the Board of Directors shall be held at such times and places as shall be designated from time to time by resolution of the Board of Directors. Notice of such regular meetings shall not be required.

Section 6. Special Meetings. Special meetings of the Board of Directors may be called by the Chairman of the Board (if any), the President or on the written request of any director, by the Secretary, in each case on at least twenty-four (24) hours personal, written, telegraphic, cable or wireless notice to each director. Such notice, or any waiver thereof pursuant to Article VI, Section 3 hereof, need not state the purpose or purposes of such meeting, except as may otherwise be required by law or provided for in the charter documents of the Corporation or these Bylaws.

Section 7. Removal. Any director may be removed, with or without cause, by the holders of a majority of the class of common stock issued and outstanding that elected such director and that are then entitled to vote at an election of directors.

Section 8.Vacancies. Any vacancy occurring on the Board of Directors shall be filled by the person designated in writing by the holders of the majority of the class of common stock issued and outstanding that elected the director vacating such position and that are entitled to vote at an election of directors. Any director so chosen shall hold

- 6 -

office until the next annual election and until his successor shall be duly elected and qualified, unless sooner displaced.

Section 9.Compensation. The Board of Directors shall have the authority to fix the compensation of directors.

Section 10.Presumption of Assent. A director who is present at a meeting of the Board of Directors at which action on any corporate matter is taken shall be presumed to have assented to the action unless his dissent shall be entered into the minutes of the meeting or unless he shall file his written dissent to such action with the person acting as secretary of the meeting before the adjournment thereof. Such right to dissent shall not apply to a director who voted in favor of such action.

Section 11. Action Without a Meeting; Telephone Conference Meeting. Unless otherwise restricted by the charter documents of the Corporation, any action required or permitted to be taken at any meeting of the Board of Directors may be taken without a meeting if all members of the Board of Directors consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the Board of Directors. Such consent shall have the same force and effect as a unanimous vote at a meeting, and may be stated as such in any document or instrument filed with the Secretary of State of the state of incorporation of the Corporation.

Unless otherwise restricted by the charter documents of the Corporation or these Bylaws, subject to the requirement for notice of meetings, members of the Board of Directors may participate in a meeting of such Board of Directors by means of a conference telephone connection or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such a meeting shall constitute presence in person at such meeting, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened.

Section 12. Approval or Ratification of Acts or Contracts by Stockholders. The Board of Directors in its discretion may submit any act or contract for approval or ratification at any annual meeting of the stockholders, or at any special meeting of the stockholders called for the purpose of considering any such act or contract, and any act or contract that shall be approved or ratified by the vote of the stockholders holding a majority (or such greater percentage as may be required by these Bylaws to approve or ratify the act or contract under consideration) of the issued and outstanding shares of stock of the Corporation entitled to vote and present in person or by proxy at such meeting (provided that a quorum is present), shall be as valid and as binding upon the Corporation and upon all the stockholders as if it has been approved or ratified by every stockholder of the Corporation. In addition, any such act or contract may be approved or ratified by the written consent of stockholders holding a majority (or such greater percentage as may be required by these Bylaws to approve or ratify the act or contract under consideration) of the issued and outstanding shares of capital stock of the Corporation entitled to vote, and such consent shall be as valid and binding upon the

- 7 -

Corporation and upon all the stockholders as if it had been approved or ratified by every stockholder of the Corporation.

Section 13. Special Corporate Actions By Directors. Any Important Matter (as defined below) shall be submitted to, and require the approval of, the Board of Directors of the Corporation and, notwithstanding any other provision of these Bylaws, no officer, employee or agent of the Corporation shall have the right or power to enter into an obligation for or to approve any Important Matter unless specifically so authorized by duly adopted resolutions of the Board of Directors. The term “Important Matter” shall mean any matter involving any of the following matters:

(a) any declaration of a dividend or distribution on, or any purchase, redemption or other acquisition for value of, any capital stock of the Corporation except to the extent expressly required by the terms thereof;

(b) the approval of each annual operating and capital budget and any significant modification thereof;

(c) the approval of any non-budgeted capital expenditure that (in one transaction or a series of related transactions) exceeds $1,000,000;

(d) the approval of any non-budgeted operating expenditure that exceeds $250,000;

(e) the creation or assumption of (i) any indebtedness for borrowed money (other than such indebtedness due within one year not exceeding $10,000,000) or (ii) any mortgage, lien, security interest or encumbrance on any of the assets or properties of the Corporation other than in the ordinary course of business or by operation of law;

(f) acting as surety, granting guaranties or incurring similar liabilities on behalf of third parties (which term shall include the stockholders of the Corporation or any of their affiliates), directly or indirectly, whether for borrowed money or otherwise;

(g) the conveyance, sale or other disposition of any asset other than in the ordinary course of business (in one transaction or a series of related transactions) having a fair market value in excess of $1,000,000;

(h) the acquisition of non-budgeted assets which obligate the Corporation to make aggregate expenditures in excess of $1,000,000;

(i) the non-budgeted acquisition of or investment in any other corporation, partnership, joint venture or other business;

- 8 -

(j)the organization of any new subsidiaries or the entry into any business which is not conducted by the Corporation as of the date of adoption of these Bylaws;

(k) any transaction or agreement with a non-affiliated third party pertaining to the purchase, transportation or sale of natural gas which involves:

1)a firm obligation for the purchase of more than 35 billion cubic feet of natural gas reserves;

2)a firm sales obligation entailing a deliverability of more than 10 million cubic feet of natural gas per day; or

3)a firm transportation obligation entailing a commitment of capacity for more than 20 million cubic feet of natural gas per day;

(l) any transaction or agreement with either stockholder of the Corporation or any of their affiliates, other than in the ordinary course of business involving delivery or transportation of natural gas in volumes not in excess of 10,000 Mcf/d;

(m) establishment of compensation and benefit packages for employees other than budgeted increases in compensation and benefits;

(n) any employment contract;

(o) the adoption of (i) any bonus or employee benefit plan or program or (ii) any material amendment to or change in any such plan or program, other than as provided for in the budget;

(p) the payment of any bonuses except for bonuses approved under Board- approved benefit plans, other than as provided for in the budget;

(q) the institution of litigation in any court or a proceeding in arbitration involving a claim in excess of $1,000,000 or the settlement of any litigation or arbitration involving the payment by the Corporation of more than $250,000;

(r) the establishment and modification of significant accounting methods, practices or policies or significant tax policies;

(s) the change of the fiscal year of the Corporation;

(t) the voting of, or giving any consent with respect to, any stock owned by the Corporation;

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(u)any material action with respect to FERC certificates, material rate settlements and other material regulatory proceedings and filings, including rate filings;

(v) any filing with the Securities and Exchange Commission;

(w) any contract entered into after the date of adoption of these Bylaws or any amendment to any existing or future contract with a stockholder of the Corporation or any affiliate thereof, provided that this provision shall not apply to any action required to implement all contracts between Florida Gas Transmission Company and affiliates of the stockholders of the Corporation which contracts were in existence on March 27, 1986, and provided further that this Section (w) shall not apply to those contracts exempt under Section (1) hereof ;

(x) instituting proceedings to have the Corporation adjudicated bankrupt or insolvent, or consenting to the institution of bankruptcy or insolvency proceedings against the Corporation or filing a petition seeking, or consenting to, reorganization or relief with respect to the Corporation under any applicable federal or state law relating to bankruptcy, or consenting to the appointment of a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Corporation or a substantial part of its property, or make any assignment for the benefit of creditors of the Corporation, or admitting in writing the Corporation’s inability to pay its debts generally as they become due, or taking action in furtherance of any such action; and;

(y) such other matters as are required by law to be approved by the stockholders of the Corporation or the Board of Directors.

The Board of Directors of the Corporation shall take or cause to be taken such action as may be required (including, without limitation, adoption of appropriate bylaw provisions) to ensure that the approval of the Corporation as the sole stockholder of each subsidiary of the Corporation is required in order for such subsidiary to enter into an obligation for or to approve any Important Matter (with references to the Corporation in the aforesaid list to mean such subsidiary for such purpose).

Article IV

Officers

Section 1. Number, Titles and Term of Office. The officers of the Corporation shall be a President, one or more Vice Presidents (any one or more of whom may be designated Executive Vice President or Senior Vice President), a Treasurer, a Secretary, and, if the Board of Directors so elects, a Chairman of the Board, and such other officers as the Board of Directors may from time to time elect or appoint. Each officer shall hold office until such officer’s successor shall be duly elected and shall qualify or until such

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officer’s death or until such officer shall resign or shall have been removed in the manner hereinafter provided. Any number of offices may be held by the same person, unless the charter documents of the Corporation provide otherwise. Except for the Chairman of the Board, no officer need be a director.

Section 2.Salaries. The salaries or other compensation of the officers and agents of the Corporation shall be fixed from time to time by the Board of Directors.

Section 3.Removal. Any officer or agent elected or appointed by the Board of Directors may be removed, either with or without cause, by the Board of Directors. Such removal shall be without prejudice to the contract rights, if any, of the person so removed. Election or appointment of an officer or agent shall not itself create contract rights.

Section 4.Vacancies. Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors.

Section 5.Powers and Duties of the Chief Executive Officer. The President shall be the chief executive officer of the Corporation unless the Board of Directors designates the Chairman of the Board as the chief executive officer. Subject to the control of the Board of Directors, the chief executive officer shall have general executive charge, management, and control of the properties, business and operations of the Corporation with all such powers as may be reasonably incident to such responsibilities; he may sign all certificates for shares of capital stock of the Corporation; and shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to him by the Board of Directors.

Section 6.Powers and Duties of the Chairman of the Board. If elected, the Chairman of the Board shall preside at all meetings of the stockholders and of the Board of Directors; and he shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the Board of Directors.

Section 7. Powers and Duties of the President. Unless the Board of Directors otherwise determines, the President shall, in the absence of the Chairman of the Board or if there is no Chairman of the Board, preside at all meetings of the stockholders and (should the President be a director) of the Board of Directors; and the President shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to the President by the Board of Directors.

Section 8.Vice Presidents. In the absence of the President, or in the event of his inability or refusal to act, a Vice President designated by the Board of Directors shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. In the absence of a designation by the Board of Directors or a Vice President to perform the duties of the President, or in the event of his absence of inability or refusal to act, the Vice President who is present and who is senior in terms of time as a Vice President of the Corporation shall so act. The

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Vice President shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe.

Section 9.Treasurer. The Treasurer shall have responsibility for the custody and control of all the funds and securities of the Corporation, and the Treasurer shall have such other powers and duties as designated by these Bylaws and as from time to time may be assigned by the Board of Directors. The Treasurer shall perform all acts incident to the position of Treasurer, subject to the control of the chief executive officer and the Board of Directors; and he shall, if required by the Board of Directors, give such bond the faithful discharge of his duties in such form as the Board of Directors may require.

Section 10.Assistant Treasurers. Each Assistant Treasurer shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the chief executive officer or the Board of Directors. The Assistant Treasurer shall exercise the powers of the Treasurer during that officer’s absence or inability or refusal to act.

Section 11. Secretary. The Secretary shall keep the minutes of all meetings of the Board of Directors and the stockholders in books provided for that purpose; shall attend to the giving and serving of all notices; may in the name of the Corporation affix the seal of the Corporation to all contracts of the Corporation and attest the affixation of the seal of the Corporation thereto; may sign with the other appointed officers all certificates for shares of capital stock of the Corporation; shall have charge of the certificate books, transfer books and stock ledgers, and such other books and papers as the Board of Directors may direct, all of which shall at all reasonable times be open to inspection of any director upon application at the office of the Corporation during business hours; shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to the Secretary by the Board of Directors,; and shall in general perform all acts incident to the office of Secretary, subject to the control of the chief executive officer and the Board of Directors.

Section 12. Assistant Secretaries. Each Assistant Secretary shall have the usual powers and duties pertaining to such office, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to an Assistant Secretary by the chief executive officer and the Board of Directors. The Assistant Secretary shall exercise the powers of the Secretary during that officer’s absence or inability or refusal to act.

Article V

Capital Stock

Section 1. Certificates of Stock. The certificates for shares of the capital stock of the Corporation shall be in such form, not inconsistent with that required by law and the charter documents of the Corporation, as shall be approved by the Board of Directors. The Chairman of the Board (if any), President, or a Vice President shall cause to be

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issued to each stockholder one or more certificates, under seal of the Corporation or a facsimile thereof if the Board of Directors shall provided for a seal, and signed by the Chairman of the Board (if any), President, or a Vice President and the Secretary, or an Assistant Secretary or the Treasurer or an Assistant Treasurer certifying the number and class of shares owned by such stockholder in the Corporation; provided, however, that any of or all the signatures on the certificate may be facsimile. The stock record books and the blank stock certificate books shall be kept by the Secretary, or at the office of such transfer agent or transfer agents as the Board of Directors may from time to time by resolution determine. In case any officer, transfer agent or registrar who shall have signed or whose facsimile signature or signatures shall have been placed upon any such certificate or certificates shall have ceased to be such officer, transfer agent or registrar before such certificate is issued by the Corporation, such certificate may nevertheless be issued by the Corporation with the same effect as if such person were such officer, transfer agent or registrar at the date of the issue. The stock certificates for each class of stock shall be consecutively numbered and shall be entered in the books of the Corporation as they are issued and shall exhibit the holder’s name and number of shares.

Section 2. Transfer of Shares. The shares of stock of the Corporation shall be transferable only on the books of the Corporation by the holders thereof in person or by their duly authorized attorneys or legal representatives upon surrender and cancellation of certificates for a like number of shares. Upon surrender to the Corporation or a transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books.

Section 3. Ownership of Shares. The Corporation shall be entitled to treat the holder of record of any share or shares of capital stock of the Corporation as the holder in fact thereof and accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of the state of incorporation of the Corporation or these Bylaws.

Section 4. Regulations Regarding Certificates. The Board of Directors shall have the power and authority to make all such rules and regulations as they may deem expedient concerning the issue, transfer and registration or the replacement of certificates for shares of capital stock of the Corporation.

Section 5. Lost or Destroyed Certificates. The Board of Directors may determine the conditions upon which the Corporation may issue a new certificate of stock in place of a certificate theretofore issued by it which is alleged to have been lost, stolen or destroyed; and may, in their discretion, require the owner of such certificate or such owner’s legal representative to give bond, with surety sufficient to indemnify the Corporation and each transfer agent and registrar against any and all losses or claims which may arise by reason of the issue of a new certificate in the place of the one so lost, stolen or destroyed.

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Article VII

Miscellaneous Provisions

Section 1. Fiscal Year. The fiscal year of the Corporation shall begin on the first day of January of each year.

Section 2. Corporate Seal. The Board of Directors may provide a suitable seal, containing the name of the Corporation. The Secretary shall have charge of the seal (if any). If and when so directed by the Board of Directors, duplicates of the seal may be kept and used by the Treasurer or by the Assistant Secretary or Assistant Treasurer.

Section 3. Notice and Waiver of Notice. Whenever any notice is required to be given by law, the charter documents of the Corporation or under the provisions of these Bylaws, said notice shall be deemed to be sufficient if given (i) by telegraphic, cable or wireless transmission (including by telecopy or facsimile transmission) or (ii) by deposit of the same in a post office box or by delivery to an overnight courier service company in a sealed prepaid wrapper addressed to the person entitled thereto at such person’s post office address, as it appears on the records of the Corporation, and such notice shall be deemed to have been given on the day of such transmission or mailing or delivery to courier, as the case may be.

Whenever notice is required to be given by law, the charter documents of the Corporation or under any of the provisions of these Bylaws, a written waiver thereof, signed by the person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a person at a meeting shall constitute a waiver of notice of such meeting, except when the person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the stockholders or directors need be specified in any written waiver of notice unless so required by the charter documents of the Corporation or these Bylaws.

Section 4.Resignations. Any director or officer may resign at any time. Such resignation shall be made in writing and shall take effect at the time specified therein, or if no time is specified, at the time of its receipt by the chief executive officer or Secretary. The acceptance of a resignation shall not be necessary to make it effective, unless expressly so provided in the resignation.

Section 5. Facsimile Signatures. In addition to the provisions for the use of facsimile signatures elsewhere specifically authorized in these Bylaws, facsimile signatures of any officer or officers of the Corporation may be used whenever and as authorized by the Board of Directors.

Section 6. Reliance upon Books, Reports and Records. A member of the Board of Directors shall in performance of such person’s duties, be fully protected in relying in

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good faith upon the books of account or reports made to the Corporation by any of its officers, or by an independent certified public accountant, or by an appraiser selected with reasonable care by the Board of Directors, or in relying in good faith upon other records of the Corporation.

Section 7. Separateness Operation Covenants. The Corporation shall conduct its business and operations in a manner that ensures its separate and distinct identity. In furtherance of this objective, the Corporation shall:

(a) maintain its books and records separate from any other person or entity;

(b) maintain its accounts separate from those of any other person or entity;

(c) not commingle its assets with those of any other entity, and maintain its assets in a manner so that it is not costly or difficult to segregate, identify or ascertain its assets;

(d) conduct its own business in its own name;

(e) maintain separate financial statements;

(f) pay its own liabilities out of its own funds;

(g) observe all entity formalities and other formalities required by its governance documents;

(h) maintain an arm’s-length relationship with its affiliates;

(i) pay the salaries of its own employees and contractors and maintain a sufficient number of employee or contractors in light of its contemplated business operations;

(j) not guarantee or become obligated for the debts of any stockholder of the Corporation’s parent, Citrus Corp. (hereinafter referred to as “Citrus Stockholder”), or the debts of any parent, subsidiary, or affiliate of any Citrus Stockholder (together hereinafter referred to as “Affiliated Entity”), or hold out its credit as being available to satisfy the obligations of any Citrus Stockholder or any Affiliated Entity, or permit all or substantially all of the Corporation’s debt to be guaranteed by a Citrus Stockholder or an Affiliated Entity;

(k) not acquire obligations or securities of any Citrus Stockholder or any Affiliated Entity;

(l) allocate fairly and reasonably any overhead for office space or services shared with or performed by affiliates;

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(m) use separate stationery, invoices, and checks;

(n) not pledge its assets for the benefit of any Citrus Stockholder or any Affiliated Entity, or make any loans or advances to any Citrus Stockholder or any Affiliated Entity;

(o) hold itself out as a separate entity;

(p) correct any known misunderstanding regarding its separate identity; and

(q) maintain adequate capital in light of its contemplated business operations.

Article VII

Amendments

The Board of Directors shall have the power to adopt, amend and repeal from time to time Bylaws of the Corporation, subject to the right of the stockholders entitled to vote with respect thereto amend to or repeal such Bylaws as adopted or amended by the Board of Directors; provided, that any alteration, amendment or repeal of any “Important Matter” set forth in Article III, Section 12 of these Bylaws shall require the approval of the stockholders then entitled to vote.

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