Edgar Filing: SOUTHERN UNION CO

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

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, 2005

__ 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

417 Lackawanna Avenue	18503-2013
Scranton, Pennsylvania	(Zip Code)
(Former address of principal executive offices)

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
5.75% Corporate Units	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 statements 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 Exchange Act Rule 12b-2).

Yes No _P

The aggregate market value of the Common Stock held by non-affiliates of the Registrant as of June 30, 2005 was $2,148,350,492 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2005). 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 March 3, 2006 was 111,673,042.

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 2, 2006, are incorporated by reference into Part III.

(182 total number of pages)

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2005

Table of Contents

		Page
	PART I
ITEM 1.	Business.	2
ITEM 1A.	Risk Factors.	20
ITEM 1B.	Unresolved Staff Comments.	26
ITEM 2.	Properties.	26
ITEM 3.	Legal Proceedings.	27
ITEM 4.	Submission of Matters to a Vote of Security Holders.	27
	PART II
ITEM 5.	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities.	28
ITEM 6.	Selected Financial Data.	30
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	31
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	50
ITEM 8.	Financial Statements and Supplementary Data.	52
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	52
ITEM 9A.	Controls and Procedures.	52
ITEM 9B.	Other Information.	53
	PART III
ITEM 10.	Directors and Executive Officers of the Registrant.	54
ITEM 11.	Executive Compensation.	54
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	54
ITEM 13.	Certain Relationships and Related Transactions.	54
ITEM 14.	Principal Accountant Fees and Services.	54
	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules.	55
Signatures.		59
Index to the Consolidated Financial Statements.		F-1

Table of Contents

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 transportation, storage and distribution of natural gas in the United States. Through Southern Union’s wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LP (Panhandle Eastern Pipe Line), and its subsidiaries (collectively Panhandle Energy), the Company owns and operates interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions. Panhandle Energy also owns and operates a liquefied natural gas (LNG) import terminal, located on Louisiana’s Gulf Coast. Through its investment in CCE Holdings, LLC (CCE Holdings), Southern Union has an interest in and operates Transwestern Pipeline Company, LLC (Transwestern) and Florida Gas Transmission Company (Florida Gas), interstate pipeline companies that transport natural gas from producing areas in western Texas, Colorado and New Mexico to markets throughout the Southwest and to California, and from producing areas along the Gulf Coast and in the Gulf of Mexico to Florida, respectively. Through Southern Union’s three regulated utility divisions - Missouri Gas Energy, PG Energy and New England Gas Company - the Company serves natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island.

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 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.

Recent Acquisitions and Divestiture - As part of its goal to become a diversified natural gas service provider, Southern Union has made a series of business acquisitions and divestitures during the past several years. These are as follows:

Acquisition of Sid Richardson Energy Services - On March 1, 2006, Southern Union acquired Sid Richardson Energy Services, Ltd., a privately held natural gas gathering and processing company, and related entities 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) that was entered into between the Company and Enhanced Service Systems, Inc. (ESSI), a wholly-owned subsidiary as borrower and a group of banks on March 1, 2006. The Sid Richardson Bridge Loan is available for a maximum period of 364 days at interest rates tied to LIBOR or prime rate plus a spread based upon the credit ratings of the Company’s senior unsecured debt. Under the terms of the Sid Richardson Bridge Loan, the Company is required to apply 100 percent of the net cash proceeds from asset dispositions and from the issuance of equity and/or debt, other than from the refinancing of debt, to repay the bridge loan facility. The Sid Richardson Bridge Loan is secured by the Company’s pledge of its interests in Panhandle Eastern Pipe Line and a pledge of the equity interests in Sid Richardson Energy Services, Ltd. and related entities.

Table of Contents

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 customers include power generating companies, utilities, energy marketers and industrial users located primarily in the southwestern United States. Southern Union Gas Services’ major natural gas pipeline interconnects are with ATMOS Pipeline and Storage, LLC, El Paso Natural Gas Company, Energy Transfer Fuel, LP, Enterprise Products Pipeline, LLC and Transwestern. Its major natural gas liquids pipeline interconnects are with Chapparal Pipeline Co., Louis Dreyfus Pipeline LP, and Chevron Pipeline.

Disposition of the Rhode Island Operations of New England Gas Company - On February 15, 2006, Southern Union entered into a definitive agreement to sell the Rhode Island operations of its New England Gas Company division to National Grid USA for $575 million, less assumed debt of $77 million, subject to working capital adjustments. Proceeds from the sale will be 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.

Disposition of PG Energy - On January 26, 2006, Southern Union entered into a definitive agreement to sell the assets of its PG Energy natural gas distribution division in Pennsylvania to UGI Corporation for approximately $580 million, subject to working capital adjustments. Proceeds from the sale will be 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.

Execution of the January 26, 2006 and February 15, 2006 sales agreements constituted a subsequent event under generally accepted accounting principles required to be considered by the Company in its annual assessment for 2005 of the carrying value of the Company’s goodwill. Accordingly, based on the fair values of these reporting units derived principally from the definitive sales agreements, an estimated goodwill impairment charge of $175 million was recorded in the 2005 period in the Company’s Distribution segment. Additional impairment charges may be determined and recorded in subsequent periods due to changes in the underlying book values of these reporting units prior to completion of the sale transactions. Pursuant to FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company will report these assets as held for sale and report their results of operations as discontinued operations in 2006. The Company currently anticipates completing the sale transactions by the end of the third quarter in 2006. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Federal and State Income Taxes from Continuing Operations.

Investment in CCE Holdings - On November 17, 2004, CCE Holdings, a joint venture in which a wholly-owned Southern Union subsidiary owns a 50 percent interest, acquired all of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron Corp. and its subsidiaries. Concurrent with this transaction, CCE Holdings divested CrossCountry Energy’s interests in Northern Plains Natural Gas Company, LLC and NBP Services, LLC to ONEOK, Inc. (ONEOK). Following these transactions, CCE Holdings owns 100 percent of Transwestern and has a 50 percent interest in Citrus Corp. (Citrus), which, in turn, owns 100 percent of Florida Gas. An affiliate of El Paso Corporation owns the remaining 50 percent of Citrus. Transwestern and Florida Gas are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The Company’s investment in CCE Holdings is accounted for using the equity method of accounting. Accordingly, Southern Union has reported its share of CCE Holdings’ earnings as Earnings from unconsolidated investments in the Consolidated Statement of Operations since November 17, 2004.

Acquisition of Panhandle Energy - On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation. Panhandle Energy is subject to the rules and regulations of FERC. Panhandle Energy’s results of operations have been included in the Consolidated Statement of Operations since June 11, 2003.

Sale of Texas Operations - On January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets (Texas Operations) to ONEOK. Proceeds from the sale were used to finance a portion of the Panhandle Energy acquisition. The results of operations and gain on sale have been segregated and reported as discontinued operations in the Consolidated Statement of Operations and as assets held for sale in the Consolidated Statement of Cash Flows for the year ended June 30, 2003.

Table of Contents

BUSINESS SEGMENTS

Reportable Segments

The Company’s operations, as reported, include two 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, Southwest to California and to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and the Company’s equity investment in CCE Holdings; and

·	The Distribution segment, which is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through the Company’s three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company.

The Company’s operations also include other subsidiaries established to support and expand natural gas sales and other energy sales, which are not included in the Transportation and Storage segment or the Distribution segment. These subsidiaries do not meet the quantitative thresholds for determining reportable segments and have been combined for disclosure purposes in the All Other category. For information about the revenues, operating income, assets and other financial information relating to the All Other category, see Item 8. Financial Statements and Supplementary Data, Note 21 - Reportable Segments.

The Company also provides various corporate functions to support its operating businesses. Except for services provided pursuant to the Management Agreement (as defined in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Other matters - Management Agreement), the corporate services provided to its operating businesses do not generate operating revenues. The primary corporate services provided include Executive Management, Accounting, Communications, Human Resources, Information Technology, Insurance, Internal Audit, Investor Relations, Environmental, Legal, Payroll, Purchasing, Risk Management, Tax and Treasury.

The Company evaluates segment performance using several factors, of which the primary financial measure, beginning January 1, 2005, is earnings before interest and taxes (EBIT). Evaluating segment performance based on EBIT is a change from utilizing operating income in prior periods. Due to the significance of the operating results of the Company’s November 2004 investment in CCE Holdings, which are included in Earnings from unconsolidated investments, management felt that EBIT would allow management and investors to more effectively evaluate the performance of all of the Company’s consolidated subsidiaries and unconsolidated investments. Accordingly, prior period segment performance information has been conformed to the current period presentation. 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. Additionally, EBIT should be considered in conjunction with net earnings and other performance measures such as operating income or net 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 year ended December 31, 2005, the six months ended December 31, 2004, or the years ended June 30, 2004 and 2003.

Table of Contents

Transportation and Storage Segment

Services

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and the Company’s 50 percent equity interest in CCE Holdings. For the year ended December 31, 2005, this segment represented 68 percent of the Company’s total segment EBIT, excluding the impact of the $175 million goodwill impairment.

For the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, the Transportation and Storage segment’s operating revenues were $505.2 million, $242.7 million, $490.9 million and $24.5 million, respectively. For the year ended December 31, 2005 and the period subsequent to the Company’s November 2004 investment in CCE Holdings, Earnings from unconsolidated investments contributed by CCE Holdings were $70.4 million and $4.6 million, respectively.

Panhandle Energy. Panhandle Energy owns and operates a large natural gas open-access interstate pipeline network. The pipeline network, consisting of the Panhandle Eastern Pipe Line Company, LP (Panhandle Eastern Pipe Line) 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 and Southwest with a comprehensive array of transportation and storage services. Panhandle Eastern Pipe Line’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 the states of 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 the states of 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 Energy has five gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma. Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage), a direct wholly-owned subsidiary of Panhandle Eastern Pipe Line, operates four of these fields and Trunkline operates one. Through Trunkline LNG Company, LLC (Trunkline LNG), Panhandle Energy 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 1.2 billion cubic feet per day (Bcf/d).

Approximately half of Panhandle Energy’s revenue comes from reservation fees related to long-term service agreements with local distribution company customers and their affiliates. Panhandle Energy also provides firm transportation services under contracts with gas marketers, producers, other pipelines, electric power generators, and a variety of other end-users. In addition, the pipelines offer both firm and interruptible transportation to customers on a short-term or seasonal basis. Demand for gas transmission on Panhandle Energy’s pipeline systems is somewhat seasonal, with the highest throughput and a higher portion of annual operating revenues and net earnings occurring in the traditional winter heating season in the first and fourth calendar quarters.

Investment in CCE Holdings. CCE Holdings is owned 50 percent by CCE Acquisition, LLC, a wholly-owned subsidiary of Southern Union. Through CCE Holdings, Southern Union effectively owns a 50 percent interest in Transwestern and a 25 percent interest in Citrus.

Transwestern is an open-access natural gas interstate pipeline 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.

Natural gas sources from the San Juan basin and surrounding producing areas can be delivered to connecting pipelines and natural gas market hubs in the east (e.g., the Waha Hub in west Texas) as well as markets to the west like California. This flexibility allows Transwestern to respond to regional supply and demand fundamentals and optimize the utilization of its pipeline infrastructure. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

Table of Contents

Florida Gas is an open-access interstate pipeline system 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 76 percent of the natural gas consumed in the state. In addition, Florida Gas’ pipeline system operates and maintains more than 40 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to most major natural gas producing regions in the contiguous 48 states of the United States and Canada.

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

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 Transwestern and Florida Gas are reported in Earnings from unconsolidated investments in the Consolidated Statement of Operations along with the remainder of CCE Holdings.

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

Year Ended

Six Months Ended

Year Ended

December 31,

June 30,

2005

2004

Panhandle Energy

Panhandle Eastern Pipe Line

609

269

576

Trunkline

459

267

564

Sea Robin

146

182

Trunkline LNG Usage Volumes

108

217

CCE Holdings (1)

Transwestern

589

N/A

Florida Gas

699

N/A

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

of 50 percent and 25 percent, respectively.

Table of Contents

The following table provides a summary of certain statistical information associated with Panhandle Energy and CCE Holdings at December 31, 2005:

Panhandle Energy
Approximate Total Miles of Pipelines
Panhandle Eastern Pipe Line					6,500
Trunkline					3,500
Sea Robin					450
Peak Day Delivery Capacity (Bcf/d)
Panhandle Eastern Pipe Line					2.8
Trunkline					1.5
Sea Robin					1.0
Trunkline LNG					1.3
Underground Storage Capacity-Owned (Bcf)					72
Underground Storage Capacity-Leased (Bcf)					16
Trunkline LNG Terminal Storage Capacity (Bcf)					6.3
Average Number of Transportation Customers					500
Weighted Average Remaining Life of Firm Transportation Contracts
Panhandle Eastern Pipe Line					3.0
Trunkline					10.5
Sea Robin (1)					1.0
Weighted Average Remaining Life of Firm Storage Contracts
Panhandle Eastern Pipe Line					2.5
Trunkline					0.3

CCE Holdings (100 percent) (2)
Approximate Total Miles of Pipelines
Transwestern					2,500
Florida Gas					5,000
Peak Day Delivery Capacity (Bcf/d)
Transwestern					2.1
Florida Gas					2.1
Average Number of Transportation Customers
Transwestern					55
Florida Gas					110
Weighted Average Remaining Life of Firm Transportation Contracts
Transwestern					3.6
Florida Gas					10.3

(1) Sea Robin firm transportation contracts have a one-year remaining life but are evergreen
and are tied to the life of the gas reserves.
(2) Represents 100 percent of Transwestern and Florida Gas versus the Company's effective
equity ownership interest of 50 percent and 25 percent, respectively.

System Enhancements - Completed or Under Construction. Trunkline LNG is currently in the process of expanding its LNG terminal, which has increased sustainable send out capacity to approximately 1.2 billion cubic feet per day (Bcf/d) from the former level of .63 Bcf/d and will increase terminal storage capacity to 9 billion cubic feet (Bcf) from 6.3 Bcf. On December 18, 2002, FERC approved Trunkline LNG’s incremental expansion of approximately .57 Bcf/d in send out capacity and approximately 2.7 Bcf of terminal storage capacity (Phase I). Construction on Phase I commenced in September 2003 and is expected to be completed late in the first quarter or early second quarter of 2006, with an estimated cost totaling $137 million, plus capitalized interest. The expanded vaporization capacity portion of the expansion was placed into service on September 18, 2005.

Table of Contents

On September 17, 2004, as modified on September 23, 2004, FERC approved Trunkline LNG’s further incremental expansion project (Phase II). Phase II is estimated to cost approximately $82 million, plus capitalized interest, and will increase the LNG terminal’s sustainable send out capacity to 1.8 Bcf/d. Phase II has an expected in-service date of mid-2006.

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 new 36-inch pipeline was placed into service on July 22, 2005 at a total construction cost of $46.7 million, plus capitalized interest. 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.

Beginning January 2002, Trunkline LNG entered into a 22-year contract with BG LNG Services for all the uncommitted capacity at its Lake Charles, Louisiana LNG terminal facility. BG LNG Services also has contract rights for the additional .57 Bcf/d in send out capacity related to the Phase I construction. BG LNG Services has contracted for all the proposed additional sendout capacity to result from the Phase II construction, subject to Trunkline LNG achieving certain construction milestones at this facility.

Transwestern completed construction of a 375 million cubic feet per day (MMcf/d) expansion to transport additional gas from the San Juan basin at the Blanco Hub to its bi-directional mainline. The San Juan Basin Project includes looping of existing pipeline segments and increasing the horsepower at existing compressor stations. Currently, 320 MMcf/d of this expanded capacity has been subscribed under ten year contracts and an additional 25 MMcf/d has been subscribed under contracts that range from three to five years. The facilities were placed in service in May 2005 at a construction cost of approximately $123.9 million, plus capitalized interest and equity costs.

For information related to potential future expansion projects of the Company or through its investment in unconsolidated entities, see Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations - Business Strategy.

Significant Customers. The following table provides Panhandle Energy’s percent of transportation and storage segment revenues and related weighted average contract lives of its significant customers at December 31, 2005:

	Percent of			Weighted
	Revenues			average life
	For Year Ended			of contracts at
Customer	December 31, 2005 (5)			December 31, 2005

BG LNG Services (1)		17	%		18.1
ProLiance		16			2.7
Ameren Corp (2)		11			0.4	(4)
CMS Energy and affiliates (3)		8			3.3
Other top 10 customers		14			N/A
Remaining customers		34			N/A
Total percentage		100	%

__________

(1)

BG LNG Services’ contracts will expand with the completion of Phase I and Phase II. Phase I is currently expected to be completed late in the first quarter or early second quarter 2006. Phase II is expected to be completed by mid-2006. Phase I will provide an annual increase of gross reservation revenues of approximately $39 million, $6 million of which was realized during 2005 due to the expanded vaporization capacity associated with the Phase I project. Phase II will provide additional annual gross revenues of approximately $22 million. (See Item 8. Financial Statements and Supplementary Data, Note 16 - Regulation and Rates). BG LNG Services’ transportation contract with Trunkline will increase in volume proportionally with the Phase I and Phase II expansions and is expected to increase reservation revenues by $8 million and $5 million, respectively, from 2005 firm transport levels.

(2)	Primarily these Ameren Corp subsidiaries are Union Electric, Central Illinois Light Company, Illinois Power and Central Illinois Public Service.

(3)

Primarily Consumers Energy contracts that originally were set to expire in late 2005 but were amended and extended to 2008. These amended contracts will result in a reduction in CMS Energy’s revenue contribution to Panhandle Energy in calendar year 2006, the first full year of effectiveness. If the new contract had been in effect for the full year ended December 31, 2005, Panhandle Energy’s operating revenues would have been approximately $9 million lower.

(4)	In February 2006, certain expiring contracts with Ameren were renewed. These renewed contracts have a weighted average remaining life of 9.3 years.

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

Table of Contents

Panhandle Energy’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 Energy’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 Transwestern’s significant customers:

Percent of

Transwestern's

Total Operating

Remaining

Revenues

average life

For Year Ended

of contracts at

Customer

December 31, 2005 (1)

December 31, 2005

Southern California Gas Company

4.2

BP Energy

4.0

Pacific Gas & Electric Company

1.2

Other top 10 customers

N/A

Remaining customers

N/A

Total percentage

100

_____________________

(1)	The Company accounts for its investment in CCE Holdings using the equity method. Accordingly, it reports its share of CCE Holdings’ earnings, including the Company’s share of Transwestern’s revenues, within Earnings from unconsolidated investments in the Consolidated Statement of Operations.

The following table provides information related to Florida Gas’ significant customers:

Percent of

Florida Gas'

Total Operating

Remaining

Revenues

average life

For Year Ended

of contracts at

Customer

December 31, 2005 (1)

December 31, 2005

Florida Power & Light

9.4

Tampa Electric/Peoples Gas

11.0

Other top 10 customers

N/A

Remaining customers

N/A

Total percentage

100

_____________________

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

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

Table of Contents

Regulation and Rates

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

FERC has comprehensive jurisdiction over Panhandle Eastern Pipe Line, Southwest Gas Storage, Trunkline, Trunkline LNG, Sea Robin, Transwestern 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. Panhandle Eastern Pipe Line, Trunkline, Sea Robin, Trunkline LNG, Southwest Gas Storage, Transwestern and Florida Gas hold certificates of public convenience and necessity issued by FERC, authorizing them to construct and operate the pipelines, facilities and properties now in operation for which such certificates are required, and to transport and store natural gas in interstate commerce.

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

	Date of Last
Company	Rate Filing	Status

Panhandle Eastern Pipe Line	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
Transwestern	November 1992	Settlement effective April 1994; expected to file for new rates proposed to be effective November 2006
Florida Gas	October 2003	Settlement effective March 2005; moratorium in effect until October 2007, required to file by October 2009

Panhandle Energy, Transwestern and Florida Gas also are 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. Panhandle Energy is also subject to the Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum pipelines.

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

Competition

The interstate pipeline systems of Panhandle Energy, Transwestern 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 demand for natural gas in the areas served by Panhandle Energy, Transwestern and Florida Gas.

Table of Contents

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 Energy, Transwestern and Florida Gas will need to adapt their marketing strategies, the type of transportation and storage services and their pricing and rate responses to competitive forces. Panhandle Energy, Transwestern 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.

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 and El Paso Corporation’s Continental Connector project, could potentially compete with Panhandle Energy. Additionally, the California Public Utilities Commission has encouraged California utilities, some of which are served by Transwestern, to investigate alternative fuel sources. Increased competition could reduce the volumes of gas transported by the Company to existing markets or force the Company to lower rates in order to remain competitive.

Panhandle Energy’s other 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 and Vector Pipeline.

Transwestern competes with other transporters that also serve the Southern California market, including El Paso Natural Gas Company, Kern River Gas Transmission Company, Gas Transmission Northwest and Southern Trails Pipeline and intrastate affiliates of Southern California Gas Company and Pacific Gas and Electric Company.

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 Duke 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.

Distribution Segment

Services

The Company’s Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company. Collectively, the utility divisions serve over 965,000 residential, commercial and industrial customers through local distribution systems consisting of 14,430 miles of mains, 9,837 miles of service lines and 78 miles of transmission lines. The utility divisions’ operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. The utility divisions’ 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 year ended December 31, 2005, this segment represented 32 percent of the Company’s total segment EBIT, excluding the impact of the $175 million goodwill impairment.

For the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, the Distribution segment’s operating revenues were $1.5 billion, $549.3 million, $1.3 billion and $1.2 billion, respectively; average customers served totaled 952,075, 946,123, 949,978 and 944,657, respectively; and gas volumes sold or transported totaled 169,165 million cubic feet (MMcf), 69,435 MMcf, 173,119 MMcf and 188,333 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 total operating revenues for the year ended December 31, 2005, the six months ended December 31, 2004, or the years ended June 30, 2004 and 2003.

Table of Contents

For information about the 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.

Missouri Gas Energy. Missouri Gas Energy, headquartered in Kansas City, Missouri, serves approximately 505,000 customers in central and western Missouri (including Kansas City, St. Joseph, Joplin and Monett) through a local distribution system that consists of approximately 8,207 miles of mains, 5,184 miles of service lines and 49 miles of transmission lines. Its service territories have a total population of approximately 1,500,000. Missouri Gas Energy’s natural gas rates and operations are regulated by the Missouri Public Service Commission (MPSC) (see Item 1. Business - Business Segments - Distribution Segment - Regulation and Rates).

PG Energy. PG Energy, headquartered in Wilkes-Barre, Pennsylvania, serves approximately 159,000 customers in northeastern and central Pennsylvania (including Wilkes-Barre, Scranton and Williamsport) through a local distribution system that consists of approximately 2,536 miles of mains, 1,538 miles of service lines and 29 miles of transmission lines. Its service territories have a total population of approximately 755,000. PG Energy’s natural gas rates and operations are regulated by the Pennsylvania Public Utility Commission (PPUC) (see Item 1. Business - Business Segments - Distribution Segment - Regulation and Rates). On January 26, 2006, the Company entered into a definitive agreement to sell the assets of the PG Energy natural gas distribution division to UGI Corporation.

New England Gas Company. New England Gas Company, headquartered in Providence, Rhode Island, serves approximately 300,000 customers in Rhode Island and Massachusetts (including Providence, Newport and Cumberland, Rhode Island and Fall River, North Attleboro and Somerset, Massachusetts) through a local distribution system that consists of approximately 3,687 miles of mains and 3,115 miles of service lines. Its service territories have a total population of approximately 1,200,000. In Rhode Island and Massachusetts, New England Gas Company’s natural gas rates and operations are regulated by the Rhode Island Public Utilities Commission (RIPUC) and Massachusetts Department of Telecommunications and Energy (MDTE), respectively (see Item 1. Business - Business Segments - Distribution Segment - Regulation and Rates).

On February 15, 2006, the Company entered into a definitive agreement to sell the Rhode Island operations of the New England Gas Company division to National Grid USA. For the year ended December 31, 2005, the Rhode Island division provided approximately $424.4 million, 37,293 MMcf and $28.7 million of gas sales and transportation revenues, volumes of gas sold and transported and EBIT, respectively. The average number of gas and transportation customers served during 2005 was 244,766.

Table of Contents

The Missouri Gas Energy customers served, gas volumes sold or transported and weather-related information for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 are as follows:

				Six
	Year Ended			Months Ended
	December 31,			December 31,			Years ended June 30,
	2005			2004			2004			2003
Average number of customers:
Residential		432,627			429,292			432,037			430,861
Commercial		62,908			61,273			61,957			60,774
Industrial		101			98			95			99
Total average customers served		495,636			490,663			494,089			491,734
Transportation customers		931			879			786			461
Total average gas sales and transportation customers		496,567			491,542			494,875			492,195

Gas sales in millions of cubic feet (MMcf):
Residential		35,094			10,837			36,880			39,821
Commercial		15,335			5,082			16,026			17,399
Industrial		467			152			338			391
Gas sales billed		50,896			16,071			53,244			57,611
Net change in unbilled gas sales		308			3,503			112			61
Total gas sales		51,204			19,574			53,356			57,672
Gas transported		26,165			11,721			25,761			26,893
Total gas sales and gas transported		77,369			31,295			79,117			84,565

Gas sales revenues (In thousands of dollars):
Residential	$	441,897		$	139,086		$	395,350		$	337,293
Commercial		183,202			58,054			163,826			138,676
Industrial		9,633			1,923			3,943			3,930
Gas revenues billed		634,732			199,063			563,119			479,899
Net change in unbilled gas sales revenues		19,413			38,124			2,024			3,434
Total gas sales revenues		654,145			237,187			565,143			483,333
Gas transportation revenues		10,202			4,095			8,702			8,439
Other revenues		7,665			4,261			7,013			5,017
Total operating revenues	$	672,012		$	245,543		$	580,858		$	496,789


Weather:
Degree days (a)		4,621			1,669			4,770			5,105
Percent of 10-year measure (b)		89	%		81	%		92	%		98	%
Percent of 30-year measure (b)		89	%		82	%		92	%		98	%

(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.

Table of Contents

The PG Energy customers served, gas volumes sold or transported and weather-related information for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 are as follows:

				Six
	Year Ended			Months Ended
	December 31,			December 31,			Years ended June 30,
	2005			2004			2004			2003
Average number of customers:
Residential		143,019			142,152			142,422			141,769
Commercial		14,735			14,469			14,384			14,141
Industrial		118			115			116			120
Public authorities and other		347			345			340			337
Total average customers served		158,219			157,081			157,262			156,367
Transportation customers		575			586			602			613
Total average gas sales and transportation customers		158,794			157,667			157,864			156,980

Gas sales in millions of cubic feet (MMcf):
Residential		16,667			4,649			17,133			18,372
Commercial		6,631			2,130			6,505			6,732
Industrial		377			150			379			376
Public authorities and other		314			99			290			334
Gas sales billed		23,989			7,028			24,307			25,814
Net change in unbilled gas sales		(159	)		1,955			34			4
Total gas sales		23,830			8,983			24,341			25,818
Gas transported		23,935			11,679			26,007			28,366
Total gas sales and gas transported		47,765			20,662			50,348			54,184

Gas sales revenues (thousands of dollars):
Residential	$	207,823		$	60,119		$	183,941		$	175,337
Commercial		76,554			23,699			62,407			56,730
Industrial		4,158			1,512			3,376			2,895
Public authorities and other		3,542			1,057			2,676			2,667
Gas revenues billed		292,077			86,387			252,400			237,629
Net change in unbilled gas sales revenues		6,514			20,310			929			135
Total gas sales revenues		298,591			106,697			253,329			237,764
Gas transportation revenues		12,861			5,968			13,872			15,389
Other revenues		1,197			523			1,713			1,515
Total operating revenues	$	312,649		$	113,188		$	268,914		$	254,668


Weather:
Degree days (a)		6,288			2,301			6,240			6,654
Percent of 10-year measure (b)		103	%		100	%		103	%		109	%
Percent of 30-year measure (b)		100	%		98	%		100	%		106	%

(a) and (b) - See descriptions in the legend of comparable table previously presented for Missouri Gas Energy.

Table of Contents

The New England Gas Company’s customers served, gas volumes sold or transported and weather-related information for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 are as follows:

				Six
	Year Ended			Months Ended
	December 31,			December 31,			Years ended June 30,
	2005			2004			2004			2003
Average number of customers:
Residential		269,463			270,051			269,926			268,312
Commercial		25,455			25,358			25,798			25,442
Industrial and irrigation		205			207			226			225
Public authorities and other		53			50			47			41
Total average customers served		295,176			295,666			295,997			294,020
Transportation customers		1,538			1,248			1,242			1,462
Total average gas sales and transportation customers		296,714			296,914			297,239			295,482

Gas sales in millions of cubic feet (MMcf):
Residential		23,154			6,633			24,194			25,481
Commercial		9,449			2,669			9,753			9,725
Industrial and irrigation		2,135			1,234			1,968			2,055
Public authorities and other		21			9			25			28
Gas sales billed		34,759			10,545			35,940			37,289
Net change in unbilled gas sales		(119	)		3,074			(1,366	)		1,336
Total gas sales		34,640			13,619			34,574			38,625
Gas transported		9,392			3,859			9,080			10,959
Total gas sales and gas transported		44,032			17,478			43,654			49,584

Gas sales revenues (thousands of dollars):
Residential	$	341,329		$	97,734		$	307,534		$	290,370
Commercial		127,102			35,509			111,712			97,091
Industrial and irrigation		24,494			11,581			16,542			15,045
Public authorities and other		425			193			437			511
Gas revenues billed		493,350			145,017			436,225			403,017
Net change in unbilled gas sales revenues		8,427			36,914			5,231			(12,657	)
Total gas sales revenues		501,777			181,931			441,456			390,360
Gas transportation revenues		15,021			5,952			11,835			14,906
Other revenues		1,813			2,732			1,343			2,242
Total operating revenues	$	518,611		$	190,615		$	454,634		$	407,508


Weather:
Degree days (a)		5,801			2,004			5,644			6,143
Percent of 10-year measure (b)		106	%		98	%		102	%		111	%
Percent of 30-year measure (b)		101	%		96	%		98	%		107	%

(a) and (b) - See descriptions in the legend of comparable table previously presented for Missouri Gas Energy.

Table of Contents

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

For the year ended December 31, 2005, the majority of the gas requirements for the utility operations of Missouri Gas Energy and PG Energy were delivered under short- and long-term transportation contracts through four major pipeline companies and, for this same period, the majority of the gas requirements for the utility operations of New England Gas Company were delivered under long-term transportation contracts through four major pipeline companies. Collectively, these contracts have various expiration dates ranging from 2006 through 2036. 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. PG Energy has firm supply commitments for all areas that are supplied with gas purchased under short-term arrangements. Missouri Gas Energy, PG Energy and New England Gas Company hold contract rights to over 17 Bcf, 11 Bcf and five 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. There have been no supply-related curtailments of deliveries to firm utility sales customers of Missouri Gas Energy, PG Energy or New England Gas Company during the last ten years.

Competition

As energy providers, Missouri Gas Energy, PG 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. In order to be more competitive with certain alternate fuels in Pennsylvania, PG Energy offers an alternate fuel rate for eligible customers. This rate applies to commercial and industrial accounts that have the capability of using fuel oils or propane as alternate sources of energy. Whenever the cost of such alternate fuel drops below PG Energy's normal tariff rates, PG Energy is permitted by the PPUC to lower its price to these customers so that PG Energy can remain competitive with the alternate fuel. In no instance, however, may PG Energy sell gas under this special arrangement for less than its average commodity cost of gas purchased during the month. Competition among the use of fuel oils, natural gas and propane is generally greater in the Company’s Pennsylvania and New England service areas 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.

Table of Contents

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. In 1999, the Commonwealth of Pennsylvania enacted the Natural Gas Choice and Competition Act, which permitted small commercial and residential customers to select their supplier of natural gas. Effective April 29, 2000, all of PG Energy’s customers have the ability to select an alternate supplier of natural gas, which PG Energy will continue to deliver through its distribution system under regulated transportation service rates (with PG Energy serving as supplier of last resort). Customers can also choose to remain with PG Energy as their supplier under regulated natural gas sales rates. In either case, the applicable rate results in the same net operating revenues to PG Energy. Despite customers' acquired right to choose, thus far higher-than-normal wholesale prices for natural gas have prevented suppliers from offering competitive rates.

Regulation and Rates

The Company’s utility divisions are regulated as to rates, operations and other matters by the regulatory commissions of the states in which each operates. In Missouri and Pennsylvania, natural gas rates are established by the MPSC and PPUC, respectively, on a system-wide basis. In Rhode Island, the RIPUC approves natural gas rates for New England Gas Company. 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. Providence, Rhode Island; Fall River, Massachusetts; Kansas City, Missouri; and St. Joseph, Missouri are the four 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 upon its expiration. The franchises in Providence, Rhode Island; 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.

Other than in Pennsylvania, 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. In Pennsylvania, however, a future test year is utilized for ratemaking purposes. Therefore, rate orders in Pennsylvania generally more closely 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. Weather normalization clauses serve to stabilize earnings. New England Gas Company has a weather normalization clause in the tariff covering its Rhode Island operations.

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 and the Hazardous Liquid Pipeline Safety Act of 1979, 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.

Table of Contents

On September 21, 2004, the MPSC issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22.4 million, effective October 2, 2004. The rate order, based on a 10.5 percent rate of return on equity, also produced an improved rate design and implemented an incentive mechanism for the sharing of capacity release and offsystem sales revenues between customers and the Company.

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


	Date of Last
Company	Rate Filing	Status

Missouri Gas Energy	September 2004	Effective October 2004; potentially may file new rate case in April 2006
PG Energy	December 2000	Effective January 2001; potentially may file new rate case in April 2006
New England Gas	May 2002	Effective July 2002

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 the recent more restrictive insurance markets.

Table of Contents

Employees

As of January 31, 2006, the Company had 2,888 employees, of whom 2,028 are paid on an hourly basis and 860 are paid on a salary basis. Of the 2,028 hourly paid employees, unions represent 63 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

Missouri Gas
Gas Workers 781	193	April 30, 2009
IBEW Local 53	97	April 30, 2009
PACE Local 5-267	28	April 30, 2009
USW Local 12561, 14228	139	April 30, 2009

PG Energy
IBEW Local 2244	57	July 31, 2006
UWUA Local 406, 407, 408, 529	117	March 31, 2007

Panhandle Energy	226	May 28, 2006

New England Gas
UWUA Local 472, 431	133	April 1, 2006
USWA Local 12431-01, 12431-02	285	May 24, 2007

As of January 31, 2006, the number of persons employed by each segment is as follows: Distribution segment—1,800 persons; Transportation and Storage segment—985 persons; All Other subsidiary operations - 11 persons. In addition, the corporate employees of Southern Union totaled 92 persons.

The employees of CCE Holdings are not employees of Southern Union or its segments, and therefore, were not considered in the employee statistics noted above. As of January 31, 2006, CCE Holdings, including Florida Gas, had 626 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 year ended December 31, 2005, the six-month period ended December 31, 2004 or the years ended June 30, 2004, and 2003.

Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information as required with the Securities and Exchange Commission (SEC). 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 Web site at http://www.sug.com. The information on Southern Union’s Web site 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 promptly posted on Southern Union’s Web site.

Table of Contents

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 and compensation committees are posted on the Corporate Governance section of Southern Union’s web site 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, also 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, 2005, consolidated debt on the Consolidated Balance Sheet totaled $2.60 billion outstanding compared to total capital (long and short-term debt plus stockholders' equity) of $4.45 billion. The Company issued $1.6 billion of debt in connection with the initial financing of its March 1, 2006 acquisition of Sid Richardson Energy Services, Ltd. and related entities. Such acquisition will be repaid with the proceeds from asset sales and the issuance of debt and/or equity.

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 would 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 credit 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.

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

As of December 31, 2005, Southern Union’s debt, including Panhandle Energy’s debt, is 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 funding costs to natural gas customers.

Table of Contents

The Company’s growth strategy entails risk for investors.

The Company intends actively to 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 successfully integrate a new business into its existing operations 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 will entail numerous risks, including, among others:

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

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

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

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

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

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

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

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

The Company is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, its subsidiaries 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.

The Company does not own 100 percent of CCE Holdings, and CCE Holdings in turn does not own 100 percent of Citrus, both of which require 100 percent owner consent for distributions. As such, the Company cannot control or guarantee the receipt of distributions from either entity.

Table of Contents

The Company is subject to operating risks.

The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas, including 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 not be adequate 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.

The US EPA recently modified environmental regulations applicable to its 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 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.

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.

Table of Contents

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

Effective January 1, 2003, the Company consummated the sale of its Texas Operations to ONEOK for approximately $437 million. The sale of the Texas Operations and the acquisition of Panhandle Energy were structured in a manner intended to qualify as a like-kind exchange of property under Section 1031 of the IRC. If like-kind exchange treatment were not to apply to these transactions, most of the tax gain realized with respect to the sale of the Texas Operations would be recognized currently. The like-kind exchange rules of the Internal Revenue Code are highly complex and their application to the sale of the Texas Operations and the Panhandle Energy acquisition is not entirely clear. If the Internal Revenue Service successfully denied the benefits of Section 1031 to the sale of the Texas Operations and the Panhandle Energy acquisition, the Company could be required to pay approximately $90 million of additional income tax (before any interest or penalty) for the 2003 taxable year. Under such circumstances, the Company expects that it would be entitled over time to additional depreciation deductions with respect to the Panhandle Energy assets as a result of the higher tax basis in such assets that would exist if the benefits of Section 1031 were not available.

Similarly, the Company has structured the sale of the assets of its PG Energy division, the sale of the Rhode Island operations of the New England Gas Company division and the acquisition of the Sid Richardson Energy Services business in a manner intended to qualify as a like-kind exchange of property under Section 1031 of the IRC. The Company is currently in the process of analyzing the potential like-kind exchange treatment of these assets to determine the amount of the potential tax deferral.

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 Energy, Transwestern 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 the Congress and state legislatures and, in some respects, state regulators. The Company cannot predict or control what effect future actions of regulatory agencies may have on its business or its access to the capital markets. Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past 25 years and there is no assurance that further substantial changes will not occur or that existing policies and rules will not be applied in a new or different manner.

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

The pipeline businesses are subject to competition.

The interstate pipeline businesses of Panhandle Energy and CCE Holdings 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 Energy and CCE Holdings.

Table of Contents

The success of the pipeline 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 Energy and CCE Holdings. As a result, the volume of natural gas transported and stored depends on the actions of those third parties and is beyond the Company’s control. Further, the following factors, most of which also are beyond the Company’s control, may unfavorably impact its ability to maintain or increase current transmission and storage rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

·	future weather conditions, including those that favor alternative energy sources;

·	the market price of natural gas;

·	price competition;

·	drilling activity and supply availability;

·	the expiration of significant contracts;

·	service area competition; and

·	regulatory actions.

The success of the pipelines 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 Energy and CCE Holdings depends substantially upon the volume of natural gas they transport. As the reserves available through the supply basins connected to the Panhandle Energy and CCE Holdings systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. 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.

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 Energy and CCE Holdings 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 Energy’s top four customers accounted for 52 percent of its 2005 revenue. Transwestern’s top three customers accounted for 49 percent of its 2005 revenue. Florida Gas’ top two customers accounted for 58 percent of its 2005 revenue. The loss of any one or more of these customers could have a negative adverse effect on the Company’s business, financial condition or results of operation.

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

The pipeline revenues of Panhandle Energy and CCE Holdings are generated under natural gas transportation contracts that expire periodically and must be replaced approximately every three years, on average. Although the Company will actively pursue the renegotiation, extension and/or replacement of all of its contracts, it cannot assure that Panhandle Energy and CCE Holdings 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 Panhandle Energy and CCE Holdings are unable to renew, extend or replace these contracts, or if Panhandle Energy and CCE Holdings renew them on less favorable terms, the Company may suffer a material reduction in revenues and earnings.

Table of Contents

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 is questionable. Nevertheless, the Company cannot predict to what extent future declines in customers' creditworthiness may negatively impact its business.

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 catastrophic events such as explosions, fires, earthquakes, floods, landslides, hurricanes, 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 not be adequate to cover all liabilities or expenses incurred or revenues lost.

The inability to continue to access Tribal lands could adversely affect the Company’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

The Company’s ability to operate its pipeline system on certain Tribal lands (lands held in trust by the United States for the benefit of a Native American Tribe) will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those Tribal lands. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion projects including Transwestern's proposed expansion of its San Juan lateral in New Mexico. The Company cannot assure that it will be able to acquire new rights-of-way on Tribal lands 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 cannot be recovered in rates.

The Company’s assets and operations can be affected by weather and other natural phenomena.

The Company’s pipeline system, especially those portions that are located offshore, are 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.

RISKS THAT RELATE TO THE COMPANY’S DISTRIBUTION BUSINESS

The distribution business is highly regulated.

The Company’s distribution business is subject to regulation by state regulatory authorities. The distribution business is regulated by the MPSC, the PPUC, the RIPUC and the MDTE. These authorities regulate many aspects of the 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.

Table of Contents

The distribution business’ operating results and liquidity needs are seasonal in nature and can 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.

The Rhode Island gas distribution business, which accounted for approximately 22 percent of the Company’s revenues for the year ended December 31, 2005, is the only region in which the Company operates a distribution business that benefits from weather normalization tariffs. 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.

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 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.

CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS

The disclosure and analysis in this Form 10-K contains some 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 products, 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 publicly to update 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 10-Q and 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 thinks could cause the Company’s actual results to differ materially from expected and historical results. Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.

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

·	changes in demand for natural gas by the Company’s customers, in the composition of the Company’s customer base and in the sources of natural gas available to the Company;

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

·	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 indebtedness resulting from that acquisition;

·	risks relating to the completion of Southern Union’s pending divestitures of PG Energy and the Rhode Island assets of New England Gas Company;

·	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.

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.

Table of Contents

OTHER

PEI Power Corporation, a wholly-owned subsidiary of the Company, 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 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 facility, through a joint venture with Cayuga Energy.

ITEM 3. Legal Proceedings.

The Company and certain of its affiliates are 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. 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 Cautionary Factors That May Affect Future Results.

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

N/A

Table of Contents

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, 2004 are set forth below:

	$/Share
	High		Low

January 1 to March 3, 2006		$25.21		$23.05

(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

(Quarter Ended)
December 31, 2004		23.78		19.52
September 30, 2004		19.67		17.14
June 30, 2004		19.37		17.12
March 31, 2004		17.91		16.10

HOLDERS

As of March 3, 2006, there were 6,425 holders of record of Southern Union's common stock, and 111,673,042 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.

DIVIDENDS

Provisions in certain of Southern Union’s long-term debt and its bank credit facilities limit the payment of cash or asset dividends on capital stock. Under the most restrictive provisions in effect, Southern Union may not declare or pay any cash or asset 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 Energy that could limit Southern Union’s access to funds from Panhandle Energy for debt service or dividends. See Item 8. Financial Statements and Supplementary Data, Note 13 - Debt and Capital Leases.

Historically, Southern Union had a policy of reinvesting its earnings in its businesses, rather than paying cash dividends. Since 1994, Southern Union has distributed an annual stock dividend of five percent. On September 1, 2005, August 31, 2004, July 31, 2003, and July 15, 2002, the Company distributed its annual five percent common stock dividend to stockholders of record on August 22, 2005, August 20, 2004, July 17, 2003, and July 1, 2002, respectively. A portion of the five percent stock dividend distributed on July 15, 2002 was characterized as a distribution of capital due to the level of the Company’s retained earnings available for distribution as of the declaration date.

Table of Contents

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 will replace the Company’s historic practice of issuing an annual five percent stock dividend. The dividend is expected to be declared and paid on a quarterly basis beginning at the end of the first quarter of 2006.

EQUITY COMPENSATION PLANS

Equity compensation plans approved by stockholders include the Amended and Restated 2003 Stock and Incentive Plan and the 1992 Long-Term Stock Incentive Plan (1992 Plan). Options are still outstanding under the 1992 Plan but no shares are available for future grant thereunder because the 1992 Plan expired on July 1, 2002. 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 four or five years.

Equity compensation plans not approved by stockholders include the Pennsylvania Division Stock Incentive Plan and the Pennsylvania Division 1992 Stock Option Plan, both of which were assumed by Southern Union upon its November 4, 1999 acquisition of the assets of Pennsylvania Enterprises, Inc. Following the acquisition, options were no longer awarded under these plans.

The following table sets forth, for each type of equity compensation plan, the number of outstanding options, the weighted-average exercise price of outstanding options and the number of shares remaining available for issuance as of December 31, 2005:

	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	2,759,037	15.64	6,246,939

There are no remaining options outstanding or available for future issuance related to the Pennsylvania Division Stock Incentive Plan and the Pennsylvania Division 1992 Stock Option Plan.

The following table provides information regarding the repurchase of equity securities by the Company of shares or any other units of any other class of the Company’s equity securities that is registered by the Company pursuant to section 12 of the Exchange Act.

Period	Total number of shares purchased	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs


11/9/2005	649,343	$23.15	N/A	N/A

Table of Contents

ITEM 6. Selected Financial Data.

	As of and for the		As of and for the
	year ended		six months ended
	December 31,		December 31,		As of and for the years ended June 30,
	2005		2004 (a)		2004		2003 (b)		2002 (c)		2001 (d)
	(In thousands of dollars, except per share amounts)

Total operating revenues	$	2,019,430	$	794,338	$	1,799,774	$	1,188,500	$	980,614	$	1,461,811
Earnings from unconsolidated
investments		70,742	$	4,745	$	200	$	422	$	1,420	$	83
Net earnings:
Continuing operations (e)		3,318		6,088		101,339		43,669		1,520		40,159
Discontinued operations (f)		-		-		-		32,520		18,104		16,524
Available for common stockholders		3,318		6,088		101,339		76,189		19,624		57,285
Net earnings per diluted
common share (g):
Continuing operations		0.03		0.07		1.24		0.66		0.02		0.60
Discontinued operations		-		-		-		0.49		0.28		0.25
Available for common stockholders		0.03		0.07		1.24		1.15		0.30		0.85
Total assets		5,836,819		5,568,289		4,572,458		4,590,938		2,680,064		2,907,299
Stockholders’ equity		1,854,069		1,497,557		1,261,991		920,418		685,346		721,857
Current portion of long-term debt and
capital lease obligation		126,648		89,650		99,997		734,752		108,203		5,913
Long-term debt and capital lease
obligation, excluding current portion		2,049,141		2,070,353		2,154,615		1,611,653		1,082,210		1,329,631
Company-obligated mandatorily
redeemable preferred securities
of subsidiary trust		-		-		-		100,000		100,000		100,000
Common stock dividends (h)		-		-		-		-		-		-

(a)

The Company’s investment in CCE Holdings, which is accounted for using the equity method, was included in the Company’s Consolidated Balance Sheet at December 31, 2004. The Company’s share of net income from CCE Holdings has been recorded as Earnings from unconsolidated investments in the Company’s Consolidated Statement of Operations since its acquisition on November 17, 2004. For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisition is not comparable to the year of acquisition.

(b)

Panhandle Energy was acquired on June 11, 2003 and was accounted for as a purchase. The Panhandle Energy 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)

Effective July 1, 2001, the Company ceased amortization of goodwill pursuant to the FASB Statement No. 142, Accounting for Goodwill and Other Intangible Assets. Goodwill, which was previously classified on the Consolidated Balance Sheet as additional purchase cost assigned to utility plant and amortized on a straight-line basis over forty years, is now subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, during the year ended June 30, 2002, the Company recorded an after-tax restructuring charge of $9 million. See Item 8. Financial Statements and Supplementary Data, Note 7 - Goodwill and Intangibles and Note 14 - Employee Benefits.

(d)

The New England operations, formed through the acquisition of Providence Energy Corporation and Fall River Gas Company on September 28, 2000, and Valley Resources, Inc. on September 20, 2000, were accounted for as a purchase. Their assets are included in the Company's Consolidated Balance Sheet at June 30, 2001 and their results of operations have been included in the Company's Consolidated Statement of Operations since their respective acquisition dates. For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisitions is not comparable to the year of acquisition.

(e)	Net earnings from continuing operations are net of dividends on preferred stock of $17.4 million, $8.7 million and $12.7 million for the year ended December 31, 2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively.

(f)

On January 1, 2003, ONEOK acquired the Company’s Texas Operations, which are accounted for as discontinued operations in the Consolidated Statement of Operations for the respective periods presented in this document. In accordance with generally accepted accounting principles, Net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs. At the time of the sale, all outstanding debt of Southern Union Company and subsidiaries was maintained at the corporate level, and no debt was assumed by ONEOK.

(g)

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, July 15, 2002 and August 30, 2001.

(h)	No common stock cash dividends were paid during the periods reported. See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Dividends.

Table of Contents

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

INTRODUCTION

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

OVERVIEW

The Company’s business purpose is to provide transportation, storage and distribution of natural gas in a safe, efficient and dependable manner. Through the Company’s ownership of Panhandle Energy and equity interest in CCE Holdings, the Company operates approximately 18,000 miles of interstate pipelines that transport up to 9.7 Bcf/d of natural gas. Through Southern Union’s three regulated utility divisions - Missouri Gas Energy, PG Energy and New England Gas Company - the Company serves approximately 965,000 natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island. For additional information related to the Company’s lines of business, locations of operations and services provided, see Item 1. Business.

BUSINESS STRATEGY

The Company’s strategy is focused on achieving profitable growth and enhancing stockholder value. The key elements of its strategy include the following:

Effectively managing the Company’s substantial base of energy infrastructure assets. Southern Union will continue to focus on increasing utilization and cost savings while making prudent capital expenditures across its base of interstate transmission assets. Since the Company’s acquisition of Panhandle Energy and CCE Holdings’ acquisition of CrossCountry Energy, the Company has been successful in reducing costs while integrating back-office and support functions within the Company. Further, Southern Union will continue to focus each of its regulated operating units on meeting their allowable rates of return by managing operating costs and capital spending, without sacrificing customer safety or quality of service. When appropriate, the Company will continue to seek rate increases within its interstate transmission and gas distribution operations.

Maintaining an investment grade rating and credit profile while growing the business. The Company will continue to pursue opportunities to enhance its credit profile through further diversification of both regulated and unregulated cash flow and earnings sources and reduce its ratio of total debt to total capital over time in order to strengthen the Company’s balance sheet and financial flexibility. In this regard, Southern Union’s acquisition of Panhandle Energy in June 2003, CCE Holdings’ acquisition of CrossCountry Energy in November 2004 and the acquisition of the Sid Richardson Energy Services business in March 2006 diversified the Company’s regulated and nonregulated cash flow and earnings sources. In addition, the Company’s use of common stock, preferred stock and equity units offerings and use of free cash flow has reduced the Company’s indebtedness and enhanced its financial strength.

Expanding through development of the Company’s existing businesses. To complement the organic growth of its existing operations, the Company will continue to pursue growth opportunities through the expansion of its existing asset base. (See Item 1A. Risk Factors). Following is a summary of ongoing or planned expansion growth opportunities.

		Estimated	Estimated		Company	Project
		Project	Annual	Projected	Ownership	Status at
Project Name	Capacity	Cost (1)	EBIT	In Service	Percentage	December 31, 2005
		(In thousands)
Projects Related to Consolidated Operations

Trunkline LNG Phase I	.57 Bcf/d	$137,000	$28,000	Late first quarter or early	100%	Vaporization in service,
	2.7 Bcf storage			second quarter 2006		remainder under construction

Trunkline LNG Phase II	.6 Bcf/d	$82,000	$16,000	Mid 2006	100%	Under construction

Trunkline North Texas	.3 to .6 Bcf/d	$90,000 to $110,000	(2)	Late 2007	100%	Customer negotiations

Trunkline LNG Infrastructure	Ambient Air	$250,000 to $280,000	(2)	Mid 2008	100%	Customer negotiations
Enhancement Project (IEP)	Vaporization and
	NGL extraction
Projects Related to Unconsolidated Investments

Florida Gas Phase VII	.1 to .16 Bcf/d	$60,000 to $100,000	$6,000 to $14,000	Mid 2007	25%	Filed with the FERC

Transwestern Phoenix Expansion (3)	.5 Bcf/d	$500,000 to $600,000	(2)	Early 2008	50%	Commencing development


(1) Excludes capitalized interest and equity costs.
(2) Amount is not currently determinable as related contractual discussions are ongoing and/or the project economic analyses are still being developed.
(3) Project scope and structure under discussion with CCE Holdings members.

Selectively acquiring businesses primarily within the natural gas industry.The Company’s strategy for long-term growth includes acquiring assets that will position it favorably in the evolving North American natural gas markets. Consistent with the Company’s acquisition of Panhandle Energy, CCE Holdings’ acquisition of CrossCountry Energy and the March 1, 2006 acquisition of the Sid Richardson Energy Services business, the Company will continue to evaluate opportunities within the North American energy sector that will optimize stockholder value. As part of that evaluation, the Company seeks to balance its ability to integrate newly acquired assets with its ability to maintain an investment grade rating while providing growth in earnings and cash flow.

RESULTS OF OPERATIONS

Overview

The Company believes that its acquisition of Panhandle Energy on June 11, 2003 and CCE Holdings’ acquisition of CrossCountry Energy on November 17, 2004 represent significant steps undertaken by the Company in its transformation into a higher return business with significant growth opportunities. The acquisitions which comprise the transportation and storage industry segment for the Company contributed 68 percent, 83 percent and 62 percent of the Company’s total segment EBIT for the year ended December 31, 2005, after excluding the impact of the $175 million goodwill impairment charge in 2005, the six-month period ended December 31, 2004 and the year ended June 30, 2004, respectively. As of December 31, 2005, the Company’s operating business segments were Transportation and Storage and Distribution. These segments provided a variety of energy services including the interstate and intrastate transportation and storage of natural gas, LNG terminalling and regasification services and the local distribution of natural gas. See Item 1. Business - Business Segments. Effective with the acquisition of the Sid Richardson Energy Services business in 2006, the Company will report a new Gathering and Processing business segment.

Table of Contents

The Company evaluates segment performance based on several factors, of which the primary financial measure, beginning January 1, 2005, is earnings before interest and taxes (EBIT). Evaluating segment performance based on EBIT is a change from utilizing operating income in prior periods. Due to the significance of the operating results of the Company’s November 2004 investment in CCE Holdings, the operating results of which are included in Earnings from unconsolidated investments, management felt that EBIT would allow management and investors to more effectively evaluate the performance of all of the Company’s consolidated subsidiaries and unconsolidated investments. EBIT may not be comparable to measurements used by other companies and should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow.

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 end, certain unaudited periods are presented to facilitate a meaningful comparison of financial results between periods.

	Year Ended December 31,						Six Months Ended December 31,						Years Ended June 30,
				2004						2003
	2005			(Unaudited)			2004			(Unaudited)			2004			2003
	(In thousands)
EBIT:
Transportation and storage segment	$	281,344		$	198,422		$	94,971		$	96,212		$	200,912		$	9,699
Distribution segment		(43,928	)		106,178			19,330			34,953			120,838			144,971
Corporate and other		(10,699	)		(23,685	)		(20,705	)		(7,488	)		(10,755	)		6,095
Total EBIT		226,717			280,915			93,596			123,677			310,995			160,765
Interest		135,157			126,166			64,898			66,600			127,867			83,343
Dividends on preferred securities of subsidiary trust		-			-			-			-			-			9,480
Earnings from continuing operations before income taxes		91,560			154,749			28,698			57,077			183,128			67,942
Federal and state income taxes		70,877			60,668			13,927			22,362			69,103			24,273
Net earnings from continuing operations		20,683			94,081			14,771			34,715			114,025			43,669

Net earnings from discontinued operations		-			-			-			-			-			32,520
Preferred stock dividends		17,365			17,365			8,683			4,004			12,686			-

Net earnings available for common stockholders	$	3,318		$	76,716		$	6,088		$	30,711		$	101,339		$	76,189

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 executed agreements for the sale of its Pennsylvania and Rhode Island natural gas distribution businesses. Excluding this charge, earnings would have improved by $101.6 million. The improvement is primarily due to realization of the 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, and the 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.

Table of Contents

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 was primarily caused by a charge for the impairment of the Company’s investment in a technology company, increases in operating expenses in the Distribution segment, primarily due to environmental site remediation and 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.

Year ended June 30, 2004 versus the year ended June 30, 2003. The Company realized $25.2 million of improved earnings for the year ended June 30, 2004 primarily due to the inclusion of a full year of operating results from its June 11, 2003 acquisition of Panhandle Energy.

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, Southwest to California and to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and its equity investment in CCE Holdings and are regulated as to rates and other matters by FERC. The Transportation and Storage segment operations are somewhat sensitive to weather and are seasonal in nature with a significant percentage of annual operating revenues and net earnings occurring in the traditional winter heating season.

Historically, much of the Company’s business was conducted through long-term contracts with customers. Over the past several years some of the Company’s customers 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 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 negatively impact the Company’s results of operations and financial condition. For information related to the status of current rate filings, see Item 1. Business - Business Segments - Transportation and Storage Segment.

Table of Contents

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

	Years Ended				Six Months Ended				Years Ended
	December 31,				December 31,				June 30,
			2004				2003
Transportation and Storage Segment	2005		(Unaudited)		2004		(Unaudited)		2004		2003
	(In thousands)

Operating revenues	$	505,233	$	489,164	$	242,743	$	244,473	$	490,883	$	24,522

Operating expenses		204,711		212,106		109,796		107,796		210,105		10,102
Depreciation and amortization		62,171		56,989		30,159		33,158		59,988		3,197
Taxes other than on income and revenues		28,196		26,867		12,667		13,089		27,288		1,595
Total operating income		210,155		193,202		90,121		90,430		193,502		9,628
Earnings from unconsolidated investments		70,618		4,861		4,761		90		200		7
Other income (expense), net		571		359		89		5,692		7,210		64
EBIT	$	281,344	$	198,422	$	94,971	$	96,212	$	200,912	$	9,699

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, 2005 versus the year ended December 31, 2004. The $82.9 million EBIT improvement is 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 Energy 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 Panhandle Eastern Pipe Line, 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

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. Management estimates further revenue reductions of approximately $2 million will be experienced in 2006 as a result of the hurricanes, plus an estimated $8 million to $12 million in lost opportunity revenues from delayed LNG expansion in-service dates which were affected by the hurricanes and other technical issues;

·	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 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, LLC;

·	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 of benefit costs primarily due to headcount reductions and lower postretirement costs due to enactment of Medicare Part D reimbursements;

·	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.

Table of Contents

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 of damages directly associated with Hurricanes Katrina and Rita;

·	Higher depreciation and amortization of $5.2 million primarily due to 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 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, 2005 versus the same period in 2004 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 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. Commodity revenues are dependent upon a number of variable factors, including weather, storage levels and customer demand for firm, interruptible and parking services;

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 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.

Year ended June 30, 2004 versus the year ended June 30, 2003. The EBIT improvement of $191.2 million is due to Panhandle Energy operating results being realized for the full fiscal year ended June 30, 2004 versus only 19 days for the fiscal year ended June 30, 2003.

Distribution Segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through the Company’s three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company. The utility divisions’ 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 utility divisions’ operations are generally sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and net earnings 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 Segment.

Table of Contents

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

	Years Ended					Six Months Ended					Years Ended
	December 31,					December 31,					June 30,
				2004					2003
Distribution Segment	2005			(Unaudited)		2004			(Unaudited)		2004		2003
	(In thousands)

Net operating revenue (1)	$	411,547		$	402,505	$	170,420		$	163,288	$	395,373	$	394,760

Operating expense, excluding goodwill impairment		201,736			209,200		104,295			89,489		194,394		171,463
Depreciation and amortization		63,278			60,849		32,511			29,263		57,601		56,396
Goodwill impairment		175,000			-		-			-		-		-
Taxes other than on income and revenues		14,009			27,082		14,218			11,620		24,484		24,139
Total operating income (loss)		(42,476	)		105,374		19,396			32,916		118,894		142,762
Other income (expense), net		(1,452	)		804		(66	)		2,037		1,944		2,209
EBIT	$	(43,928	)	$	106,178	$	19,330		$	34,953	$	120,838	$	144,971

(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, 2005 versus the year ended December 31, 2004. EBIT for the Distribution segment improved by $24.9 million in 2005 compared with 2004 after excluding the effects of the $175 million goodwill impairment charge recorded in 2005. The EBIT improvement was primarily due to the following items:

·	Net operating revenues increased by approximately $9 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 $7.5 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 $3.3 million of lower bad debt expense primarily as a result of more aggressive collection efforts in 2005, partially offset by approximately $2.3 million of insurance costs primarily due to higher claims in 2005;

·	Depreciation and amortization were higher by approximately $2.5 million primarily due to normal growth in plant and the implementation of certain financial information systems in the first quarter of 2005; and

·	Taxes other than on income and revenues were approximately $13.1 million lower primarily due to property tax refunds for the years 2002 to 2004 received by Missour Gas Energy during 2005.

Six-month period ended December 31, 2004 versus the six-month period ended December 31, 2003. The $15.6 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:

·	Environmental site remediation costs were higher in the 2004 period by approximately $6.6 million primarily due to mercury remediation costs at New England Gas Company;

·	Bad debt expense increased $3.4 million resulting from the aging of higher customer receivables due to higher gas prices;

·	Outside service costs increased $2.5 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 $2.3 million in other net operating costs primarily due to general wage increases, increased overtime costs associated with distribution system maintenance and Sarbanes-Oxley related costs;

·	Higher depreciation and amortization expense principally related to a charge of $3.2 million taken in the 2004 period to write off certain capitalized software costs, in addition to normal plant growth;

·	Taxes other than on income and revenues, principally consisting of property, payroll and state franchise taxes, increased $2.6 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 $7.1 million in net operating revenue primarily due to increased sales volumes resulting from colder than normal weather in 2004 in the Company’s Pennsylvania and New England service territories and the positive impact of the $22.4 million annual increase to base revenues granted to Missouri Gas Energy by MPSC, effective October 2, 2004

Year ended June 30, 2004 versus the year ended June 30, 2003. The EBIT reduction of $24.1 million for the year ended June 30, 2004 compared with the year ended June 30, 2003 is primarily due to $1.2 million of higher depreciation and amortization in 2004 related to plant growth and an increase in operating expenses of $22.9 million, primarily due to the following items:

·	Pension and other postretirement benefit costs increased $8.9 million in the 2004 period primarily due to the impact of stock market volatility on plan assets;

·	Bad debt expense increased by $6.4 million in the 2004 period due to higher customer receivables resulting from increased gas prices; and

·	Increased medical and insurance premiums of $1.6 million and $1.5 million, respectively.

Corporate and Other

Except for revenue related to the Management Agreement associated with CCE Holdings, Corporate and Other consists of corporate operations that do not generate operating revenues and certain subsidiaries established to support and expand natural gas sales and other energy sales. For more information about the Management Agreement, see Item 1. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Other Matters - Management Agreement.

Year ended December 31, 2005 versus the year ended December 31, 2004. EBIT improved by $13.0 million in 2005 compared with 2004 primarily due to the following items:

·	Recognition of a $4.3 million management fee for services provided under the 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.

Table of Contents

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 $13.2 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.

Year ended June 30, 2004 versus the year ended June 30, 2003. EBIT decreased $16.9 million in the year ended June 30, 2004 compared with the year ended June 30, 2003 primarily due to the following items:

·	Gain of $22.5 million recorded in fiscal year 2003 on the settlement of the Southwest litigation, partially offset by $6 million of related legal costs; and

·	Charges of $3 million recorded by PEI Power Corporation in fiscal year 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.

Interest Expense

Year ended December 31, 2005 versus the year ended December 31, 2004. Interest expense was $9 million higher in 2005 compared with 2004 primarily because of 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.

Table of Contents

Year ended June 30, 2004 versus the year ended June 30, 2003. Interest expense increased by $44.5 million in the year ended June 30, 2004 compared with the year ended June 30, 2003 primarily because of the following items:

Interest expense of $47.6 million (net of $10.8 million of amortization of debt premiums established in purchase accounting related to the Panhandle Energy acquisition) on Panhandle Energy debt realized for the full fiscal year period versus $2.1 million applicable to the post-acquisition period of 19 days during fiscal year 2003 ; and

Dividends on preferred securities of the Company’s subsidiary trust of $3.2 million, which were required to be classified as interest expense pursuant to FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, upon adoption by the Company effective July 1, 2003.

These increases were partially offset by decreased interest expense of $4.4 million on the $311.1 million principal amount of the 2002 Term Note entered into by the Company on July 15, 2002. This decrease in the 2002 Term Note interest was due to reductions in LIBOR rates during 2004 and the principal repayment of $200 million of the 2002 Term Note since its inception.

Federal and State Income Taxes from Continuing Operations

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 77 percent and 39 percent, respectively. The fluctuation was primarily due to the significant impact of the $175 million goodwill impairment charge related to the Distribution segment as there was no tax basis in the goodwill and therefore no tax benefit associated with this charge. Additionally, the rate was impacted by the 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. The Company determined that this valuation allowance was no longer necessary because the book income from CCE Holdings was substantially greater than taxable income for 2005 and is expected to continue to be higher for the forseeable future.

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 for the six-month period ended December 31, 2004 versus the same period ended December 31, 2003 from 49 percent to 39 percent, respectively, 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 benefit of a dividends received deduction.

Year ended June 30, 2004 versus the year ended June 30, 2003. The effective federal and state income tax rate for years ended June 30, 2004 and 2003 was 38 percent and 36 percent, respectively. The increase in the effective federal and state income tax rate is primarily the result of the state income tax effect resulting from the operations of Panhandle Energy being included in the consolidated results of the Company for the entire fiscal year in 2004.

Disposition of PG Energy and Rhode Island Operations of New England Gas Company. For GAAP purposes, the Company expects to record an estimated $150 million of income tax expense with respect to the dispositions of the Pennsylvania and Rhode Island divisions that will be included in discontinued operations in 2006.

For income tax purposes, the Company expects to incur an estimated gain of $700 million on the sale of these two divisions in 2006. In order to minimize the current tax impact of this gain, the Company has structured these dispositions and the acquisition of the Sid Richardson Energy Services business in a manner intended to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986 (Section 1031 of the IRC). The like-kind exchange structure would allow the Company to defer a significant portion of the income tax that would otherwise be payable in 2006.

Table of Contents

Net Earnings from Discontinued Operations

Net earnings from discontinued operations for the year ended June 30, 2003 are related to the Company’s Southern Union Gas natural gas operating division and related assets sold to ONEOK on January 1, 2003. See Item 1. Business.

Preferred Stock Dividends

There is no change in dividends on preferred securities for the years ended December 31, 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 to the public on October 8, 2003. See Item 8. Financial Statements and Supplementary Data, Note 12 - Preferred Securities.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

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 Company has increased the scale of its natural gas transportation, storage and distribution operations and the size of its customer base by pursuing and consummating the Panhandle Energy and CCE Holdings acquisitions. Acquisitions generally require a substantial increase in expenditures that may need to be financed through cash flow from operations, dispositions of assets, future debt or equity offerings, or any combination thereof. 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 and 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 acquisition financing or refinancing 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.

Year ended December 31, 2005 versus the year ended December 31, 2004. Cash flows provided by operating activities were $218.6 million for the 12 months 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 $297.0 million for 2004. Changes in operating assets and liabilities used cash of $138.0 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.

Table of Contents

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.

Year ended June 30, 2004 versus the year ended June 30, 2003. Cash flows provided by operating activities were $327.2 million for the year ended June 30, 2004 compared with cash flows provided by operating activities of $56.1 million for the same period in 2003. Cash flows provided by operating activities before changes in operating assets and liabilities for 2004 were $306.5 million compared with $146.6 million for 2003. Changes in operating assets and liabilities provided cash of $20.7 million in 2004. Changes in operating assets and liabilities used cash of $90.6 million in 2003. The unusually high accounts receivable balance that occurred due to high gas costs during both 2004 and 2003, the normal delay in the recovery of deferred gas purchase costs due to the regulatory lag in passing along such changes in purchased gas costs to customers and funds expended for replenishing natural gas stored in inventory in greater volumes and at higher rates, impacted working capital in both 2004 and 2003.

Investing Activities

Summary

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

Table of Contents

Cash flow changes associated with these objectives resulted primarily from ongoing expansion of its existing asset base through additions to property, plant and equipment and the acquisition of an interest in CCE Holdings on November 17, 2004, for $605.4 million, the acquisition of Panhandle Energy on June 11, 2003, for $522.3 million, net of cash received, and the sales proceeds of $437 million from the sale of Southern Union Gas and other assets during 2003. The following table presents a summary of additions to property, plant and equipment additions by segment including additions related to major projects.

	Year		Six months		Year		Year
	Ended		Ended		Ended		Ended
	December 31,		December 31,		June 30,		June 30,
Property, Plant and Equipment Additions	2005		2004		2004		2003
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions	$	75,263	$	51,751	$	65,260	$	-
Trunkline LNG Loop		25,329		17,647		3,675		-
Pipeline Integrity		21,816		11,278		18,378		-
System Reliability		22,637		8,296		17,179		-
Information Technology		6,162		2,762		10,696		-
Other		38,208		20,152		16,190		5,128	(1)
Total		189,415		111,886		131,378		5,128

Distribution Segment
Missouri Safety Program		11,426		4,653		6,878		9,094
Other, primarily system replacement and expansion		73,470		51,789		71,913		58,233
Total		84,896		56,442		78,791		67,327

Corporate and other		2,306		10,109		15,884		7,275

Total (2)	$	276,617	$	178,437	$	226,053	$	79,730

(1) Represents Panhandle Energy's property, plant and equipment additions for the period from June 12 to June 30, 2003.
(2) Includes net capital accruals totaling $(3.1) million, $7.8 million, $12.1 million and $(248,000) for the year ended
December 31, 2005, six-month period ended December 31, 2004 and years ended June 30, 2004 and 2003, respectively.

Principal Capital Expenditure Projects

The following is a summary of the Company’s principal capital expenditure projects. For additional information related to the Company’s ongoing and planned expansion projects, see Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition - Business Strategy.

LNG Terminal Expansion. The Company estimates expenditures associated with the Phase I and Phase II LNG terminal expansions to be $32.1 million in 2006, plus capitalized interest.

Trunkline LNG Loop. The Company’s capital expenditures associated with the completed Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal were $46.7 million, plus capitalized interest.

Hurricane-Related Expenditures. Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast from the Gulf of Mexico. These hurricanes caused modest damage to property and equipment owned by Sea Robin, Trunkline and Trunkline LNG. Approximately $900,000 of capital outlays were recorded in 2005, with additional estimated capital outlays of approximately $20 million, prior to any insurance recoveries, expected to be incurred in 2006. Estimated capital outlays primarily include repair and replacement of equipment lost or damaged in the hurricanes, potential abandonment costs for certain facilities, which will be impacted by producer decisions regarding rebuilding their damaged platforms and reconnecting their gas reserves to Panhandle Energy’s pipelines and higher LNG terminal construction costs.

Table of Contents

Panhandle Eastern Pipe Line East End Enhancement. The Company has planned certain enhancements to the east end of the Panhandle Eastern Pipe Line system with estimated capital outlays of $70 million and $27 million, plus capitalized interest, in 2006 and 2007, respectively.

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 estimates incurring capital expenditures of $10.5 million in 2006 related to this program and approximately $134.3 million over the remaining life of the program of 14 years.

Financing Activities

Summary

In conjunction with financing activities, the Company continues to pursue opportunities to enhance its credit profile by reducing its ratio of total debt to total capital, which at December 31, 2005 was 58 percent compared to 66 percent at December 31, 2004. This reduction in the ratio of total debt to total capital resulted from equity transactions used to reduce debt during 2005. The issuance of common stock, equity units and preferred stock and use of proceeds 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. Standard & Poor’s and Moody’s Investor Services, Inc. view hybrid securities such as the equity units as a combination of debt and equity due to the mandatory exercise of the forward purchase contract for equity at a fixed date in the future. Because of the partial equity credit that is received, the equity units are viewed more favorably than debt financing. The Company’s effective debt cost rate under its December 31, 2005 debt structure is 4.96 percent (which includes interest and the amortization of debt issuance costs and redemption premiums on refinanced debt) compared to 4.69 percent at December 31, 2004.

On March 1, 2006, in connection with its purchase of Sid Richardson Energy Services, Ltd. and related entities, the Company and ESSI entered into the $1.6 billion Sid Richardson Bridge Loan in order to provide temporary financing. The Sid Richardson Bridge Loan will be repaid primarily with the proceeds from the sales of the PG Energy division and the Rhode Island operations of the New England Gas Company division, with the balance being repaid through the issuance of debt and/or equity securities. The Company expects that the bridge loan will be repaid in its entirety before the end of 2006 and intends to structure any permanent financing to help maintain its investment grade rating. The Sid Richardson Bridge Loan is secured by the acquired assets of Sid Richardson Energy Services, Ltd. and related entities and a pledge of the Company’s ownership interest in Panhandle Eastern Pipe Line.

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.

Cash flow used in financing activities was $179.2 million for the year ended June 30, 2004 compared to cash flow provided by financing activities of $222.5 million for the same period in 2003. Financing activity cash flow changes were primarily due to the net impact of acquisition financing, repayment and issuance of debt, net activity under the revolving credit facilities, issuance of preferred stock and the redemption of preferred securities of the Company’s subsidiary trust.

Table of Contents

Common Stock, Equity Units and Preferred Stock 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, 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 Transaction Bridge Loan) and to repay borrowings under its credit facilities. Each 5% Equity Unit consists of a 1/20th interest in a $1,000.00 principal amount of Southern Union’s 4.375 percent 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).

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 and other transaction related costs, of $332.6 million. Southern Union used the net proceeds to repay a portion of the CCE Holdings Transaction 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 9.2 million 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.

On June 11, 2003, the Company issued 9,500,000 shares of common stock at the public offering price of $16.00 per share. After underwriting discounts and commissions, the Company realized net proceeds of $146.7 million. The Company granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,425,000 shares of the Company’s common stock at the same price, which was exercised on June 11, 2003, resulting in additional net proceeds to the Company of $22 million. The total net proceeds were used to pay for a portion of the acquisition of Panhandle Energy and to repay borrowings under the short-term credit agreements.

Also on June 11, 2003, the Company issued 2,500,000 equity units at a public offering price of $50 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $121.3 million. Each 5.75% Equity Unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due August 16, 2006, issued pursuant to the Company’s existing indenture. The 5.75% Equity Units carry a total annual coupon of 5.75 percent (2.75 percent annual face amount of the senior notes plus 3.0 percent annual contract adjustment payments). Each stock purchase contract issued as a part of the 5.75% Equity Units carries a maximum conversion premium of up to 22 percent over the $16.00 issuance price (before adjustment for subsequent stock dividends) of the Company’s common shares that were sold on June 11, 2003, as discussed previously. The proceeds were used to pay for a portion of the acquisition of Panhandle Energy and to repay borrowings under the short term credit agreements.

Table of Contents

Debt Refinancing, Repayment and Issuance Activity

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, letter of credit requirements and other general corporate purposes. The Company has additional availability under uncommitted lines of credit facilities (Uncommitted Facilities) with various banks. 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, 2005, the commitment fees were an annualized 0.11 percent.

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 for an initial period of six months at a rate of 4.54 percent, which is based upon six-month LIBOR plus 70 basis points.

Trunkline LNG Holdings, LLC (LNG Holdings) as borrower, and Panhandle Eastern Pipe Line and Trunkline LNG, as guarantors, entered into a Credit Agreement on April 26, 2005, 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 Energy’s option, in addition to a margin which is tied to the rating of Panhandle Energy’s unsecured senior funded debt. On April 29, 2005, the proceeds from the Credit Agreement 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 a $407 million Bridge Loan Agreement 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 Energy 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 Energy’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 Energy 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 Energy 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 Energy 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 Energy 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 Energy repurchased $3.2 million 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.

On July 15, 2002, the Company issued a $311.1 million term note, the proceeds of which were used to repay the remaining balance of debt issued in conjunction with the purchase of the New England operations and borrowings under its revolving credit facilities. The term note required semi-annual principal payments through August 2005 and has been repaid.

Table of Contents

Debt Maturities 2006 and Other Debt Matters

The Company has a scheduled debt maturity of $125 million on August 16, 2006, due to the initial maturity of the 2.75% Senior Notes that were issued in connection with the sale of $125 million of its 5.75% Equity Units by the Company on June 11, 2003. The Company is currently evaluating various options with respect to this obligation, and it does not anticipate any material impact on its liquidity or financial condition from this upcoming event.

Balances of $420 million and $292 million were outstanding under the Company’s credit facilities at effective interest rates of 4.73 percent and 3.20 percent at December 31, 2005 and December 31, 2004, respectively. As of March 3, 2006, there was a balance of $388 million outstanding under the Company’s credit facilities at an average effective interest rate of 5.28 percent.

The Company has a currently effective shelf registration statement on file with the SEC for a total principal amount of $1 billion in securities of which $219.8 million in securities is available for issuance as of March 3, 2006.

The Company’s ability to arrange financing, including refinancing, and its cost of capital are dependent on various factors and conditions, including: general economic and capital market conditions; maintenance of acceptable credit ratings; credit availability from banks and other financial institutions; investor confidence in the Company, its competitors and peer companies in the energy industry; market expectations regarding the Company’s future earnings and probable cash flows; market perceptions of the Company’s ability to access capital markets on reasonable terms; and provisions of relevant tax and securities laws.

On July 3, 2003, Moody’s Investor Services, Inc. changed its credit rating on the Company’s senior unsecured debt to Baa3 with a negative outlook from Baa3 with a stable outlook. The Company’s senior unsecured debt is currently rated BBB by Standard & Poor’s, a rating that it has held since March 2003 when it was downgraded from BBB+. Standard & Poor’s changed its outlook from stable to negative on March 12, 2004. Although no further downgrades are anticipated, such an event would not be expected to have a material impact on the Company. The Company is not party to any lending agreements that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit ratings.

Standard & Poor’s placed the Company on Credit Watch on December 16, 2005, in connection with the announcement of the acquisition of the Sid Richardson Energy Services business. On February 16, 2006, Standard & Poor’s affirmed the Company’s BBB rating, but retained the negative outlook. 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 February 23, 2006, Moody’s Investor Services, Inc. confirmed 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 Sid Richardson Services business. On February 24, 2006, Fitch Ratings, Inc. affirmed the Company’s BBB rating and retained the stable outlook.

The Company had standby letters of credit outstanding of $8.0 million at December 31, 2005, $8.6 million at December 31, 2004, $58.6 million at June 30, 2004 and $7.8 million at June 30, 2003, which guarantees payment of insurance claims and various other commitments.

As of December 31, 2005, Panhandle Energy’s debt was rated BBB by Fitch Ratings, Inc. and Standard & Poor’s and Baa3 by Moody’s Investor Services, Inc. The instruments governing Panhandle Energy’s rated debt require it to maintain a specified fixed charge coverage ratio and leverage ratio and restrict Panhandle Energy’s ability to make certain payments if these ratios are not maintained. The governing instruments also limit the ability of Panhandle Energy to subject its properties to certain liens. At December 31, 2005, as a result of these covenants, Panhandle Energy was subject to a $495.7 million limitation on additional restricted payments, including dividends and loans to affiliates, and a limitation of $232.6 million of additional secured and subsidiary level indebtedness. Panhandle Energy is also subject to a limitation of $401.6 million of total additional indebtedness. If Panhandle Energy’s debt ratings by Moody’s Investor Services, Inc. were to fall below Baa3, or if its debt ratings by Standard and Poor’s were to fall below BBB-, then the allowable restricted payments would be reduced to $445.6 million. At December 31, 2005, Panhandle Energy was in compliance with all covenants in the instruments governing its rated debt.

Table of Contents

OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

As of December 31, 2005, the Company had guarantees related to PEI Power Corporation of $7.2 million, letters of credit related to insurance claims and other commitments of $8.0 million and surety bonds related to construction or repair projects of approximately $3.9 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.

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2005:

	Contractual Obligations (In thousands)
													2011 and
	Total		2006		2007		2008		2009		2010		thereafter
Long-term debt,
including capital leases (1) (2)	$	2,169,238	$	126,648	$	457,274	$	401,646	$	61,998	$	41,875	$	1,079,797
Short-term borrowing,
including credit facilities (1)		420,000		420,000		-		-		-		-		-
Gas purchases (3)		1,778,806		602,564		444,262		283,041		239,058		185,913		23,968
Missouri Gas Energy Safety Program		144,801		10,453		9,729		9,826		9,924		10,024		94,845
Transportation contracts		398,014		67,629		66,368		66,368		62,504		48,395		86,750
Storage contracts (4)		348,365		65,122		63,330		53,937		48,574		45,674		71,728
LNG terminal expansion		32,091		32,091		-		-		-		-		-
Operating lease payments		107,237		21,676		19,524		14,472		11,604		10,822		29,139
Interest payments on debt		1,739,444		139,596		116,150		104,969		94,096		89,406		1,195,227
Benefit plan contributions		32,575		32,575		-		-		-		-		-
Non-trading derivative liabilities		5,725		3,244		2,481		-		-		-		-
Total contractual cash obligations	$	7,176,296	$	1,521,598	$	1,179,118	$	934,259	$	527,758	$	432,109	$	2,581,454

____________________________

(1)

The Company is party to certain debt agreements containing certain covenants that if not satisfied would be 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 and Capital Leases.

(2)	The long-term debt cash obligations exclude $12.2 million of unamortized debt premium as of December 31, 2005.

(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)	Charges for third party storage capacity.

Management Agreement

On November 5, 2004, SU Pipeline Management LP (Manager), a wholly-owned subsidiary of Southern Union, and Panhandle Energy entered into an Administrative Services Agreement (Management Agreement) with CCE Holdings. Pursuant to the Management Agreement, Manager will provide administrative services to CCE Holdings and its subsidiaries. Manager will be responsible for all administrative and ministerial services not reserved to the executive committee or members of CCE Holdings. For performing these functions, CCE Holdings will reimburse Manager for certain defined operating and transition costs, and under certain circumstances may pay Manager an annual management fee. Transition costs are non-recurring costs of establishing the shared services, including but not limited to severance costs, professional fees, certain transaction costs and the costs of relocating offices and personnel, pursuant to the Management Agreement. Management fees are to be calculated based on a percentage of the amount by which certain earnings targets, as previously determined by the executive committee, are exceeded. Accrued management fees for 2005 totaled $4.3 million. No management fees were due under the Management Agreement for the period prior to 2005.

Table of Contents

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 increasing cost of providing service and the inherent regulatory lag in adjusting those rates.

Regulatory

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

Benefit Plan Changes

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

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

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.

Table of Contents

Effects of Regulation

The Company is subject to regulation by certain state and federal authorities in both its Distribution and Transportation and Storage segments. Missouri Gas, PG Energy, New England Gas Company, Transwestern and Florida Gas have accounting policies which conform to the FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, and which 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 income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement 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 and liabilities reflected in the Consolidated Balance Sheets applicable to the Distribution segment are $113.0 million and $10.1 million at December 31, 2005 and $103.0 million and $10.9 million at December 31, 2004, respectively. For a summary of regulatory matters applicable to the Company, see Item 8. Financial Statements and Supplementary Data, Note 16 - Regulation and Rates.

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.

As of May 31, 2005 and November 30, 2005, 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 December 31, 2005 and December 31, 2004, no impairment was indicated based on FASB Statement No. 142, Goodwill and Other Intangible Assets. Considering the prices included in the definitive agreements in the first quarter of 2006 to sell the Company’s PG Energy division and the Rhode Island operations of its New England Gas Company division, the Company determined that there was a goodwill impairment. Execution of the sale agreements constituted a subsequent event of the type that under GAAP required the Company to consider the fair value indicated by the definitive sale agreements in its 2005 goodwill impairment evaluation.

Table of Contents

Pensions and Other Postretirement Benefits

The Company follows FASB Statement No. 87, Employers’ Accounting for Pensions and FASB Statement No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions to account for pension costs and other postretirement benefit costs, respectively. These statements require liabilities to be recorded on the balance sheet at the present value of these future obligations to employees net of any plan assets. The calculation of these liabilities and associated expenses require the expertise of actuaries and are subject to many assumptions including life expectancies, present value discount rates, expected long-term rate of return on plan assets, rate of compensation increase and anticipated health care costs. Any change in these assumptions can significantly change the liability and associated expenses recognized in any given year. However, the Company expects to recover substantially all of its net periodic pension and other postretirement benefit costs attributable to employees in its Distribution segment in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and postretirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. See Item 8. Financial Statements and Supplementary Data, Note 14 - Employee Benefits.

Derivatives and Hedging Activities

The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, to account for derivative and hedging activities. 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 either: (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 debt. 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 other comprehensive income until the related hedge 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.

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.

Table of Contents

Purchase Accounting

The Company’s acquisition of Panhandle Energy 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 owns a 50 percent equity interest, 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 Energy and CCE Holdings were finalized in 2004 and 2005, respectively.

New Accounting Pronouncements

The Company adopted FASB Statement 123R, Share-Based Payment, 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. Based upon unexercised stock option balances outstanding at December 31, 2005, the Company estimates additional compensation expense resulting from the implementation of this statement will be $3 million for 2006, $1.8 million for each of 2007 and 2008, $900,000 for 2009 and $148,000 for 2010. The Company did not make any amendments to its existing stock option arrangements as a result of considering the statement’s adoption. Upon the Company’s adoption of the statement, 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 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.

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, 2005, the Company had issued fixed-rate long-term debt aggregating $1.72 billion in principal amount (excluding premiums on Panhandle Energy’s debt of $12.2 million) and having a fair value of $1.85 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 $76.4 million if interest rates were to decline by ten percent from their levels at December 31, 2005. 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.

In connection with its agreement to acquire the Sid Richardson Energy Services business (now doing business as Southern Union Gas Services), the Company purchased put options on the price of natural gas in December 2005. These options were tied to the WAHA price of natural gas for the periods March 2006 through December 2006 (2006 Put Options) and January 2007 through December 2007 (2007 Put Options). The 2006 Put Options relate to 45,000 MMBtu/day at the price of $11.00 per MMBtu, which equals an estimated 85 percent of natural gas volumes to be processed and retained by Southern Union Gas Services. The 2007 Put Options relate to 25,000 MMBtu/day at the price of $10.00 per MMBtu, which equals an estimated 50 percent of natural gas volumes to be processed and retained by Southern Union Gas Services. The goal of the purchase of the 2006 and 2007 Put Options was to reduce the downside commodity price risk of the Southern Union Gas Services business. The Company believes that natural gas is the appropriate commodity to hedge due to the contract and asset structure of Southern Union Gas Services. Prior to the March 1, 2006 closing of the Sid Richardson Energy Services acquisition, the 2006 and 2007 Put Options were accounted for using mark-to-market accounting. The impact on the Company’s 2005 results of operations was a gain of $1.8 million due to the general decline of natural gas prices subsequent to the purchase of the 2006 and 2007 Put Options. At December 31, 2005, the Company reported the fair market value of the put options in the Consolidated Balance Sheet as $32.4 million in Prepayments and other current assets and $19.1 million in Deferred charges. After the closing of the acquisition on March 1, 2006, the 2006 and 2007 Put Options were designated as “hedges” and are being accounted for in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The Company paid a total of $49.7 million to purchase the 2006 and 2007 Put Options, which will be marked to fair market value at each period end.

Table of Contents

The Company's floating-rate obligations aggregated $875.6 million at December 31, 2005 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, 2005 levels, the Company's consolidated interest expense would increase by a total of approximately $345,000 each month in 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 FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, 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, 2005 is not material to the Company.

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

In connection with the acquisition of PG Energy, 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 (together the Taxing Authorities) approved a Tax Incremental Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan requires that:

·	the Redevelopment Authority of Lackawanna County raise $10.6 million of funds to be used for infrastructure improvements of PEI Power Park;

·	the Taxing Authorities create a tax increment district and use the incremental tax revenues generated from new development to service the $10.6 million debt; and

·	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 of one 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, 2005, the balance outstanding on the TIF debt was $7.2 million with an interest rate of 6.5 percent. Estimated incremental tax revenues are expected to cover approximately 65 percent of the 2006 annual debt service. Based on information available at this time, the Company believes that the $4.0 million amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2005.

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 and Capital Leases). 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. As of December 31, 2004, the fair value liability position of the swaps was $11.1 million.

The Company was also party to an interest rate swap agreement with a notional amount of $8.2 million at June 30, 2003 that fixed the interest rate applicable to floating rate long-term debt and which qualified for hedge accounting. The fair value liability position of the swap was $93,000 at June 30, 2003. In October 2003, the swap expired and $15,000 of unrealized after-tax losses included in Accumulated other comprehensive loss relating to this swap was reclassified to interest expense during the quarter ended December 31, 2003.

Table of Contents

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, 2005, approximately $967,000 of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next 12 months.

In March 2004, Panhandle Energy entered into interest rate swaps to hedge the risk associated with the fair value of its $200 million 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under the swap agreements, Panhandle Energy 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, 2005 and December 31, 2004, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $5.7 million and $3.9 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.

During 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. 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 value of the contracts is recorded as an adjustment to a regulatory asset/liability in the Consolidated Balance Sheet. As of December 31, 2005 and December 31, 2004, the fair values of the contracts, which expire at various times through October 2006, are included in the Consolidated Balance Sheet as assets and matching adjustments to deferred cost of gas of $17.5 million and $2.6 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 that evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2005.

Table of Contents

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 transactions 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 our internal control over financial reporting.

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

Management evaluated the effectiveness of the Company’s internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our 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, 2005.

Management's assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report included herein.

Southern Union Company

March 16, 2006

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, 2005 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, 2005 was appropriately reported.

Table of Contents

PART III

ITEM 10. Directors and Executive Officers of the Registrant.

There is incorporated in this Item 10 by reference the information that will appear in the Company’s definitive proxy statement for the 2006 Annual Meeting of Stockholders under the captions Board of Directors - Board Size and Composition, Board of Directors - Board Committees and Meetings - Audit Committee and - Corporate Governance Committee and Board of Directors - Corporate Governance Guidelines and Code of Ethics, Report of the Audit Committee, and Executive Officers and Compensation - Executive Officers Who Are Not Directors, - Executive Compensation and - Section 16(a) Beneficial Ownership Reporting Compliance.

The Company has adopted a Code of Ethics that applies to its Chief Executive Officer, Chief Financial Officer, Controller and other individuals in the finance department performing similar functions. The Code of Ethics is available on the Company’s Web site 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 Chief Executive Officer, Chief Financial Officer or other authorized officer will disclose the nature of such amendment or waiver on the Web site 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 June 7, 2005.

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 2006 Annual Meeting of Stockholders under the captions Executive Officers and Compensation - Executive Compensation and Certain Relationships.

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 2006 Annual Meeting of Stockholders under the captions Executive Officers and Compensation - Information Regarding Plans and Other Arrangements Not Subject to Stockholder Approval and - Equity Compensation Plans and Security Ownership.

ITEM 13. Certain Relationships and Related Transactions.

There is incorporated in this Item 13 by reference the information that will appear in the Company’s definitive proxy statement for the 2006 Annual Meeting of Stockholders under the caption Certain Relationships.

ITEM 14. Principal Accountant Fees and Services.

There is incorporated in this Item 14 by reference the information that will appear in the Company’s definitive proxy statement for the 2006 Annual Meeting of Stockholders under the caption Independent Auditors.

Table of Contents

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.

(a)(1) and (2) Financial Statements and Financial Statement Schedules.

(a)(3) Exhibits.

Exhibit No. Description

2(a) Amended and Restated Stock Purchase Agreement by and among CMS Gas Transmission Company, Southern Union Company and Southern Union Panhandle Corporation dated as of May 12, 2003. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on May 27, 2003 and incorporated herein by reference.)

2(b) 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(c) 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(d) 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(e) 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.)

2(f) Purchase and Sale Agreement between Southern Union Company and ONEOK, Inc. dated as of October 16, 2002. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on October 10, 2002 and incorporated herein by reference.)

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

3(a) Amended and Restated Certificate of Incorporation of Southern Union Company

Table of Contents

3(b) By-Laws of Southern Union Company as amended through May 9, 2005.

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.)

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(p) First Mortgage Bonds Indenture of Mortgage and Deed of Trust dated as of March 15, 1946 by Southern Union Company (as successor to PG Energy, Inc. formerly, Pennsylvania Gas and Water Company, and originally, Scranton-Spring Brook Water Service Company to Guaranty Trust Company of New York. (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(q) Twenty-Third Supplemental Indenture dated as of August 15, 1989 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and Morgan Guaranty Trust Company of New York (formerly Guaranty Trust Company of New York). (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(r) Twenty-Sixth Supplemental Indenture dated as of December 1, 1992 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and Morgan Guaranty Trust Company of New York. (Filed as Exhibit 4.3 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(s) Thirtieth Supplemental Indenture dated as of December 1, 1995 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and First Trust of New York, National Association (as successor trustee to Morgan Guaranty Trust Company of New York). (Filed as Exhibit 4.4 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(t) Thirty-First Supplemental Indenture dated as of November 4, 1999 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and U. S. Bank Trust, National Association (formerly, First Trust of New York, National Association). (Filed as Exhibit 4.5 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

Table of Contents

4(u) Pennsylvania Gas and Water Company Bond Purchase Agreement dated September 1, 1989. (Filed as Exhibit 4.6 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(v) 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) Bridge Loan Agreement by and between Southern Union Company and Enhanced Service Systems, as borrowers, and the Banks listed therein dated as of March 1, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

10(b) 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(c) 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(d) Change of Control Agreement between the Company and Julie H. Edwards, effective July 5, 2005. (Filed as Exhibit 10.2 to Southern Union's Current Report on Form 8-K filed on July 5, 2005 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(g) Employment agreement between Thomas F. Karam and Southern Union Company dated December 28, 1999. (Filed as Exhibit 10(a) to Southern Union's Quarterly Report on Form 10-Q for the quarter ended December 31, 1999 and incorporated herein by reference.)

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

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

Table of Contents

10(k) 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(l) 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(m) Amended and Restated Southern Union Company 2003 Stock and Incentive Plan.

10(n) Amended and Restated Limited Liability Company Agreement of CCE Holdings, LLC between EFS-PA, LLC and CCE Acquisition, LLC, dated November 5, 2004. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 10, 2004 and incorporated herein by reference.)

10(o) Administrative Service Agreement between CCE Holdings, LLC and SU Pipeline Management LP, dated November 5, 2004. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on November 10, 2004 and incorporated herein by reference.)

Code of Ethics and Business Conduct.

Independent Registered Public Accounting Firm Preferability Letter

Subsidiaries of the Registrant.

Consent of Independent Registered Public Accounting Firm.

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.

Table of Contents

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 16, 2006.

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 16, 2006.

Signature/Name Title

/s/ GEORGE L. LINDEMANN* George L. Lindemann	Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
/s/ Julie H. Edwards Julie H. Edwards	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ George E. Aldrich George E. Aldrich	Vice President and Controller (Chief Accounting Officer)
/s/ David Brodsky * David Brodsky	Director
/s/ Frank W. Denius* Frank W. Denius	Director
/s/ Kurt A. Gitter, M.D.* Kurt A. Gitter, M.D.	Director

/s/ Herbert H. Jacobi* Herbert H. Jacobi	Director

/s/ Adam M. Lindemann * Adam M. Lindemann	Director

/s/ Thomas N. McCarter, III * Thomas N. McCarter, III	Director

/s/ George Rountree, III* George Rountree, III	Director

/s/ Allan D. Scherer* Allan Scherer	Director

*By: /s/ JULIE H. EDWARDS Julie H. Edwards Senior Vice President and Chief Financial Officer Attorney-in-fact	*By: /s/ ROBERT M. KERRIGAN, III Robert M. Kerrigan, III Vice President, Assistant General Counsel and Secretary Attorney-in-fact

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:	Page(s):
Consolidated Statement of Operations - year ended December 31, 2005, six months ended
December 31, 2004 and years ended June 30, 2004 and 2003	F-2
Consolidated Balance Sheet - December 31, 2005 and December 31, 2004	F-3 - F-4
Consolidated Statement of Cash Flows - year ended December 31, 2005, six months ended
December 31, 2004 and years ended June 30, 2004 and 2003	F-5
Consolidated Statement of Stockholders’ Equity and Comprehensive Income -
year ended December 31, 2005, six months ended December 31, 2004 and years ended
June 30, 2004 and 2003	F-6 - F-7
Notes to Consolidated Financial Statements	F-8
Report of Independent Registered Public Accounting Firm	F-64

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

	Year Ended			Six Months Ended			Year Ended			Year Ended
	December 31,			December 31,			June 30,			June 30,
	2005			2004			2004			2003
	(In thousands of dollars, except shares and per share amounts)
Operating revenues:
Gas distribution	$	1,503,272		$	549,346		$	1,304,405		$	1,158,964
Gas transportation and storage		505,233			242,743			490,883			24,522
Other		10,925			2,249			4,486			5,014
Total operating revenues		2,019,430			794,338			1,799,774			1,188,500

Operating expenses:
Cost of gas and other energy		1,040,956			361,256			864,438			724,611
Revenue-related taxes		51,857			18,037			45,395			40,485
Operating, maintenance and general		417,663			217,967			411,811			193,745
Depreciation and amortization		126,393			63,376			118,755			60,642
Goodwill impairment (Note 7)		175,000			-			-			-
Taxes, other than on income and revenues		44,517			26,771			54,048			26,653
Total operating expenses		1,856,386			687,407			1,494,447			1,046,136
Operating income		163,044			106,931			305,327			142,364

Other income (expenses):
Interest		(135,157	)		(64,898	)		(127,867	)		(83,343	)
Earnings from unconsolidated investments		70,742			4,745			200			422
Dividends on preferred securities of subsidiary trust		-			-			-			(9,480	)
Other, net (Note 4)		(7,069	)		(18,080	)		5,468			17,979
Total other expenses, net		(71,484	)		(78,233	)		(122,199	)		(74,422	)

Earnings from continuing operations before income taxes		91,560			28,698			183,128			67,942

Federal and state income taxes		70,877			13,927			69,103			24,273

Net earnings from continuing operations		20,683			14,771			114,025			43,669

Discontinued operations (Note 19):
Earnings from discontinued operations before
income taxes		-			-			-			84,773
Federal and state income taxes		-			-			-			52,253
Net earnings from discontinued operations		-			-			-			32,520

Net earnings		20,683			14,771			114,025			76,189

Preferred stock dividends		(17,365	)		(8,683	)		(12,686	)		-

Net earnings available for common stockholders	$	3,318		$	6,088		$	101,339		$	76,189

Net earnings available for common stockholders from
continuing operations per share (Note 5):
Basic	$	0.03		$	0.07		$	1.26		$	0.67
Diluted	$	0.03		$	0.07		$	1.24		$	0.66

Net earnings available for common stockholders per
share (Note 5):
Basic	$	0.03		$	0.07		$	1.26		$	1.17
Diluted	$	0.03		$	0.07		$	1.24		$	1.15

Weighted average shares outstanding (Note 5):
Basic		109,395,418			87,313,787			80,431,988			64,949,776
Diluted		112,794,210			89,717,427			81,479,503			66,025,488

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

F-2

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

ASSETS

	December 31,			December 31,
	2005			2004
	(In thousands of dollars)
Property, plant and equipment (Note 6):
Plant in service	$	4,183,280		$	3,869,221
Construction work in progress		184,423			237,283
		4,367,703			4,106,504
Less accumulated depreciation and amortization		(881,763	)		(778,876	)
Net property, plant and equipment		3,485,940			3,327,628

Current assets:
Cash and cash equivalents		16,938			30,053
Accounts receivable, billed and unbilled,
net of allowances of $15,893 and $15,424, respectively		428,735			322,888
Accounts receivable – affiliates		8,827			10,604
Inventories		295,658			267,136
Gas imbalances - receivable		105,233			36,122
Prepayments and other assets		68,382			45,705
Total current assets		923,773			712,508

Goodwill (Note 7)		465,547			640,547

Deferred charges:
Regulatory assets (Note 8)		112,963			102,955
Deferred charges		113,793			96,109
Total deferred charges		226,756			199,064

Unconsolidated investments (Note 9)		682,834			631,893

Other		51,969			56,649


Total assets	$	5,836,819		$	5,568,289

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

F-3

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,			December 31,
	2005			2004
	(In thousands of dollars)
Stockholders’ equity (Note 10):
Common stock, $1 par value; authorized 200,000,000 shares;
issued 112,529,872 shares at December 31, 2005	$	112,530		$	90,763
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares at December 31, 2005 (Note 12)		230,000			230,000
Premium on capital stock		1,681,167			1,204,590
Less treasury stock: 1,053,879 and 404,536
shares, respectively, at cost		(27,566	)		(12,870	)
Less common stock held in trust: 1,216,221
and 1,033,150 shares, respectively		(12,910	)		(17,980	)
Deferred compensation plans		10,173			14,128
Accumulated other comprehensive loss		(56,272	)		(59,118	)
Retained earnings (deficit)		(83,053	)		48,044
Total stockholders' equity		1,854,069			1,497,557

Long-term debt and capital lease obligation (Note 13)		2,049,141			2,070,353

Total capitalization		3,903,210			3,567,910

Current liabilities:
Long-term debt and capital lease obligation
due within one year (Note 13)		126,648			89,650
Notes payable		420,000			699,000
Accounts payable and accrued liabilities		206,504			183,018
Federal, state and local taxes payable		47,195			33,946
Accrued interest		40,688			36,934
Customer deposits		16,096			13,156
Deferred gas purchases		83,147			3,709
Gas imbalances - payable		124,297			102,567
Other		158,555			151,856
Total current liabilities		1,223,130			1,313,836

Deferred credits:
Regulatory liabilities (Note 8)		10,070			10,885
Deferred credits		303,919			310,164
Total deferred credits		313,989			321,049

Accumulated deferred income taxes (Note 15)		396,490			365,494

Commitments and contingencies (Note 18)

Total stockholders' equity and liabilities	$	5,836,819		$	5,568,289

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

F-4

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

	Year Ended			Six Months Ended			Year Ended			Year Ended
	December 31,			December 31,			June 30,			June 30,
	2005			2004			2004			2003
	(In thousands of dollars)
Cash flows provided by (used in) operating activities:
Net earnings	$	20,683		$	14,771		$	114,025		$	76,189
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		126,393			63,376			118,755			60,642
Goodwill impairment		175,000			-			-			-
Amortization of debt premium		(2,484	)		(1,510	)		(14,243	)		(1,307	)
Deferred income taxes		61,211			12,082			67,455			78,747
Provision for bad debts		22,519			11,649			21,216			17,873
Provision for impairment of other assets		2,338			16,425			1,603			-
Amortization of debt expense		4,670			1,064			4,143			2,919
Gain on sale of subsidiaries and other assets		-			-			-			(62,992	)
Loss on sale of subsidiaries		-			-			1,150			-
Gain on extinguishment of debt		-			-			(6,354	)		-
Non-cash stock compensation		3,848			-			-			-
Net cash used by assets held for sale		-			-			-			(23,698	)
Earnings from unconsolidated investments, net of cash distributions		(55,742	)		(4,745	)		(200	)		(422	)
Other		(1,821	)		(1,197	)		(1,075	)		(1,312	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable, billed and unbilled		(126,590	)		(174,716	)		(6,181	)		(48,520	)
Gas imbalance receivable		736			(5,241	)		863			-
Accounts payable		43,681			45,511			(4,421	)		23,113
Gas imbalance payable		(465	)		2,307			1,655			154
Customer deposits		2,940			1,113			(542	)		5,013
Deferred gas purchase costs		59,385			10,239			20,670			(21,006	)
Inventories		(52,420	)		(47,474	)		(9,279	)		(23,556	)
Deferred charges and credits		(26,849	)		22,743			13,773			(12,561	)
Prepaids and other assets		(41,992	)		(11,974	)		8,978			2,541
Taxes and other liabilities		3,596			18,323			(4,831	)		(15,736	)
Net cash flows provided by (used) in operating activities		218,637			(27,254	)		327,160			56,081
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(279,721	)		(170,644	)		(213,983	)		(79,978	)
Acquisition of equity interest in unconsolidated investment		-			(605,388	)		-			-
Acquisitions of operations, net of cash received		-			-			-			(522,316	)
Notes receivable		-			-			(2,000	)		(6,750	)
Proceeds from sale of subsidiaries and other assets		-			-			2,175			437,000
Net cash used by assets held for sale		-			-			-			(13,410	)
Other		(2,808	)		(1,711	)		(1,131	)		(6,154	)
Net cash flows used in investing activities		(282,529	)		(777,743	)		(214,939	)		(191,608	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in bank overdraft		(17,091	)		7,405			1,820			(137	)
Issuance of long-term debt		255,626			-			750,000			311,087
Issuance costs of debt		(914	)		(337	)		(8,530	)		(313	)
Issuance of preferred stock		-			-			230,000			-
Issuance costs of preferred stock		-			-			(6,590	)		-
Issuance of common stock		331,772			228,287			-			168,682
Issuance of equity units		100,000			-			-			125,000
Issuance cost of equity units		(2,622	)		-			-			(3,443	)
Purchase of treasury stock		(15,032	)		-			(2,403	)		(2,181	)
Dividends paid on preferred stock		(17,365	)		(8,683	)		(8,393	)		-
Repayment of debt and capital lease obligation		(335,567	)		(94,123	)		(908,773	)		(500,135	)
Net (payments) borrowings under revolving credit facilities		(279,000	)		678,000			(230,500	)		119,700
Proceeds from exercise of stock options		22,242			4,530			4,122			3,047
Other		8,728			-			-			1,217
Net cash flows provided by (used in) financing activities		50,777			815,079			(179,247	)		222,524
Change in cash and cash equivalents		(13,115	)		10,082			(67,026	)		86,997
Cash and cash equivalents at beginning of period		30,053			19,971			86,997			-
Cash and cash equivalents at end of period	$	16,938		$	30,053		$	19,971		$	86,997


Cash paid for interest, net of amounts capitalized	$	139,770		$	69,954		$	143,715		$	90,462
Cash paid for income taxes, net of refunds		(2,007	)		7,764			(10,875	)		2,351

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

F-5

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

	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 of dollars)

Balance July 1, 2002	$	58,055	$	-	$	707,912		$	(57,673	)	$	(17,821	)	$	9,373		$	(14,500	)	$	-		$	685,346

Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			76,189			76,189
Unrealized loss in investment
securities, net of tax benefit		-		-		-			-			-			-			(581	)		-			(581	)
Minimum pension liability
adjustment, net of tax benefit		-		-		-			-			-			-			(41,930	)		-			(41,930	)
Unrealized loss on hedging
activities, net of tax benefit		-		-		-			-			-			-			(5,568	)		-			(5,568	)
Comprehensive income																								28,110
Payment on note receivable		-		-		305			-			-			-			-			-			305
Purchase of treasury stock		-		-		-			(2,181	)		-			-			-			-			(2,181	)
5% stock dividend		3,468		-		55,832			-			-			-			-			(59,333	)		(33	)
Stock compensation plan		-		-		480			-			737			-			-			-			1,217
Issuance of stock for acquisition		-		-		-			48,900			-			-			-			-			48,900
Issuance of common stock		10,925		-		157,757			-			-			-			-			-			168,682
Issuance costs of equity units		-		-		(3,443	)		-			-			-			-			-			(3,443	)
Contract adjustment payment		-		-		(11,713	)		-			-			-			-			-			(11,713	)
Sale of common stock held in trust		-		-		(243	)		-			2,424			-			-			-			2,181
Exercise of stock options		626		-		2,304			487			(370	)		-			-			-			3,047
Contributions to Trust		-		-		-			-			(2,165	)		2,165			-			-			-
Disbursements from Trust		-		-		-			-			1,578			(1,578	)		-			-			-
Balance June 30, 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

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

F-6

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

(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 of dollars)

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

Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			20,683			20,683
Unrealized gain on hedging
activities, net of tax		-		-		-			-			-			-			1,075			-			1,075
Minimum pension liabilitiy
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

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

Table of Contents

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 transportation, storage and distribution of natural gas in the United States. Through Southern Union’s wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LP, (Panhandle Eastern Pipe Line) and its subsidiaries (collectively Panhandle Energy), the Company owns and operates more than 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 Energy 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 CCE Holdings, LLC (CCE Holdings), Southern Union has an interest in and operates Transwestern Pipeline Company, LLC (Transwestern) and Florida Gas Transmission Company (Florida Gas,) interstate pipeline companies that transport natural gas from producing areas in western Texas, Colorado and New Mexico to markets throughout the Southwest and to California, and from producing areas along the Gulf Coast and in the Gulf of Mexico to Florida, respectively. Through Southern Union’s three regulated utility divisions - Missouri Gas Energy, PG Energy and New England Gas Company, the Company serves over 965,000 natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island.

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 the 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. Investments that are variable interest entities are consolidated if the Company is allocated a majority of the entity’s residual gains and/or losses, including fees paid by the entity. 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 June 11, 2003 acquisition of Panhandle Energy was accounted for using the purchase method of accounting in accordance with FASB Statement No. 141, Business Combinations. Under this statement, the purchase price paid by the acquirer, including transaction costs, is allocated to the 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 generally has used outside appraisers to assist in the initial determination of fair value. The appraisal related to Southern Union’s acquisition of Panhandle Energy was finalized in 2004. See Note 3 - Acquisitions and Sales.

Plant, Property 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 items of PP&E is charged to expense as incurred.

When PP&E is retired, the original cost less salvage 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.

F-8

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 year ended December 31, 2005, the six months ended December 31, 2004 and for the years ended June 30, 2004 and 2003 were 3.0 percent, 3.3 percent, 3.2 percent and 3.1 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, 2005 and December 31, 2004, such overdraft balances classified in accounts payable were approximately $7.9 million and $9.2 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 and distribution of natural gas in the United States, and reports these operations under two reportable segments: the Transportation and Storage segment and the Distribution segment. See Note 21 - Reportable Segments.

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.

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 the customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered to the customer, 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 Panhandle Eastern Pipe Line’s subsidiary, Trunkline Gas Company, LLC (Trunkline), which settles imbalances via cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.

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

F-9

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, Company policy requires a deposit from customers 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.

The following table shows the balance in the allowance for doubtful accounts and activity for the year ended December 31, 2005, the six-month period ended December 31, 2004 and the years ended June 30, 2004 and 2003:

	Year Ended			Six Months Ended			Years Ended
	December 31,			December 31,			June 30,
	2005			2004			2004			2003
	(In thousands)
Beginning Balance	$	15,424		$	16,111		$	22,651		$	20,753
Additions: Charged to Cost and Expenses		22,519			11,649			21,216			17,873
Deductions: Write-off of Uncollectible Accounts		(22,751	)		(14,752	)		(30,809	)		(17,715	)
Other		701			2,416			3,053			1,740
Ending Balance	$	15,893		$	15,424		$	16,111		$	22,651

The following table presents the billed and unbilled Accounst receivable included in the Consolidated Balance Sheet at December 31, 2005 and 2004. Billed receivables are net of the allowance for doubtful accounts. Unbilled receivables for the Transportation and Storage segment reflect an estimate for services provided in the last month of each period presented which are billed in the following month. Unbilled receivables for the Distribution segment represent estimated billing for unread meters through the normal course of business.

	December 31, 2005						December 31, 2004
	Billed		Unbilled		Total		Billed		Unbilled		Total
	(In thousands)

Transportation and Storage Segment	$	6,281	$	47,109	$	53,390	$	3,310	$	44,913	$	48,223
Distribution Segment		219,047		147,597		366,644		159,908		112,781		272,689
Corporate and other		8,701		-		8,701		1,976		-		1,976
Total	$	234,029	$	194,706	$	428,735	$	165,194	$	157,694	$	322,888

Earnings Per Share. The Company’s earnings per share presentation conforms to FASB Statement No. 128, Earnings per Share. All share and per share data have been appropriately restated for all stock dividends, unless otherwise stated.

Stock Based Compensation. Southern Union accounts for stock option grants using the intrinsic-value method in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees, and related authoritative interpretations. Under the intrinsic-value method, no compensation expense is recognized when the exercise price of Southern Union’s employee stock options is greater than or equal to the market price of the underlying stock on the date of grant.

F-10

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table illustrates the effect on net earnings and net earnings available for common stockholders per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, as amended by FASB Statement No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, to stock-based employee compensation for the stated periods:

	Year Ended		Six Months Ended		Years Ended
	December 31,		December 31,		June 30,
	2005		2004		2004		2003
	(In thousands of dollars, except per share amounts)

Net earnings, as reported	$	20,683	$	14,771	$	114,025	$	76,189
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		1,373
Pro forma net earnings	$	20,095	$	14,275	$	112,326	$	74,816

Net earnings available for common stockholders per share:
Basic- as reported	$	0.03	$	0.07	$	1.26	$	1.17
Basic- pro forma	$	0.02	$	0.06	$	1.24	$	1.15

Diluted- as reported	$	0.03	$	0.07	$	1.24	$	1.15
Diluted- pro forma	$	0.02	$	0.06	$	1.21	$	1.12

The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for incentive and non-qualified stock options and stock appreciation rights granted in the years ended December 31, 2005 and June 30, 2004:

	Year ended	Year ended
	December 31, 2005	June 30, 2004

Dividend yield	1.67%	0.00%
Volatility	20.57% to 38.83%	36.75%
Risk free interest rate	3.69% to 4.52%	2.95%
Expected term	1 to 6.5 years	6 years
Expected forfeiture	0%	0%
Weighted average option fair value	$7.05 to $13.96	$7.35

Additionally, for the year ended December 31, 2005 the Company granted shares of restricted stock with a weighted average fair value of $23.56 to $24.87 per share. No restricted stock awards were granted prior to the year ended December 31, 2005. There were no options or shares of restricted stock granted above fair market value at the grant date during the years ended December 31, 2005 and June 30, 2004, except as disclosed in Note 10 - Stockholders’ Equity. No options were granted during the six months ended December 31, 2004 or during the year ended June 30, 2003.

See Note 10 - Stockholders’ Equity for discussion of non-cash compensation expense recorded in 2005 related to stock options.

F-11

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Comprehensive Income. 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 loss on investment securities, and unrealized gain (loss) on hedging activities, all of which are presented in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income.

The table below gives an overview of comprehensive income for the periods indicated.

	Year Ended		Six Months Ended			Years Ended
	December 31,		December 31,			June 30,
Comprehensive Income Overview	2005		2004			2004			2003
	(In thousands)

Net earnings	$	20,683	$	14,771		$	114,025		$	76,189
Other comprehensive income (loss):
Unrealized loss on investment securities,
net of tax (benefit) of $0, $0, $(13) and $(323), respectively		-		-			(21	)		(581	)
Unrealized gain (loss) on hedging activities, net of tax (benefit)
of $73, $2,031, $4,306 and $(3,092), respectively		108		2,154			7,105			(5,562	)
Realized gain (loss) on hedging activities in net earnings,
net of tax (benefit) of $608, $(2,089), $(3,331) and $(3), respectively		967		(2,216	)		(5,497	)		(6	)
Minimum pension liability adjustment, net of tax (benefit)
of $1,064, $(8,328), $6,526 and $(23,306), respectively		1,771		(8,832	)		10,768			(41,930	)
Other comprehensive income (loss)		2,846		(8,894	)		12,355			(48,079	)
Comprehensive income	$	23,529	$	5,877		$	126,380		$	28,110

Accumulated other comprehensive loss reflected in the Consolidated Balance Sheet at December 31, 2005 includes unrealized gains and losses on hedging activities and minimum pension liability adjustments.

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, 2005 was $102.5 million, or 14,145,000 million British thermal units (MMBtu), of which $25.1 million was classified as non-current. Gas held for operations at December 31, 2004 was $116.8 million, or 20,936,000 MMBtu, of which $30.5 million is classified as non-current.

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, 2005 and December 31, 2004 was $187.6 million and $161.7 million, respectively, and consisted of 25,324,000 and 28,091,000 MMBtu, respectively.

F-12

Table of Contents

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 the 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, the Company has accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, 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. Goodwill acquired in a purchase business combination and determined to have an indefinite useful life is not amortized, but instead is tested for impairment annually by applying a fair-value based test. The Company’s goodwill is related to its three regulated utility divisions - Missouri Gas Energy, PG Energy and New England Gas Company. 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 longterm debt is estimated using current market quotes and other estimation techniques. See Note 13 - Debt and Capital Leases.

Gas Imbalances. In the Transportation and Storage segment, gas imbalances occur as a result of differences in volumes of gas received and delivered. 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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 record an asset. Panhandle Energy’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 year ended December 31, 2005, the six month period ended December 31, 2004 and the years ended June 30, 2004 and 2003 was $9.0 million, $2.7 million, $3.8 million and $224,000, respectively.

Derivative Instruments and Hedging Activities. The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, to account for derivative and hedging activities. 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 either: (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 debt. 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 other comprehensive loss until the related hedge 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. 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) and FIN No. 47, Accounting for Conditional Asset Retirement Obligations. 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. Upon adopting FASB Statement No. 143, the Company classified approximately $27 million of negative salvage previously included in accumulated depreciation to deferred credits for amounts collected for asset retirement obligations on certain of the Panhandle Energy assets acquired that were not asset retirement liabilities under the statement but represent other obligations.

The Company adopted FIN No. 47 as of December 31, 2005. Upon adoption of FIN No. 47, the Company recorded an increase in net PP&E and a liability for an ARO of $882,000. This new asset and liability related to obligations associated with the removal and disposal of asbestos and asbestos-containing materials on the Panhandle Energy system.

FASB 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.

F-14

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Energy 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.

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 the ARO and its associated long-lived assets at December 31, 2005.


	In Service
ARO Description	Date	Long-Lived Assets	Amount
			(In thousands)
Retire offshore lateral lines	Various	Offshore lateral lines	$ 2,803
Remove asbestos	Various	Mainlines and compressors	882

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

	Year Ended			Six Months Ended			Year Ended
	December 31,			December 31,			June 30,
	2005			2004			2004
	(In thousands)

Beginning Balance	$	5,657		$	6,407		$	6,757
Incurred		2,371			-			395
Settled		(285	)		(999	)		(1,373	)
Accretion Expense		457			249			628
Ending Balance	$	8,200		$	5,657		$	6,407

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-15

Table of Contents

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 their obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes, including taxes that are subject to ongoing appeals.

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.

FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Medicare Prescription Drug Act): Issued by the FASB in May 2004, FASB Financial Staff Position (FSP) No. FAS 106-2 (FSP FAS 106-2) requires entities to record the impact of the Medicare Prescription Drug Act as an actuarial gain in the postretirement benefit obligation for postretirement benefit plans that provide drug benefits covered by that legislation. Southern Union adopted this FSP as of March 31, 2005, the effect of which was not material to the Company's consolidated financial statements. The effect of this FSP may vary as a result of any future changes to the Company's benefit plans. See Note 14 - Employee Benefits - Recently Enacted Legislation.

FSP No. FIN 46R-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities”: Issued by the FASB in March 2005, this Staff Position addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (VIE) or potential VIE when specific conditions exist. An implicit variable interest is an implied pecuniary interest in an entity that indirectly changes with changes in the fair value of the entity's net assets exclusive of variable interests. Implicit variable interests may arise from transactions with related parties, as well as from transactions with unrelated parties. Southern Union adopted this FSP, which had no impact on its consolidated financial statements, as of March 31, 2005.

FIN No. 47, “Accounting for Conditional Asset Retirement Obligations”: Issued by the FASB in March 2005, this Interpretation 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 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 and did not materially impact its consolidated financial statements.

F-16

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounting Principles not yet 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 FASB Statement 123R, Share-Based Payment, 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 financial statements. Based upon unvested stock-based compensation awards outstanding at December 31, 2005, the Company estimates additional compensation expense resulting from the implementation of this statement will be $3 million for 2006, $1.8 million for each of 2007 and 2008, $900,000 for 2009 and $148,000 for 2010. The Company did not make any amendments to their existing stock option arrangements as a result of considering the statement’s adoption. Upon the Company’s adoption of the statement, 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.

FERC Accounting Release. On June 30, 2005, FERC issued a final order on accounting for pipeline assessment costs that requires pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs under the Pipeline Safety Improvement Act of 2002. The accounting release determined that assessment activities associated with an integrity management program must be accounted for as maintenance and charged to expense in the period incurred. Costs associated with any remediation or rehabilitation can be capitalized. FERC accounting guidance is effective January 1, 2006 for regulatory accounting purposes. Panhandle Energy has begun to apply the order for its regulatory accounting in 2006 with no impact on its current treatment for GAAP purposes.

3. Acquisitions and Sales

Acquisition of Sid Richardson Energy Services. On March 1, 2006, Southern Union acquired Sid Richardson Energy Services, Ltd., a privately held natural gas gathering and processing company, and related entities for $1.6 billion in cash. The acquisition was funded under a bridge loan facility in the amount of $1.6 billion (Sid Richardson Bridge Loan) that was entered into between the Company and Enhanced Service Systems, Inc. (ESSI), a wholly-owned subsidiary as borrower and a group of banks on March 1, 2006. The Sid Richardson Bridge Loan is available for a maximum period of 364 days at interest rates tied to LIBOR or prime rate plus a spread based upon the credit ratings of the Company’s senior unsecured debt. Under the terms of the Sid Richardson Bridge Loan, the Company is required to apply 100 percent of the net cash proceeds from asset dispositions and from the issuance of equity and/or debt, other than from the refinancing of debt, to repay the bridge loan facility. The Sid Richardson Bridge Loan is secured by the Company’s pledge of its interests in Panhandle Eastern Pipe Line and a pledge of the equity interests in Sid Richardson Energy Services, Ltd. and related entities.

The principal assets of the business, now known as Southern Union Gas Services, are located in the Permian Basin of Texas and New Mexico and include approximately 4,600 miles of natural gas and natural gas liquids gathering pipelines, four active cryogenic plants and six active 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 customers include power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States. Southern Union Gas Services’ major natural gas pipeline interconnects are with ATMOS Pipeline, El Paso Natural Gas Company, Energy Transfer Fuel, LP, Enterprise Pipeline and Transwestern. Its major natural gas liquids pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

F-17

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Disposition of the Rhode Island Assets of New England Gas Company. On February 15, 2006, Southern Union entered into a definitive agreement to sell the Rhode Island operations of its New England Gas Company division to National Grid USA for $575 million, subject to working capital adjustments, less assumed debt of $77 million. Proceeds from the sale will be 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, Ltd. and related entities.

Disposition of PG Energy. On January 26, 2006, Southern Union entered into a definitive agreement to sell the assets of its PG Energy natural gas distribution division in Pennsylvania to UGI Corporation for $580 million, subject to working capital adjustments. Proceeds from the sale will be used to retire a portion of the acquisition debt to be incurred in connection with Southern Union’s $1.6 billion purchase of Sid Richardson Energy Services Company Ltd. and related entities.

Execution of the January 26, 2006 and February 15, 2006 sales agreements constituted a subsequent event under GAAP required to be considered by the Company in its annual assessment for 2005 of the carrying value of the Company’s goodwill. Accordingly, based on the fair values of these reporting units derived principally from the definitive sales agreements, an estimated goodwill impairment charge of $175 million was recorded in the 2005 period in the Company’s Distribution segment. Additional impairment charges may be determined and recorded in subsequent periods due to changes in the underlying book values of these reporting units prior to completion of the sale transactions. Pursuant to FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company will report these assets as held for sale and report their results of operations as discontinued operations in 2006. The Company currently anticipates completing the sale transactions by the end of the third quarter in 2006.

Investment in CCE Holdings. On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns 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 divested 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 owns 100 percent of Transwestern Pipeline Company, LLC (Transwestern) and has a 50 percent interest in Citrus Corp. (Citrus) which, in turn, owns 100 percent of Florida Gas Transmission Company (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. Subsequently, 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 is accounted for using the equity method of accounting. Accordingly, Southern Union reports its share of CCE Holdings’ earnings as Earnings from unconsolidated investments in the Consolidated Statement of Operations. The Consolidated Statement of Operations for the periods subsequent to the acquisition is therefore not comparable to the same periods in prior years.

Transwestern and Florida Gas are primarily engaged in the interstate transportation of natural gas and are subject to FERC rules and regulations. Transwestern owns and operates a bi-directional interstate natural gas pipeline system (approximately 2,500 miles in length and having 2.1 Bcf/d of capacity) that accesses natural gas supply from the San Juan Basin, western Texas and mid-continent producing areas, and transports these volumes to markets in California, the Southwest and the key trading hubs in western Texas. Florida Gas is the principal transporter of natural gas to the Florida energy market through a pipeline system (approximately 5,000 miles in length and having 2.1 Bcf/d of capacity) that connects the natural gas supply basins of the Texas and Louisiana Gulf Coasts and the Gulf of Mexico to Florida.

F-18

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Acquisition of Panhandle Energy. On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation for approximately $581.7 million in cash and 3,000,000 shares of Southern Union common stock (before adjustment for subsequent stock dividends) valued at approximately $48.9 million based on market prices at closing of the Panhandle Energy acquisition, and in connection therewith incurred transaction costs of approximately $31.9 million. At the time of the acquisition, Panhandle Energy had approximately $1.16 billion of principal amounts of debt outstanding which it retained. The Company funded the cash portion of the acquisition with approximately $437 million in cash proceeds it received from the January 1, 2003 sale of its Southern Union Gas Company natural gas operating division and related assets (Texas Operations), approximately $121.3 million of the net proceeds it received from concurrent common stock and equity unit offerings (see Note 10 - Stockholders’ Equity) and with working capital available to the Company. The Company structured the Panhandle Energy acquisition and the sale of the Texas Operations to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.

Panhandle Energy is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services and is subject to the rules and regulations of FERC. The Panhandle Energy entities include Panhandle Eastern Pipe Line Company, LP (Panhandle Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company, LLC (Sea Robin), an indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG), a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings), which is itself an indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line, and Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage), a wholly-owned subsidiary of Panhandle Eastern Pipe Line. Collectively, these pipeline assets include more than 10,000 miles of interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes region. The pipelines have a combined peak day delivery capacity of 5.3 Bcf/d and 72 Bcf of owned underground storage capacity and 6.3 Bcf of above ground LNG storage capacity. Trunkline LNG, located on Louisiana’s Gulf Coast, operates one of the largest LNG import terminals in North America, based on current send out capacity.

The following table summarizes the estimated fair values of the Panhandle Energy assets acquired and liabilities assumed at the date of acquisition. These fair values were recorded based on the finalization of outside appraisals and reflect a net reduction of approximately $16 million from the initial purchase price allocation as a result of purchase accounting adjustments made during the year ended June 30, 2004.

		At June 11, 2003
		(In thousands)

Property, plant and equipment (excluding intangibles)	$	1,904,762
Intangibles		9,503
Current assets (Includes cash and cash equivalents of
approximately $60 million)		217,645
Other non-current assets		30,098
Total assets acquired		2,162,008
Long-term debt		(1,207,617	)
Current liabilities		(165,585	)
Other non-current liabilities		(125,785	)
Total liabilities assumed		(1,498,987	)
Net assets acquired	$	663,021

The following unaudited pro forma financial information for the year ended June 30, 2003 is presented as though the following events had occurred at the beginning of the period: (i) the acquisition of Panhandle Energy; (ii) the issuance of the common stock and equity units in June 2003; and (iii) the refinancing of certain short-term and long-term debt at the time of the Panhandle Energy acquisition. The pro forma financial information is not necessarily indicative of the results which would have actually been obtained had the acquisition of Panhandle Energy, the issuance of the common stock and equity units or the refinancings been completed as of the assumed date for the period presented or which may be obtained in the future.

	(Unaudited)
	Year Ended
	June 30, 2003
	(In thousands)

Operating revenues	$	1,671,114
Net earnings from continuing operations		132,458
Net earnings per share from continuing operations:
Basic		1.67
Diluted		1.64

F-19

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Sale of Texas Operations. Effective January 1, 2003, the Company completed the sale of its Texas Operations to ONEOK for approximately $437 million in cash, which resulted in a pre-tax gain of $63 million. In accordance with GAAP, the results of operations and gain on sale of the Texas Operations have been segregated and reported as Discontinued operations in the Consolidated Statement of Operations and as Assets held for sale in the Consolidated Statement of Cash Flows for the respective periods.

4. Other Income (Expense), Net

Other expense for the year ended December 31, 2005 of $7.1 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 the Sid Richardson Energy Services business. See Note 11 - Derivative Instruments and Hedging Activities for additional information related to the put options.

Other expense for the six months ended December 31, 2004 of $18.1 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 income for the year ended June 30, 2004 of $5.5 million includes a gain of $6.4 million on the early extinguishment of debt and income of $2.2 million generated from the sale and/or rental of gas-fired equipment and appliances from various operating subsidiaries. These items were 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.

Other income for the year ended June 30, 2003 of $18 million includes a gain of $22.5 million on the settlement of the Southwest litigation and income of $2 million generated from the sale and/or rental of gas-fired equipment and appliances. These items were partially offset by $5.9 million of legal costs related to the Southwest litigation and $1.3 million of selling costs related to the disposition of the Texas Operations.

F-20

Table of Contents

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 year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003:

				Six Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			June 30,
	2005			2004			2004			2003
	(In thousands of dollars, except per share amounts)

Net earnings from continuing operations	$	20,683		$	14,771		$	114,025		$	43,669
Net earnings from discontinued operations		-			-			-			32,520
Preferred stock dividends		(17,365	)		(8,683	)		(12,686	)		-
Net earnings available for common stockholders	$	3,318		$	6,088		$	101,339		$	76,189

Weighted average shares outstanding - Basic		109,395,418			87,313,787			80,431,988			64,949,776
Weighted average shares outstanding - Diluted		112,794,210			89,717,427			81,479,503			66,025,488

Basic earnings per share:
Net earnings available for common stockholders
from continuing operations	$	0.03		$	0.07		$	1.26		$	0.67
Net earnings from discontinued operations		-			-			-			0.50
Net earnings available for common stockholders	$	0.03		$	0.07		$	1.26		$	1.17

Diluted earnings per share:
Net earnings available for common stockholders
from continuing operations	$	0.03		$	0.07		$	1.24		$	0.66
Net earnings from discontinued operations		-			-			-			0.49
Net earnings available for common stockholders	$	0.03		$	0.07		$	1.24		$	1.15

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, warrants, restriced 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		Ended		Years Ended
	December 31,		December 31,		June 30,
	2005		2004		2004		2003

Weighted average shares outstanding - Basic		109,395,418		87,313,787		80,431,988		64,949,776
Add assumed vesting of restricted stock		15,596		-		-		-
Add assumed conversion of equity units		2,141,033		1,172,431		-		-
Add assumed exercise of stock options		1,242,163		1,231,209		1,047,515		1,075,712
Weighted average shares outstanding - Dilutive		112,794,210		89,717,427		81,479,503		66,025,488

During the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, no adjustments were required in net earnings available for common stockholders for the earnings per share calculations.

During the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, the Company repurchased 649,343, nil, 122,203 and 156,340 shares of its common stock outstanding, respectively. Substantially all of these repurchases occurred in private off-market large-block transactions.

F-21

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

There were 87,346, 304,595 and 2,442,094 “anti-dilutive” options outstanding for the 12-month periods ended December 31, 2005, June 30, 2004 and June 30, 2003, respectively. There were no “anti-dilutive” shares outstanding for the six-month period ended December 31, 2004. At December 31, 2005, 826,348 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit. From time to time, the Company’s benefit plans may purchase shares of Southern Union common stock subject to regular restrictions.

On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit. Each 5% Equity Unit consists of a 1/20^th interest in a $1,000.00 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note 13 - Debt and Capital Leases) 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. Until the conversion date, the 5% Equity Units will have a dilutive effect on earnings per share if Southern Union’s average common stock price for the period exceeds the settlement conversion price. (see Note 10 - Stockholders’ Equity).

On June 11, 2003, Southern Union issued 2,500,000 of its 5.75% Equity Units at a public offering price of $50 per unit. Each 5.75% Equity Unit consists of a $50.00 principal amount of Southern Union’s 2.75% Senior Notes due 2006 (see Note 13 - Debt and Capital Leases) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on August 16, 2006, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $13.82 and $16.86, respectively, which are subject to adjustments for future stock splits or stock dividends). Southern Union will issue between 7,413,070 shares and 9,043,945 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. Until the conversion date, the 5.75% Equity Units will have a dilutive effect on earnings per share if Southern Union’s average common stock price for the period exceeds the maximum conversion price. (See Note 10 - Stockholders’ Equity).

F-22

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. Property, Plant and Equipment

			December 31,
Property, Plant and Equipment	Lives in Years		2005			2004
			(In thousands)

Distribution plant		10-75	$	1,774,802		$	1,707,174
Transmission plant		36-46		1,285,848			1,185,647
General - LNG		40		494,827			388,703
General plant - other		1-71		163,684			143,435
Underground storage plant		36-46		275,603			274,337
Gathering plant		26		45,822			46,074
Other		5-38		145,185			126,308
Total plant (a)				4,185,771			3,871,678
Less contributions in aid of construction				(2,491	)		(2,457	)
Plant in service				4,183,280			3,869,221
Construction work in progress				184,423			237,283
				4,367,703			4,106,504
Less accumulated depreciation and amortization (a)				(881,763	)		(778,876	)
Net property, plant and equipment			$	3,485,940		$	3,327,628

(a) Includes capitalized computerized software cost totaling:

Unamortized computer software cost		3-15	$	119,471		$	118,596
Less accumulated amortization				(44,588	)		(40,378	)
Net capitalized computer software costs			$	74,883		$	78,218

Amortization expense of capitalized computer software costs for the year ended December 31, 2005, the six months ended December 31, 2004 and for the years ended June 30, 2004 and 2003 was $11 million, $7.6 million, $10.0 million and $10 million, respectively. During the six months ended December 31, 2004, the Company recorded in amortization expense a $2.3 million charge to write-down the value of certain capitalized software costs. Also during the six months ended December 31, 2004, the Company commenced the utilization of an upgraded internally developed computer application to manage its pipeline administration and recorded in property, plant and equipment costs of $34.2 million related to these applications pursuant to SOP 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. Computer software costs are amortized between three and fifteen years.

F-23

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Goodwill and Intangibles

The following table displays changes in the carrying amount of goodwill:

Goodwill Analysis	Amounts
	(In thousands)

Balance as of July 1, 2002	$	642,921
Impairment losses		-
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

As a result of the sale of the Texas Operations, goodwill of $70.5 million (reclassified as a component of assets held for sale, see Note 19 - Discontinued Operations) was eliminated during the quarter ended March 31, 2003. 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 quarter ended June 30, 2004. All goodwill reflected in the Company’s Consolidated Balance Sheet is applicable to its Distribution segment.

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. Considering the prices included in the definitive agreements in the first quarter of 2006 to sell the Company’s PG Energy division and the Rhode Island operations of its New England Gas Company division, the Company determined that there was a goodwill impairment. Execution of the sale agreements 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, an estimated goodwill impairment charge of $175 million was recorded in the 2005 period.

On June 11, 2003, the Company completed its acquisition of Panhandle Energy. Based on purchase price allocations that rely on estimates and outside appraisals, the acquisition resulted in no recognition of goodwill. In addition, based on the purchase price allocations and outside appraisals, the acquisition resulted in the recognition of intangible assets relating to customer relationships of approximately $9.5 million. These intangibles are currently being amortized over a period of twenty years, the remaining life of the contract for which the value is associated. As of December 31, 2005, the carrying amount of these intangibles was approximately $8.0 million and is included in Property, plant and equipment on the Consolidated Balance Sheet. Amortization expense on the customer contracts for the year ended December 31, 2005, the six months ended December 31, 2004 and for the years ended June 30, 2004 and 2003 was approximately $465,000, $224,000, $583,000 and $200,000, respectively. The Company estimates the annual amortization expense for years 2006 through 2010 and thereafter will be $465,000 per year.

F-24

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Regulatory Assets and Liabilities

	December 31,
Regulatory Assets	2005		2004
	(In thousands)

Pension and Post-retirement Benefits	$	32,627	$	26,809
Deferred Income Tax		28,076		28,958
Environmental		23,656		16,332
Missouri Safety Program		11,956		15,161
Other		16,648		15,695
	$	112,963	$	102,955

As of December 31, 2005 and December 31, 2004, the Company’s regulatory assets relating to Distribution segment operations include $59.1 million and $62.7 million, respectively, that is being recovered through current rates. As of December 31, 2005 and December 31, 2004, the remaining recovery period associated with these assets ranged from one month to 187 months and one month to 199 months, respectively. None of these regulatory assets are included in rate base.

	December 31,
Regulatory Liabilities	2005		2004
	(In thousands)

Environmental	$	8,817	$	8,740
Other		1,253		2,145
	$	10,070	$	10,885

The Company records regulatory assets and liabilities with respect to its Distribution segment operations in accordance with FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Panhandle Energy does not apply this statement in accounting for its operations. Panhandle Energy’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978. In 1999, Panhandle Energy discontinued the application of this statement primarily due to the level of discounting from tariff rates and its ability to recover all costs. The accounting required by the statement differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, among others, recording of regulatory assets and the capitalization of an equity component on regulated capital projects.

F-25

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Unconsolidated Investments

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

	December 31,
Unconsolidated Investments	2005		2004
	(In thousands)
Equity investments:
CCE Holdings	$	668,985	$	615,861
Other		13,074		12,919
Investments at cost		775		3,113

	$	682,834	$	631,893

Equity Investments. Unconsolidated investments include the Company’s 50 percent, 29 percent and 49.9 percent investments in CCE Holdings, Lee 8 and PEI Power II, respectively, which are accounted for using the equity method. The Company’s share of net income from these equity investments is recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations. The Company’s equity investment balances include unamortized purchase price differences of $18.4 million and $20.7 million as of December 31, 2005 and 2004, respectively. The purchase price differences represent the excess of the purchase price over the Company’s share of the investee’s book value at the time of acquisition and, accordingly, have been designated as goodwill that will be accounted for pursuant to APB Opinion 18, The Equity Method of Accounting for Investments in Common Stock, and FASB Statement No. 142, Goodwill and Other Intangible Assets.

CCE Holdings. On November 17, 2004, CCE Holdings acquired the equity interests of CrossCountry Energy from Enron Corp. and its affiliates for $2.45 billion in cash, including certain consolidated debt. The Company contributed an equity investment of $590.5 million to CCE Holdings to finance a portion of the cost of the acquisition. At the time of the acquisition, a wholly-owned subsidiary of Southern Union owned all of the “Class A” membership interests of CCE Holdings, comprising 50 percent of the outstanding membership interests, and a wholly-owned subsidiary of General Electric Company (GE) owned all of the “Class B” membership interests of CCE Holdings, comprising 50 percent of the outstanding membership interests. In December 2004, GE sold down a portion of its equity interest in CCE Holdings to four institutional investors. Currently, GE owns approximately 30 percent of CCE Holdings, and these investors own approximately 20 percent of CCE Holdings. CrossCountry Energy owns 100 percent of Transwestern and 50 percent of Citrus, which, in turn, owns 100 percent of Florida Gas. An affiliate of El Paso Corporation owns the remaining 50 percent interest in Citrus. CrossCountry Energy is comprised of approximately 7,500 miles of natural gas pipelines with approximately 4.2 Bcf/d of natural gas transportation capacity.

CCE Holdings’ executive committee is comprised of two persons elected by the holder of the majority of the Class A membership interests in CCE Holdings (i.e., Southern Union), and two persons elected by the holder of the majority of the Class B membership interests in CCE Holdings (i.e., GE). The executive committee is the principal decision maker in the operation of CCE Holdings’ assets.

F-26

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company recorded equity earnings from its investment in CCE Holdings of $70.4 million and $4.6 million in 2005 and 2004, respectively, in Earnings from unconsolidated investments in the Consolidated Statement of Operations. Additionally, CCE Acquisition LLC, a wholly-owned subsidiary of the Company, received a distribution of $15 million from CCE Holdings during 2005. No distributions were received in 2004.

Southern Union and GE, through their respective wholly-owned subsidiaries, each have identical call options to purchase a 25 percent portion of the equity interest of the other party (and any person to which it transferred any interests) prior to the expiration of the period ending 18 months after the closing of the CrossCountry Energy acquisition (Transfer Restriction Period) that are exercisable on the fifth, sixth, seventh and eighth anniversaries of the closing of the acquisition of CrossCountry Energy.

In addition, Southern Union has a call option to purchase any Class B membership interest that is transferred after the expiration of the Transfer Restriction Period, and GE has a call option to purchase any Class A membership interest that is transferred after the expiration of the Transfer Restriction Period.

GE also has an option to “put” its interest in CCE Holdings to Southern Union ten years after the CrossCountry Energy acquisition by CCE Holdings. The Company believes that the exercise prices of the call and put options noted above are based on the fair market value of the underlying interests.

Other. Southern Union also has a 29 percent and 49.9 percent interest in the net assets of the Lee 8 partnership and PEI Power II, respectively, both of which are accounted for under the equity method. 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 plant operated through a joint venture with Cayuga Energy in Pennsylvania.

Summarized financial information for the Company’s equity investments was:

	At December 31, 2005				At December 31, 2004
	CCE		Other Equity		CCE		Other Equity
	Holdings		Investments		Holdings		Investments
	(In thousands)
Balance Sheet Data:
Current assets	$	69,983	$	2,122	$	54,078	$	1,255
Non-current assets		2,313,874		28,832		2,257,899		22,847
Current liabilities		49,428		2,955		64,468		833
Non-current liabilities		1,034,092		356		1,057,907		2,625

	For the Year Ended December 31, 2005				For the Six Months Ended December 31, 2004
	CCE		Other Equity		CCE		Other Equity
	Holdings		Investments		Holdings		Investments
	(In thousands)
Income Statement Data:
Revenues	$	236,359	$	6,942	$	27,194	$	1,919
Operating income		121,000		1,230		6,576		394
Equity earnings		72,492		-		7,549		-
Net income		140,735		1,058		8,602		295

F-27

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments at Cost. As of December 31, 2005 and 2004, 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 in 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. Based on Advent's efforts during 2004 to raise additional capital from private investors and the resulting valuations of Advent by these investors placing a significantly lower value on the Company's investment than its cost, the Company reevaluated the fair value of its investment in Advent. The foregoing, as well as certain other factors, led to the non-cash charge discussed above.

On March 24, 2005, Advent’s board of directors approved the filing of a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the Western District of Texas (Bankruptcy Court). As a result, Southern Union recorded a $4 million liability associated with the guarantee by a subsidiary of the Company of a line of credit between Advent and a bank in the first quarter of 2005. On April 8, 2005, subsequent to the bankruptcy filing, Advent defaulted on its $4 million line of credit and the guarantee liability was funded. Also as of March 31, 2005, the Company 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.

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, to reduce the carrying value of this investment to its estimated fair value. 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 $773,000 at December 31, 2005 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 the Company’s Investment in CCE Holdings.

Environmental Matters. Transwestern and Florida Gas, through the Company’s investment in CCE Holdings, are responsible for environmental remediation at certain sites on their gas transmission systems. The contamination resulted from the past releases primarily of hydrocarbons, and to some extent past releases of chlorinated compounds and, on Transwestern, PCBs that were originally introduced into the Transwestern system through use of a PCB-based lubricant in the late 1960s and early 1970s. Transwestern and Florida Gas are 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 financial position, results of operations or cash flows.

Transwestern incurred, and continues to incur, certain costs related to PCBs that migrated into its customers’ facilities. Because of the continued detection of PCBs in the customers’ facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities during 2005 totaled $400,000. Future costs cannot be reasonably estimated and no accrual has been established for these costs at December 31, 2005. Nevertheless, such future costs are not expected to have a material impact on Transwestern’s financial position or results of operations or cash flows.

F-28

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Environmental regulations were recently modified for U.S. EPA’s 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 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 totaled approximately $113.3 million at December 31, 2005. Pursuant to FASB Statement No. 142, Goodwill and Other Intangible Assets, CCE Holdings performs an annual impairment test of the recorded goodwill balance.

Regulatory Assets and Liabilities. Transwestern and Florida Gas are subject to regulation by certain state and federal authorities. Both companies have accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. Management’s assessment for Transwestern and Florida Gas of the probability of their recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, Transwestern or Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of their 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. At December 31, 2005, Transwestern had regulatory asset and regulatory liability balances of $64.9 million and nil, respectively. Florida Gas’ regulatory asset and liability balances at December 31, 2005 were $24.1 million and $9.0 million, respectively.

Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the 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 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 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 $12 million to $22 million per year, inclusive of remediation costs. For Transwestern, the required modifications and inspections are estimated to range from approximately $3 million to $5 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 planning to replace approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way on State Road 91 between Griffin Road and Atlantic Avenue in Broward County, Florida with a single 36-inch pipeline starting in the fourth quarter 2006. Estimated cost of this project is $110 million. Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may require relocation and replacements of 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 the associated relocation and/or right-of-way costs, cannot be determined at this time.

F-29

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 April 8, 2005, Florida Gas filed a complaint in the Ninth Judicial Circuit, Orange County, Florida seeking a declaratory judgment order finding, among other things, that Florida Gas has a compensable property interest in certain easements and agreements with the FDOT/FTE, and that Florida Gas is entitled to recover: (i) compensation for any of Florida Gas’ right-of-way to be taken, (ii) costs incurred and to be incurred by Florida Gas 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). Florida Gas also seeks an order declaring that FDOT/FTE has a duty to avoid conflict at Florida Gas facilities when reasonably possible and to provide sufficient rights-of-way to allow Florida Gas to fully operate, relocate and maintain its facilities in a manner contemplated by the agreements or pay compensation for the loss of Florida Gas’ property rights. Trial is set for September 12, 2006. If Florida Gas is unsuccessful in obtaining reimbursement through this judicial proceeding, 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. There can be no assurance that Florida Gas’ litigation to obtain reimbursement will be successful or that any subsequent effort to obtain rate recovery at FERC will fully compensate Florida Gas for its costs.

Phoenix Expansion Project. On November 22, 2005, FERC granted Transwestern’s request to use the pre-filing review process for Transwestern’s proposed Phoenix Expansion Project. The project has been assigned Docket No. PF06-4-000. The Phoenix Expansion Project, as currently proposed, consists of the construction and operation of approximately 260 miles of 36-inch diameter natural gas pipeline extending from the existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area. In addition, Transwestern proposes to complete the looping on its existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. Other major facilities include the abandonment and the replacement of the existing compression facilities at Transwestern’s Compressor Station No. 4. Transwestern is proposing to file its application on or before July 1, 2006, with a projected in-service date of early 2008. As of February 28, 2006, Transwestern has executed expansion agreements with shippers for volumes sufficient in Transwestern’s judgment to commence further development of the Phoenix Expansion Project. The project scope and structure are under discussion with the CCE Holdings members.

Litigation.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Transwestern and 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 September 1, 2005, August 31, 2004, July 31, 2003 and July 15, 2002, Southern Union distributed its annual five percent common stock dividend to stockholders of record on August 22, 2005, August 20, 2004, July 17, 2003 and July 1, 2002, respectively. A portion of the five percent stock dividend distributed on July 15, 2002 was characterized as a distribution of capital due to the level of the Company's retained earnings available for distribution as of the declaration date. Unless otherwise stated, all per share and share data included herein 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 it from paying cash dividends.

F-30

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 21, 2005, Southern Union’s Board of Directors approved the payment of an annual cash dividend of $.40 per common share. The cash dividend will replace the Company’s historic practice of issuing an annual five percent stock dividend. The dividend is expected to be declared and paid on a quarterly basis beginning at the end of the first quarter of 2006.

Common Stock. 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 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. The options subject to this modification now remain exercisable for a period of 18 months from the executives’ respective termination dates. As a result of the modification and revaluation 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.

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 periods of 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, 2005 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 years ended June 30, 2004 and 2003, options exercised under the Pennsylvania Option Plan were 466,127, nil, nil and 15,538 options, respectively. During the year ended December 31, 2005, 139,837 and 91,831 options were exercised and canceled, respectively, and for the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, no options were exercised under the Pennsylvania Incentive Plan.

F-31

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information on stock options granted, exercised, canceled and outstanding under the Amended 2003 Plan and the 1992 Plan for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003:

	Amended 2003 Plan					1992 Plan
				Weighted					Weighted
	Shares			Average		Shares			Average
	Under			Exercise		Under			Exercise
	Option			Price		Option			Price

Outstanding July 1, 2002		-			-		4,027,675			11.10
Granted		-			-		-			-
Exercised		-			-		(696,164	)		4.43
Canceled		-			-		(188,576	)		13.94
Outstanding June 30, 2003		-			-		3,142,935			12.41
Granted		765,779			16.83		-			-
Exercised		-			-		(370,128	)		9.44
Canceled		(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
Canceled		(65,051	)		16.83		(18,887	)		14.63
Outstanding December 31, 2004		698,522			16.83		2,390,705			12.81
Granted		941,252			18.27		136,608			12.75
Exercised		(62,976	)		16.83		(794,105	)		12.47
Canceled		(77,385	)		16.83		(473,584	)		12.45
Outstanding December 31, 2005		1,499,413			17.73		1,259,624			13.15

F-32

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding under the Amended 2003 Plan and the 1992 Plan at December 31, 2005:

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

Amended 2003 Plan:
$0.00 - $7.49		209,903		9.67 years	$	-	-	$	-
12.50 - 14.99		558,161		7.99 years		16.83	92,759		16.83
22.50 - 24.99		731,349		9.67 years		23.52	262,500		23.62
		1,499,413					355,259

1992 Plan:
$7.50 - $9.99		166,543		1.41 years	$	9.70	166,543	$	9.70
10.00 - 12.49		5,134		1.11 years		10.07	5,134		10.07
12.50 - 14.99		1,085,449		3.71 years		13.69	973,971		13.64
15.00 - 17.49		2,498		3.72 years		15.95	2,254		16.01
		1,259,624					1,147,902

F-33

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted average remaining contractual life of options outstanding under the Amended 2003 Plan and the 1992 Plan at December 31, 2005 was 9.04 and 3.39 years, respectively.

The options exercisable under the various plans and corresponding weighted average exercise price at December 31, 2005, December 31, 2004, June 30, 2004 and June 30, 2003 are as follows:

	Amended				Pennsylvania		Pennsylvania
	2003		1992		Option		Incentive
	Plan		Plan		Plan		Plan

Options exercisable at:
December 31, 2005		355,259		1,147,902		-		-
December 31, 2004		22,050		2,122,795		466,127		231,668
June 30, 2004		-		2,132,852		466,127		228,451
June 30, 2003		-		2,089,161		466,127		225,234

Weighted average exercise price at:
December 31, 2005	$ 21.85	$ 13.06	$ -	$ -
December 31, 2004	16.83	12.67	8.77	10.19
June 30, 2004	-	12.52	8.77	10.14
June 30, 2003	-	11.74	8.77	10.09

Warrant. On February 10, 1994, Southern Union granted a warrant to purchase 122,165 shares of its common stock at an exercise price of $5.68 to the Company’s outside legal counsel. On February 10, 2004, the warrant was exercised on a cashless basis, resulting in the issuance of 84,758 shares of Company common stock.

February 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 and Capital Leases) 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.

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 and other transaction related costs, 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.

July 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.

F-34

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 2003 Equity Issuances. On June 11, 2003, Southern Union issued 9,500,000 shares of common stock at a public offering price of $16.00 per share. After underwriting discounts and commissions, the Company realized net proceeds of $146.7 million. The Company granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,425,000 shares of the Company’s common stock at the same price, which was exercised on June 11, 2003, resulting in additional net proceeds to the Company of $22 million.

Also on June 11, 2003, Southern Union issued 3,000,000 shares of common stock from its treasury stock to CMS Energy Corporation in payment of a portion of the purchase price of Panhandle Energy. The shares were valued at $16.30 per share, or $48.9 million, based on the closing price for the Company's common stock as of June 10, 2003.

Also on June 11, 2003, Southern Union issued 2,500,000 of its 5.75% 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 $121.6 million. Each 5.75% Equity Unit consists of a $50.00 principal amount of Southern Union’s 2.75% Senior Notes due 2006 (see Note 13 - Debt and Capital Leases) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on August 16, 2006, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $13.82 and $16.86, respectively, which are subject to adjustments for future stock splits or stock dividends). Southern Union will issue between 7,413,070 shares and 9,043,945 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 5.75% Equity Units carry a total annual coupon of 5.75 percent (2.75 percent annual face amount of the senior notes plus 3.0 percent annual contract adjustment payments). Each stock purchase contract issued as a part of the 5.75% Equity Units carries a maximum conversion premium of up to 22 percent over the $16.00 issuance price (before adjustment for subsequent stock dividends) of the Company’s common shares that were sold on June 11, 2003, as discussed previously. The present value of the 5.75% 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 the Company’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.

11. Derivative Instruments and Hedging Activities

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.

Cash Flow Hedges. On April 29, 2005, the Company refinanced the existing bank loans of LNG Holdings in the amount of $255.6 million, due 2007 (see Note 13 - Debt and Capital Leases). 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.

F-35

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company was also party to an interest rate swap agreement with a notional amount of $8.2 million at June 30, 2003 that fixed the interest rate applicable to floating rate long-term debt and qualified for hedge accounting. The fair value liability position of the swap was $93,000 at June 30, 2003. In October 2003, the swap expired and $15,000 of unrealized after-tax losses included in Accumulated other comprehensive loss relating to this swap was reclassified to interest expense during the quarter ended December 31, 2003.

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 income and will be amortized into interest expense over the lives of the associated debt instruments. As of December 31, 2005, approximately $967,000 of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months.

Fair Value Hedges. In March 2004, Panhandle Energy 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 FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under the swap agreements, Panhandle Energy 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, 2005 and December 31, 2004, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $5.7 million and $3.9 million, respectively.

Trading and Non-Hedging Activities. During 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. 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/liability in the Consolidated Balance Sheet. As of December 31, 2005 and December 31, 2004, the fair values of the contracts, which expire at various times through October 2006, are included in the Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $17.5 million and $2.6 million, respectively.

Natural Gas Put Options. In connection with its agreement to acquire the Sid Richardson Energy Services business, now doing business as Southern Union Gas Services, the Company purchased put options on the price of natural gas in December 2005. These options were tied to the WAHA price of natural gas for the periods March 2006 through December 2006 (2006 Put Options) and January 2007 through December 2007 (2007 Put Options). The 2006 Put Options relate to 45,000 MMBtu/day at the price of $11.00 per MMBtu, which equals an estimated 85 percent of natural gas volumes to be processed and retained by Southern Union Gas Services. The 2007 Put Options relate to 25,000 MMBtu/day at the price of $10.00 per MMBtu, which equals an estimated 50 percent of natural gas volumes to be processed and retained by Southern Union Gas Services. The goal of the purchase of the 2006 and 2007 Put Options was to reduce the downside commodity price risk of the Southern Union Gas Services business. The Company believes that natural gas is the appropriate commodity to hedge due to the contract and asset structure of Southern Union Gas Services. Prior to the March 1, 2006 closing of the acquisition, the 2006 and 2007 Put Options were accounted for using mark-to-market accounting. The impact on the Company’s 2005 results of operations was a gain of $1.8 million due to the general decline of natural gas prices subsequent to the Company’s purchase of the 2006 and 2007 Put Options. At December 31, 2005, the Company reported the fair market value of the put options in the Consolidated Balance Sheet as $32.4 million in Prepayments and other assets and $19.1 million in Deferred charges. After the closing of the acquisition on March 1, 2006, the 2006 and 2007 Put Options were designated as “cash flow hedges” and are being accounted for in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The Company paid a total of $49.7 million to purchase the 2006 and 2007 Put Options, which will be marked to fair market value at each period end, over the life of the options.

F-36

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. Preferred Securities

On May 17, 1995, Southern Union Financing I (Subsidiary Trust), a consolidated wholly-owned subsidiary of Southern Union, issued $100 million principal amount of its 9.48% Trust Originated Preferred Securities (Preferred Securities). In connection with the Subsidiary Trust’s issuance of the Preferred Securities and the related purchase by Southern Union of all of the Subsidiary Trust’s common securities, Southern Union issued to the Subsidiary Trust $103.1 million principal amount of its 9.48% Subordinated Deferrable Interest Notes, due 2025 (Subordinated Notes). The sole assets of the Subsidiary Trust were the Subordinated Notes. On October 1, 2003, Southern Union called the Subordinated Notes and the Preferred Securities for redemption, and the Subordinated Notes and the Preferred Securities were redeemed at par 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 further described below.

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 share of Southern Union’s 7.55% Noncumulative Preferred Stock, Series A 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.

13. Debt and Capital Leases

The following table sets forth the long-term debt and capital lease obligations, including the current portions thereof, of Southern Union and Panhandle Energy 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,
	2005		2005		2004		2004
	(In thousands)
Southern Union Company
7.60% Senior Notes due 2024	$	359,765	$	411,931	$	359,765	$	406,524
8.25% Senior Notes due 2029		300,000		360,723		300,000		364,365
2.75% Senior Notes due 2006		125,000		125,000		125,000		125,000
Term Note due 2005		-		-		76,087		76,087
6.50% to 10.25% First Mortgage Bonds, due 2006 to 2029		111,419		111,165		112,421		112,421
4.375% Senior Notes, due 2008		100,000		100,000		-		-
Capital lease and other, due 2006 to 2007		71		71		117		117
		996,255		1,108,890		973,390		1,084,514

Panhandle Energy
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		305,214
6.05% Senior Notes due 2013		250,000		254,450		250,000		268,450
6.50% Senior Notes due 2009		60,623		63,228		60,623		66,024
8.25% Senior Notes due 2010		40,500		45,135		40,500		47,430
7.00% Senior Notes due 2029		66,305		73,521		66,305		73,492
Term Loan due 2007		255,626		255,626		258,433		258,433
Net premiums on long-term debt		12,205		12,205		14,688		14,688
		1,185,259		1,204,165		1,190,549		1,233,731

Total consolidated debt and capital lease		2,181,514	$	2,313,055		2,163,939	$	2,318,245
Less current portion		126,648				89,650
Less fair value swaps of Panhandle Energy		5,725				3,936
Total consolidated long-term debt and capital lease	$	2,049,141			$	2,070,353

F-37

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southern Union has $2.18 billion of long-term debt recorded at December 31, 2005, of which $126.6 million is current. Debt of $1.72 billion, including net premiums of $12.2 million, is at fixed rates ranging from 2.75 percent to 10.25 percent. Southern Union also has floating rate debt, including notes payable, totaling $875.6 million bearing an average interest rate of 4.76 percent as of December 31, 2005. The variable rate bank loans are unsecured.

As of December 31, 2005, the Company has scheduled debt payments as follows:

											2011 and
	2006		2007		2008		2009		2010		thereafter
	(In thousands)

Southern Union Company	$	126,648	$	1,648	$	101,646	$	1,375	$	1,375	$	763,492
Panhandle Energy		-		455,626		300,000		60,623		40,500		316,305

Total	$	126,648	$	457,274	$	401,646	$	61,998	$	41,875	$	1,079,797

Each note, debenture or bond above is an obligation of Southern Union or a unit of Panhandle Energy, as noted above. Panhandle Energy’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.

Debt issuance costs and premiums or discounts on the early extinguishment of debt are accounted for in accordance with that required by various regulatory bodies having jurisdiction over the Company’s operations. The Company recognizes gains or losses on the early extinguishment of debt to the extent it is provided for by such regulatory authorities, where applicable, and in some cases such gains or losses are deferred and amortized over the term of the new or replacement debt issues.

Term Note. On July 16, 2002, the Company issued a $311.1 million Term Note dated July 15, 2002 (the 2002 Term Note). The 2002 Term Note carried a variable interest rate that was tied to either the LIBOR or prime interest rates at the Company’s option. During the quarter ended June 30, 2005, the Company repaid the remaining $76.1 million principal outstanding under the 2002 Term Note and, as of June 2, 2005, the 2002 Term Note was canceled.

Additional Debt. In connection with the Panhandle Energy acquisition, 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.

Panhandle Energy Refinancing. On April 29, 2005, Panhandle Energy refinanced LNG Holdings’ outstanding bank loans of $255.6 million for the same principal amount and extended the maturity date from January 31, 2007 to March 15, 2007. The new notes have 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) Panhandle Eastern Pipe Line and Trunkline LNG each severally provided a guarantee for the notes; and (iii) the interest rate is tied to the rating of Panhandle Eastern Pipe Line’s unsecured funded debt.

On March 12, 2004, Panhandle Energy 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 Energy’s 7.875% Senior Notes due 2004 that matured on August 15, 2004.

In July 2003, Panhandle Energy 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 principal amount of its two series of debentures then outstanding (Panhandle Calls). Panhandle Energy 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 Energy 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 Energy 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 Energy repurchased $3.2 million 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.

F-38

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Notes Payable. 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 Company has additional availability under uncommitted line of credit facilities (Uncommitted Facilities) with various banks. 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, 2005, the commitment fees were an annualized 0.11 percent.

On July 14, 2005, the Company amended an existing 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 for an initial period of six months at a rate of 4.54 percent, which is based upon six-month LIBOR plus 70 basis points.

Bridge Loan. On November 17, 2004, an indirect, wholly-owned subsidiary of the Company entered into a $407 million Bridge Loan Agreement (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 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 Bridge Loan in full during February 2005 out of the proceeds from 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.

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 be considered an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:

	(a)	Under the Company’s 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 former Providence Gas and Fall River Gas territories, 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.

F-39

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

14. Employee Benefits

Pension and Other Postretirement Benefits. The Company maintains eight trusteed, non-contributory defined benefit retirement plans (Plans), which cover substantially all its employees, other than employees of Panhandle Energy (see Panhandle Energy, below). The Company funds the cost of the Plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. The Plans’ assets are invested in cash, government securities, corporate bonds and stock, and various funds. The Company also had two supplemental non-contributory retirement plans for certain executive employees and other postretirement benefit plans for its employees. During 2005, one of these supplemental plans was terminated.

The Company’s eight qualified defined benefit retirement Plans cover: (i) those employees who are employed by Missouri Gas Energy; (ii) those employees who are employed by PG Energy and PEI Power; (iii) union employees of (the former) ProvEnergy; (iv) non-union employees of (the former) ProvEnergy; (v) union employees of (the former) Valley Resources; (vi) non-union employees of (the former) Valley Resources; (vii) union employees of (the former) Fall River Gas; and (viii) non-union employees of (the former) Fall River Gas.

Due to the change in year end to December 31, effective with the short fiscal year 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 years ended June 30, 2004 and 2003.

F-40

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pension, postretirement medical and other 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 postretirement benefit plans at December 31, 2005 and December 31, 2004.

	Pension Benefits At						Post-Retirement Benefits At
	December 31,						December 31,
	2005			2004			2005			2004
	(In thousands)
Change in Benefit Obligation:
Benefit obligation at beginning of period	$	398,516		$	386,493		$	168,953		$	152,425
Service cost		7,614			3,689			3,631			2,091
Interest Cost		22,396			11,412			7,594			4,607
Benefits paid		(20,816	)		(10,217	)		(5,121	)		(3,346	)
Actuarial (gain) loss		19,956			9,095			(31,701	)		14,484
Plan amendments		-			446			(28,208	)		(1,308	)
Curtailment recognition		103			-			-			-
Settlement recognition		(12,431	)		(2,402	)		-			-
Benefit obligation at end of period	$	415,338		$	398,516		$	115,148		$	168,953

Change in Plan Assets:
Fair value of plan assets at beginning of period	$	276,835		$	276,154		$	37,962		$	34,004
Return on plan assets		35,936			1,980			1,487			160
Employer contributions		18,765			11,320			11,181			7,144
Benefits paid		(20,816	)		(10,217	)		(5,121	)		(3,346	)
Settlement recognition		(12,431	)		(2,402	)		-			-
Fair value of plan assets at end of period	$	298,289		$	276,835		$	45,509		$	37,962

Funded Status:
Funded status at end of period	$	(117,049	)	$	(121,680	)	$	(69,639	)	$	(130,991	)
Unrecognized net actuarial loss		128,930			130,164			9,404			41,017
Unrecognized prior service cost		9,085			13,439			(23,940	)		3,409
Prepaid/ (accrued) at measurement date		20,966			21,923			(84,175	)		(86,565	)
Contributions subsequent to measurement date		1,184			1,044			3,787			1,815
Net asset (liability) recognized at end of period	$	22,150		$	22,967		$	(80,388	)	$	(84,750	)

Amounts recognized in the Consolidated Balance Sheet:
Prepaid benefit cost	$	29,456		$	28,705		$	-		$	-
Accrued benefit liability		(100,838	)		(101,487	)		(80,388	)		(84,750	)
Intangible asset		8,249			10,923			-			-
Accumulated other comprehensive loss		85,283			84,826			-			-
Net asset (liability) recognized	$	22,150		$	22,967		$	(80,388	)	$	(84,750	)

At the measurement date, the accumulated benefit obligation related to certain of the Company’s pension plans exceeded the fair value of the pension plan assets. As a result, in accordance with SFAS No. 87, Employers’ Accounting for Pensions, the Company recorded a minimum pension liability, with an offset to Accumulated other comprehensive loss.

F-41

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information for pension plans with an accumulated benefit obligation in excess of plan assets:

	Pension Benefits				Post-Retirement Benefits
	December 31,		December 31,		December 31,		December 31,
	2005		2004		2005		2004
	( In thousands)

Projected benefit obligation	$	379,474	$	365,101		N/A		N/A
Accumulated benefit obligation		348,593		332,329	$	115,148	$	168,953
Fair value of plan assets		246,571		229,799		45,509		37,962

The change in the minimum pension liability included in Accumulated other comprehensive loss as of December 31, 2005 decreased by $2.8 million ($1.8 million, net of tax), primarily as a result of the termination of the Southern Union Company Supplemental Retirement Plan. The minimum pension liability as of December 31, 2004 increased by $14.4 million ($8.8 million, net of tax), primarily as a result of the decrease in the discount rate, an increase in benefits earned and lower than assumed investment returns.

The weighted-average assumptions used to determine benefit obligations for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 were as follows:

	Pension Benefits												Post-retirement Benefits
	Year			Six Months			Years						Year			Six Months			Years
	Ended			Ended			Ended						Ended			Ended			Ended
	December 31,			December 31,			June 30,						December 31,			December 31,			June 30,
	2005			2004			2004			2003			2005			2004			2004			2003
Discount rate:
Beginning of year		5.75	%		6.00	%		6.50	%		7.50	%		5.75	%		6.00	%		6.50	%		7.50	%
End of year		5.50	%		5.75	%		6.00	%		6.50	%		5.50	%		5.75	%		6.00	%		6.50	%
Rate of compensation increase
(average)		3.24	%		3.40	%		3.60	%		4.00	%		N/A			N/A			N/A			N/A
Health care cost trend rate		N/A			N/A			N/A			N/A			12.00	%		13.00	%		13.00	%		13.00	%

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

	December 31,						June 30,
	2005			2004			2004			2003

Health care cost trend rate assumed for next year		12.00	%		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

F-42

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net periodic benefit cost for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 includes the following components:

	Pension Benefits												Post-retirement Benefits
	Year			Six Months			Years						Year			Six Months			Years
	Ended			Ended			Ended						Ended			Ended			Ended
	December 31,			December 31,			June 30,						December 31,			December 31,			June 30,
	2005			2004			2004			2003			2005			2004			2004			2003
	(In thousands)

Service cost	$	7,614		$	3,689		$	6,533		$	5,655		$	3,631		$	2,091		$	3,993		$	1,177
Interest cost		22,396			11,412			22,591			22,899			7,594			4,607			8,739			5,579
Expected return on plan		(24,211	)		(12,302	)		(21,477	)		(24,749	)		(2,552	)		(1,100	)		(1,640	)		(1,734	)
Amortization of prior service cost		1,182			744			1,145			790			(854	)		321			266			(65	)
Recognized actuarial (gain) loss		10,213			3,982			8,402			2,433			577			379			485			(234	)
Curtailment recognition		3,172			-			-			-			-			-			-			-
Settlement recognition		(644	)		(386	)		(445	)		(558	)		-			-			-			-
Subtotal		19,722			7,139			16,749			6,470			8,396			6,298			11,843			4,723
Regulatory adjustment		7,521			-			-			-			229			222			44			-
Net periodic benefit cost	$	27,243		$	7,139		$	16,749		$	6,470		$	8,625		$	6,520		$	11,887		$	4,723

In the Distribution segment, the Company recovers certain qualified pension plan and postretirement benefit plan costs through rates to utility customers. Certain utility commissions require that the recovery of pension costs be based on ERISA or other utility commission specific guidelines. The difference between these amounts and pension expense calculated pursuant to FASB 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.

The weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 were as follows:

	Pension Benefits												Post-retirement Benefits
	Year			Six Months			Years						Year			Six Months			Years
	Ended			Ended			Ended						Ended			Ended			Ended
	December 31,			December 31,			June 30,						December 31,			December 31,			June 30,
	2005			2004			2004			2003			2005			2004			2004			2003
Discount rate:
Beginning of year		6.00	%		6.50	%		7.50	%		7.50	%		6.00	%		6.50	%		7.50	%		7.50	%
End of year		5.75	%		6.00	%		6.50	%		7.50	%		5.75	%		6.00	%		6.50	%		7.50	%
Expected return on assets -
tax exempt accounts		9.00	%		9.00	%		9.00	%		9.00	%		7.00	%		7.00	%		7.00	%		9.00	%
Expected return on assets -
taxable accounts		N/A			N/A			N/A			N/A			5.00	%		5.00	%		5.00	%		5.50	%
Rate of compensation increase		3.40	%		3.60	%		4.00	%		5.00	%		N/A			N/A			N/A			N/A
Health cost trend rate		N/A			N/A			N/A			N/A			13.00	%		13.00	%		13.00	%		12.00	%

The Company employs a building block approach in determining the expected long-term rate of return on the Plans’ 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.

F-43

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2005			2004			2004			2003

Health care cost trend rate assumed for next year		13.00	%		13.00	%		13.00	%		12.00	%
Ultimate trend rate		4.75	%		4.75	%		5.00	%		6.00	%
Year that the rate reaches the ultimate trend rate		2012			2012			2011			2006

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	$	1,192	$	(894	)
Effect on accumulated post-retirement benefit obligation	$	12,019	$	(9,527	)

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 cashflows 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.

Pension Plan Asset Information. The assets of the Plans are invested in accordance with several investment practices that emphasize long-term investment fundamentals with an investment objective of long-term growth. The investment practices take into consideration risk tolerance and the asset allocation strategy as described below.

The broad goal and objective of the investment of the Plans’ assets is to ensure that future growth of the assets is sufficient to offset normal inflation plus liability requirements of the Plan’s beneficiaries. 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 and Life Plans’ Asset Information. The assets of the Postretirement Health and Life Plans (Postretirement Plans) are invested in accordance with sound investment practices that emphasize long-term investment fundamentals. The investment committee 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 (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, the Postretirement Plans are expected to earn a long-term return that compares favorably to appropriate market indices.

F-44

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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						Post-retirement Benefits
	October 1, 2004 to			April 1, 2004 to			October 1, 2004 to			April 1, 2004 to
Asset Category	September 30, 2005			September 30, 2004			September 30, 2005			September 30, 2004

Equity securities		74	%		66	%		15	%		18	%
Debt securities		19	%		28	%		37	%		47	%
Other - cash equivalents		7	%		6	%		48	%		35	%
Total		100	%		100	%		100	%		100	%

No Company common stock is included in the equity securities at December 31, 2005. Equity securities included Company common stock in the amount of $19.8 million at December 31, 2004.

Based on the pension plan objectives, asset allocations are maintained 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 ten percent.

Based on the Postretirement Benefit Plan objectives, asset allocations are 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 percent.

The above referenced asset allocations for pension and 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 versus these guidelines as a result of administrative oversight by the Investment Committee.

The Company expects to contribute approximately $20 million to $24 million to its pension plans and approximately $12.6 million to its other post-retirement benefit plans in 2006.

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

			Post-retirement		Post-retirement
			Benefits		Benefits
	Pension		(Gross, Before		(Medicare Part D
Years	Benefits		Medicare Part D)		Subsidy)
	(In thousands)

2006	$	20,762	$	7,212	$	669
2007		21,633		7,008		760
2008		21,692		7,120		862
2009		22,779		7,545		971
2010		23,779		7,843		1,089
2011-2015		135,265		47,658		6,150

F-45

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recently Enacted Legislation. The Medicare Prescription Drug Act was signed into law December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Issued by the FASB in May 2004, FSP FAS 106-2 requires entities to record the impact of the Medicare Prescription Drug Act as an actuarial gain in the postretirement benefit obligation for postretirement benefit plans that provide drug benefits covered by that legislation. Recognition of the effect of Medicare Part D produced a reduction in Projected Benefit Obligation of $39.2 million and a reduction in Net Periodic Benefit Cost of $4.1 million. The effect of this FSP may vary as a result of any future changes to the Company's benefit plans.

Defined Contribution Plan. The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. For Missouri Gas Energy non-union and corporate employees, the Company contributes 50 percent and 75 percent of the first five percent and second five percent, respectively, of the participant’s compensation paid into the Savings Plan. For Missouri Gas Energy union employees, the Company contributes 50 percent of the first seven percent of the participant’s compensation paid into the Savings Plan. For PG Energy, the Company contributes 55 percent of the first four percent of the participant's compensation paid into the Savings Plan. For New England Gas Company’s Fall River operations, the Company contributes 100 percent of the first four percent of non-union employee compensation paid into the Savings Plan and 100 percent of the first three percent of union employee compensation paid into the Savings Plan. For New England Gas Company’s Providence operations, the Company contributes 50 percent of the first ten percent of the participant's compensation paid into the Savings Plan. For New England Gas Company’s Cumberland operations (formerly Valley Resources), the Company contributes 50 percent of the first four percent of the participant's compensation paid into the Savings Plan. Company contributions are 100 percent vested after five years of continuous service for all plans other than Missouri Gas Energy union and New England Gas Company’s Cumberland operations, which are 100 percent vested after six years of continuous service. Company contributions to the Savings Plan during the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 were $4.5 million, $2.4 million, $4.1 million and $2.3 million, respectively.

Effective January 1, 1999, the Company amended the Savings Plan to provide contributions for certain employees who were employed as of December 31, 1998. These contributions were designed to replace certain benefits previously provided under defined benefit plans. Employer contributions to these separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan were determined based on the employee’s age plus years of service plus accumulated sick leave as of December 31, 1998. The contribution amounts are determined as a percentage of compensation and range from 3.5 percent to 8.5 percent. Company contributions to Retirement Power Accounts during the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003 were $4.8 million, $2.9 million, $5.1 million and $1.5 million, respectively.

Panhandle Energy. Following its June 11, 2003 acquisition by Southern Union, Panhandle Energy continues to provide certain retiree benefits through employer contributions to a qualified defined contribution plan, which range from four percent to six percent of the participating employee’s salary based on the participating employee’s age and years of service. The adoption of the postretirement benefit (OPEB) plan resulted in the recording of a $42.8 million liability as of June 12, 2003 and Panhandle Energy continues to fund the plan at approximately $7.8 million per year. Because Panhandle Energy’s retirement eligible active employees as of June 12, 2003 have primary coverage through a benefit they are eligible to receive from the former owner of Panhandle Energy, no liability is currently recognized for these employees under the OPEB plan.

Following its acquisition by the Company in June 2003, Panhandle Energy initiated a workforce reduction initiative designed to reduce the workforce by approximately five percent. The workforce reduction initiative was an involuntary plan with a voluntary component, and was fully implemented by September 30, 2003.

In conjunction with Southern Union’s investment in CCE Holdings, and CCE Holdings’ acquisition of CrossCountry Energy, Panhandle Energy initiated an additional workforce reduction plan designed to reduce the workforce by approximately an additional six percent. Certain of the approximately $7.7 million of the resulting severance and related costs are reimbursable by CCE Holdings pursuant to agreements between the parties involved, with the reimbursable portion totaling approximately $6 million.

F-46

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2005 and December 31, 2004, 826,348 and 1,198,034 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.

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 will not have a material effect on the Company’s consolidated financial statements.

15. Taxes on Income

	Year		Six Months		Years
	Ended		Ended		Ended
	December 31,		December 31,		June 30,
Income Tax Expense	2005		2004		2004		2003
	(In thousands)
Current:
Federal	$	7,155	$	1,761	$	1,497	$	(15,258	)
State		2,511		84		151		(6,563	)
		9,666		1,845		1,648		(21,821	)

Deferred:
Federal		56,402		10,953		60,380		38,926
State		4,809		1,129		7,075		7,168
		61,211		12,082		67,455		46,094

Total income tax expense from
continuing operations	$	70,877	$	13,927	$	69,103	$	24,273

F-47

Table of Contents

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	2005			2004
	(In thousands)
Deferred income tax assets:
Alternative minimum tax credit	$	26,089		$	24,352
Insurance accruals		3,024			2,268
Bad debt reserves		4,952			4,866
Post-retirement benefits		21,198			17,326
Minimum pension liability		34,017			39,909
NOL carry-forward		-			12,434
Unconsolidated investments		-			11,942
Other		45,913			58,419
Total deferred income tax assets		135,193			171,516
Valuation allowance		-			(11,942	)
Net deferred income tax assets		135,193			159,574

Deferred income tax liabilities:
Property, plant and equipment		(448,359	)		(427,380	)
Unconsolidated investments		(7,961	)		-
Unamortized debt expense		(5,686	)		(5,991	)
Regulatory liability		(14,620	)		(15,358	)
Other		(45,622	)		(48,341	)
Total deferred income tax liabilities		(522,248	)		(497,070	)
Net deferred income tax liability		(387,055	)		(337,496	)
Less current income tax assets		9,435			27,998
Accumulated deferred income taxes	$	(396,490	)	$	(365,494	)

Deferred credits in the accompanying Consolidated Balance Sheet include $4.7 million and $5.2 million of unamortized deferred investment tax credit as of December 31, 2005 and December 31, 2004, respectively.

Deferred taxes have been established for the difference between the book and tax basis of the Company’s investment in CCE Holdings. The difference generated a deferred tax asset of $11.9 million at December 31, 2004. The Company has also recorded an offsetting valuation allowance of $11.9 million. The Company determined that this valuation allowance was no longer necessary because the book income from CCE Holdings was substantially greater than taxable income for 2005 and will continue to be in the foreseeable future.

Southern Union completed an analysis of its deferred tax accounts in 2005. As a result of this analysis, income tax expense for the year ending December 31, 2005 has been decreased $6.4 million comprised of federal and state income taxes of $4.8 million and $1.6 million, respectively, primarily due to adjustments related to bad debt reserves and PP&E.

F-48

Table of Contents

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			Six Months			Years
	Ended			Ended			Ended
	December 31,			December 31,			June 30,
Effective Income Tax Rate Analysis	2005			2004			2004			2003
	(In thousands)
Computed statutory income tax expense
from continuing operations at 35%	$	32,046		$	10,044		$	64,095		$	23,780
Changes in income taxes resulting from:
Goodwill impairment charge		61,250			-			-			-
Valuation allowance		(11,942	)		11,942			-			-
Dividend received deduction		(8,731	)		(9,800	)		-			-
State income taxes, net of federal income tax benefit		4,757			788			4,697			326
Analysis of deferred tax accounts		(4,757	)		-			-			-
Investment Tax Credit amortization		(422	)		(210	)		(424	)		(421	)
Other		(1,324	)		1,163			735			588
Actual income tax expense from continuing operations	$	70,877		$	13,927		$	69,103		$	24,273

16. Regulation and Rates

Panhandle Energy. In December 2002, FERC approved a Trunkline LNG certificate application to expand the Lake Charles LNG terminal facility to approximately 1.2 Bcf per day of sustainable send out capacity and to increase terminal storage capacity to 9 Bcf from the current 6.3 Bcf. BG LNG Services has contract rights for the .57 Bcf per day of additional capacity. Construction on the Trunkline LNG expansion project (Phase I) commenced in September 2003 and is expected to be completed at an estimated cost of $137 million, plus capitalized interest, late in the first quarter or early in the second quarter of 2006. The expanded vaporization capacity portion of the expansion was placed into service on September 18, 2005. On September 17, 2004, as modified on September 23, 2004, the FERC approved Trunkline LNG’s further incremental expansion project (Phase II). Phase II is estimated to cost approximately $82 million, plus capitalized interest, and will increase the LNG terminal’s sustainable send out capacity to 1.8 Bcf per day. Phase II has an expected in-service date of mid-2006. BG LNG Services has contracted for all the proposed additional capacity, subject to Trunkline LNG achieving certain construction milestones at the facility. Approximately $35 million and $127 million of expansion project costs are included in the line item Construction work-in-progress through December 31, 2005 and December 31, 2004, respectively.

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. 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 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 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 $15 - $25 million per year, inclusive of remediation costs.

F-49

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Missouri Gas Energy. On September 21, 2004, the MPSC issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22.4 million, effective October 2, 2004. The rate order, based on a 10.5 percent return on equity, also produced an improved rate design and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between customers and the Company.

On October 20, 2004, Missouri Gas Energy filed a writ of review with the Cole County Circuit Court regarding the MPSC’s October 2004 rate order. Missouri Gas Energy is seeking base revenues in addition to the increase cited above on grounds that the capital structure and 10.5 percent return on equity used by the MPSC in determining such increase do not provide an adequate rate of return. Upon judicial review, the Cole County Circuit Court issued an opinion in March 2005 agreeing with Missouri Gas Energy’s claims and remanding the matter to the MPSC for reconsideration. On April 8, 2005, the MPSC appealed the Cole County Circuit Court’s ruling to the Missouri Court of Appeals - Western District. By its opinion of December 27, 2005, the Court of Appeals reversed the decision of the Circuit Court and affirmed the decision of the MPSC. Missouri Gas Energy is in the process of filing an Application for Transfer with the Missouri Supreme Court. The $22.4 million increase in base revenues under the MPSC’s October 2004 rate order continues to be in effect and may only be increased by a subsequent decision of the MPSC on remand. Any impact of a subsequent appellate or MPSC decision should be prospective in nature, and the Company cannot currently predict the outcome of this matter.

Through filings made on various dates, the staff of the MPSC has recommended that the MPSC disallow a total of approximately $38.5 million in gas costs incurred during the period July 1, 1997 through June 30, 2003. Missouri Gas Energy disputes the basis of $32.1 million of the total proposed disallowance which appears to be the same as was rejected by the Commission 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. Missouri Gas Energy also disputes the basis of $3 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 $3.4 million of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003; a hearing is expected during 2006.

New England Gas Company. On May 22, 2003, the Rhode Island Public Utility Commission (RIPUC) approved a Settlement Offer filed by New England Gas Company related to the final calculation of earnings sharing for the 21-month period covered by the Energize Rhode Island Extension settlement agreement. This calculation generated excess revenues of $5.3 million. The net result of the excess revenues and the Energize Rhode Island weather mitigation and non-firm margin sharing provisions was the crediting to customers of $949,000 over a 12-month period that ended June 30, 2004.

On May 24, 2002, the RIPUC approved a settlement agreement between the New England Gas Company and the Rhode Island Division of Public Utilities and Carriers. The settlement agreement resulted in a $3.9 million decrease in base revenues for New England Gas Company’s Rhode Island operations, a unified rate structure ("One State; One Rate") and an integration/merger savings mechanism. The settlement agreement also allows New England Gas Company to retain $2.0 million of merger savings and to share incremental earnings with customers when the Rhode Island operations’ return on equity exceeds 11.25 percent. Included in the settlement agreement was a conversion to therm billing and the approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows New England Gas Company to continue its low income assistance and weatherization programs and to recover environmental response costs over a ten-year period, establishes a new weather normalization clause and allows for the sharing of non-firm margins (which is margin earned from interruptible customers with the ability to switch to alternative fuels). The weather normalization clause is designed to mitigate the impact of weather volatility on customer billings, which will assist customers in paying bills and stabilize the revenue stream. New England Gas Company will defer the margin impact of weather that is greater than two percent colder-than-normal and will recover the margin impact of weather that is greater than two percent warmer-than-normal. The non-firm margin incentive mechanism allows New England Gas Company to retain 25 percent of all non-firm margins earned in excess of $1.6 million.

F-50

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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: 2006—$21.7 million; 2007—$19.5 million; 2008—$14.5 million; 2009—$11.6 million; 2010— $10.8 million and thereafter $29.1 million. Rental expense was $20.1 million, $9.5 million, $17.8 million and $4.3 million for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, 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 is currently updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

The Company follows the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, Environmental Remediation Liabilities, for recognition, measurement, display and disclosure of environmental remediation liabilities.

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions. 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, 2005 and 2004 to cover probable environmental response actions:

	December 31,
	2005		2004
	(In thousands)

Current	$	6,541	$	4,421
Noncurrent		27,274		25,919
Total Environmental Liabilities	$	33,815	$	30,340

During 2005, the Company spent $10.1 million related to environmental cleanup programs.

F-51

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems. Panhandle Energy 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 Energy has developed and is implementing a program to remediate such contamination. Remediation and decontamination has been completed at 26 of 35 compressor station sites where auxiliary buildings that house the air compressor equipment have been 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. Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties. In some instances, such as the Pierce Waste Oil sites described below, the Company may share liability associated with contamination with other potentially responsible parties, The Company may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Panhandle Eastern Pipe Line 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. Panhandle Eastern Pipe Line and Trunkline received notices of potential liability from the United States Environmental Protection Agency (U.S. EPA) for the Dunavan site. The notice demanded reimbursement to the U.S. EPA for all its 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 provided 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 Panhandle Eastern Pipe Line 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 consolidated financial position, results of operations or cash flows.

On June 16, 2005, Panhandle Eastern Pipe Line 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, initially reported as 45 gallons, of hydrocarbons reached the Mississippi River. Panhandle Eastern Pipe Line 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. Panhandle Eastern Pipe Line has resolved potential claims of affected boat owners and the marina operator. Panhandle Eastern Pipe Line received a violation notice from the Illinois Environmental Protection Agency (Illinois EPA) alleging that Panhandle Eastern Pipe Line is 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 Panhandle Eastern Pipe Line that the matter may 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. 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.

F-52

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Air Quality Control. U.S. EPA issued a final rule on regional ozone control (NOX SIP Call) in April 2004 that impacts Panhandle Energy in two Midwestern states, Indiana and Illinois. Based on a U.S. EPA guidance document negotiated with gas industry representatives in 2002, Panhandle Energy will be required in states that follow the U.S. 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 the company 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 the Panhandle Energy system in Illinois and Indiana with an approximate cost of $20 million for capital improvements through 2007, based on current projections. Approximately $16 million of the $20 million of capital expenditures have been incurred as of December 31, 2005. Indiana has promulgated state regulations to address the requirements of the NOx SIP Call rule that essentially follow the U.S. EPA guidance.

The Illinois EPA has distributed several draft versions of a rule to control NOx emissions from reciprocating engines and turbines state-wide. 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, 2009. 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 early 2006. The rule is currently being reviewed for potential impact to Panhandle Energy. As drafted, the rule applies to all Panhandle Eastern Pipe Line and Trunkline stations in Illinois and significant expenditures in addition to the $20 million associated with NOx reductions above would be required for emission control.

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 $17 million will be needed at the two affected Texas locations. Approximately $6 million of the $17 million of capital expenditures have been incurred as of December 31, 2005.

The U.S. EPA promulgated various Maximum Achievable Control Technology rules in February 2004. The rules require that Panhandle Eastern Pipe Line and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources. Most Panhandle Eastern Pipe Line and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for Panhandle Eastern Pipe Line 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. Panhandle Eastern Pipe Line and Trunkline have approximately 20 internal combustion engines subject to the rules. Management expects that compliance with these regulations will necessitate an estimated expenditure of $1.7 million for capital improvements, based on current projections.

Spill Control. Environmental regulations were recently modified for U.S. EPA’s Spill Prevention, Control and Countermeasures 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 be reasonably 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.

F-53

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Distribution Segment Environmental Matters.

Like others in the gas distribution industry, the Company is responsible for environmental remediation at various contaminated sites that are primarily associated with Manufactured Gas Plants (MGPs) and sites associated with the operation and disposal activities from MGPs. MGPs produced a fuel known as “town gas”. Some constituents of the manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these constituents are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required. These 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 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 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.

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. Management believes the final disposition of these proceedings will not have a material adverse effect on the Company’s 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 New England Gas Company a letter of responsibility pertaining to alleged historical MGP impacted soils in a residential neighborhood along Bay and Judson Streets (Bay Street Area) in Tiverton, Rhode Island. The letter requested that New England Gas Company perform a site investigation of the Bay Street Area. 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. Three lawsuits were filed against New England Gas Company in Rhode Island state court in 2005, asserting claims for damages as a result of previous events that occurred in Tiverton, Rhode Island. 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 all three lawsuits to Rhode Island federal court and filed Motions to Dismiss, which are currently pending. On or about September 19, 2005, the Company was served with a fourth lawsuit, also with similar claims, filed in the Superior Court of Bristol County, Massachusetts on behalf of 17 plaintiffs. The case was removed to Massachusetts federal court and then transferred to Rhode Island federal court. The Company will vigorously defend itself against all four lawsuits. Parts of the Bay Street Area 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 potentially responsible parties associated with the fill materials and the waste disposal. 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 operation 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. Mercury had also been removed by the vandals from the Pawtucket facility and a quantity had been released in a parking lot in the neighborhood. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup has been completed at the property and nearby apartment units. Investigation of some other neighborhood properties has been undertaken, with cleanup necessitated and completed in a few instances. State and federal authorities are also investigating the incident and have arrested the alleged vandals of the Pawtucket facility. In addition, inquiries are being conducted regarding New England Gas Company's compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and hazard communication requirements. New England Gas Company received and complied with a subpoena requesting documents relating to this matter. On January 20, 2006 a complaint was filed against New England Gas Company by plaintiffs in the Superior Court of Providence, Rhode Island regarding mercury release at 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 filed by plaintiffs is currently pending. 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.

F-54

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Hope Land. Hope Land Mineral Corporation (Hope Land) contends that it owns the storage rights to property that contains a portion of Panhandle Energy’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 Panhandle Energy and dismissed the case. Panhandle Energy 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 Panhandle Energy to prevent running of the statute of limitations. Panhandle Energy then filed an action for condemnation to obtain the storage rights from Hope Land. Pursuant to a pre-filing settlement with Hope Land, Panhandle Energy obtained legal title to the storage rights upon the filing of the condemnation action. As a result, the only issue to be determined at trial is the value of such rights and the amount of trespass damages to which Hope Land is entitled. The trial court has not yet issued a scheduling order, but Panhandle Energy expects the trial to be scheduled for the second quarter of 2006. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Panhandle Energy, 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. On May 13, 2005, the Special Master in this case issued a recommended decision that would, if adopted by the District Judge, result in dismissal of Panhandle Energy from the case. A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle Energy, in U.S. District Court for the District of Kansas. Panhandle Energy is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action. Panhandle Energy believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which was filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to the complaints (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle Energy complied with the terms of its tariff) and is defending the suits vigorously. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 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 whether the Company ultimately will collect such amounts.

F-55

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Commitments and Contingencies.

Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast after coming through the Gulf of Mexico. These hurricanes caused modest damage to property and equipment owned by 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. For 2005, Panhandle Energy recorded lower revenues of approximately $3 million and expense increases of $7 million. Incremental capital outlays of approximately $900,000 were recorded in 2005, with additional estimated capital outlays of approximately $20 million expected to be incurred in 2006, prior to any insurance recoveries. Estimated expenses and capital outlays primarily include repair and replacement of equipment lost or damaged in the hurricanes, potential abandonment costs for certain facilities, which will be impacted by producer decisions regarding rebuilding their damaged platforms and reconnecting their gas reserves to Panhandle Energy’s pipelines, higher insurance premiums, higher LNG terminal construction costs, as well as employee assistance related expenses. The revenue losses relate primarily to reduced volumes on Sea Robin, which are expected to continue into 2006. Hurricane impacts have resulted in delays in the completion of Trunkline LNG’s Phase I and Phase II expansions from the original completion dates. Additionally, Panhandle Energy anticipates reimbursement from its property insurance carrier for damages from Hurricane Rita in excess of its $5 million deductible.

At December 31, 2005, the Company has 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 $2.53 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.

In connection with the acquisition of PG Energy, the Company assumed 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 (together 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 the 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, 2005, the balance outstanding on the TIF Debt was $7.2 million with an interest rate of 6.5 percent. Estimated incremental tax revenues are expected to cover approximately 65 percent of the 2006 annual debt service. Based on information available at this time, the Company believes that the $4.0 million amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2005.

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. Panhandle Eastern Pipe Line 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, Panhandle Eastern Pipe Line and Trunkline may file with FERC to recover these costs from pipeline customers. Management believes these commitments and contingencies will not have a material adverse effect on the Company’s consolidated financial condition, results of operations or cash flows.

F-56

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Effective April 1, 2004, the Company agreed to a three-year contract with a bargaining unit representing a portion of the PG Energy employees. Effective, August 1, 2003, the Company agreed to a three-year contract with another bargaining unit representing the remaining PG Energy unionized employees.

Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a bargaining unit representing Panhandle Energy employees.

During the year ended June 30, 2003, the bargaining unit representing certain employees of New England Gas Company’s Cumberland operations (formerly Valley Resources) was merged with the bargaining unit representing the employees of the Company’s Fall River operations (formerly Fall River Gas).

Of the Company’s employees represented by unions, Missouri Gas Energy employs 36 percent, New England Gas Company employs 33 percent, Panhandle Energy employs 18 percent and PG Energy employs 13 percent.

The Company had standby letters of credit outstanding of $8.0 million and $8.6 million at December 31, 2005 and December 31, 2004, respectively, which guarantee payment of insurance claims and other various commitments.

19. Discontinued Operations

Effective January 1, 2003, the Company completed the sale of its Texas Operations to ONEOK for approximately $437 million in cash resulting in a pre-tax gain of $63 million. In accordance with GAAP, the results of operations and gain on sale have been segregated and reported as Discontinued operations in the Consolidated Statement of Operations.

The following table summarizes the Texas Operations’ results of operations that have been segregated and reported as Discontinued operations in the Consolidated Statement of Operations:

	Year Ended
	June 30,
	2003
	(In thousands)

Operating revenues	$	144,490
Operating income	$	21,602
Net earnings from discontinued operations (a)	$	32,520

_________________________________

(a) In accordance with GAAP, net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs. All outstanding debt of Southern Union and its subsidiaries was maintained at the corporate level at the time of the sale, and no debt was assumed by ONEOK, Inc. in the sale of the Texas Operations.

20. Quarterly Operations (Unaudited)

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	$	767,556	$	305,164	$	255,047	$	691,663
Operating income (loss)		155,582		31,076		40,289		(63,903	)
Net earnings (loss) from continuing operations		92,196		15,676		19,590		(106,779	)
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: ⁽¹⁾
Continuing operations		0.81		0.10		0.13		(1.00	)
Available for common stockholders		0.81		0.10		0.13		(1.00	)

(1) The sum of earnings per share by quarter may not equal the net earnings per common and common share equivalents for the year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.

The following table presents the operating results for each quarter of the six-month transition period ended December 31, 2004:

	Quarters Ended
	September 30			December 31
	(In thousands, except per share amounts)

Operating revenues	$	234,576		$	559,762
Operating income		18,794			88,137
Net earnings (loss) from continuing
operations		(7,140	)		21,911
Net earnings (loss) available for
common stockholders		(11,481	)		17,569
Diluted net earnings (loss) per share
available for common stockholders: ⁽¹⁾
Continuing operations		(0.14	)		0.19
Available for common stockholders		(0.14	)		0.19

F-57

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the operating results for each quarter of the year ended June 30, 2004:

	Quarters Ended
	September 30			December 31		March 30		June 30
	(In thousands, except per share amounts)

Operating revenues	$	231,351		$	507,066	$	774,551	$	286,806
Operating income		23,936			95,330		150,337		35,724
Net earnings (loss) from continuing
operations		(3,707	)		38,422		75,367		3,943
Net earnings (loss) available for
common stockholders		(3,707	)		34,418		71,026		(398	)
Diluted net earnings (loss) per share
available for common stockholders: ⁽¹⁾
Continuing operations		(0.05	)		0.42		0.87		-
Available for common stockholders		(0.05	)		0.42		0.87		-

21. Reportable Segments

The Company’s operating segments are aggregated into reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in two reportable segments. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and the Company’s equity investment in CCE Holdings. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through the Company’s three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company.

Revenue included in the Corporate and other category is attributable to several operating subsidiaries of the Company: PEI Power Corporation, which generates and sells electricity; PG Energy Services Inc., which offers appliance service contracts; ProvEnergy Power Company LLC (ProvEnergy Power), which prior to its sale on October 31, 2003 provided outsourced energy management services and owned 50 percent of Capital Center Energy Company LLC, a joint venture formed between ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air; and Alternate Energy Corporation, which provided energy consulting services. None of these businesses have ever met the quantitative thresholds for determining reportable segments individually or in the aggregate. Except for revenue associated with the Management Agreement with CCE Holdings, the Company’s corporate operations do not generate any revenues. For more information about the Management Agreement, see Note 23, Related Party Transactions.

F-58

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company evaluates segment performance based on several factors, of which the primary financial measure, beginning January 1, 2005, is earnings before interest and taxes (EBIT). Evaluating segment performance based on EBIT is a change from utilizing operating income in prior periods. Due to the significance of the operating results of the Company’s November 2004 investment in CCE Holdings, which are included in Earnings from unconsolidated investments, management felt that EBIT would allow management and investors to more effectively evaluate the performance of all of the Company’s consolidated subsidiaries and unconsolidated investments. Accordingly, prior period segment performance information has been conformed to the current period presentation. 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.

Prior to the acquisition of Panhandle Energy and the Company’s investment in CCE Holdings, the Company was primarily engaged in the natural gas distribution business and considered its operations to consist of one reportable segment. As a result of the acquisition of Panhandle Energy and its subsequent investment in CCE Holdings, management assessed the manner in which financial information is reviewed in making operating decisions and assessing performance, and concluded that Panhandle Energy’s operations and its investment in CCE Holdings (Transportation and Storage) and the Company’s regulated utility operations (Distribution) would be treated as two separate and distinct reportable segments. During the year ended June 30, 2003, the Company reported its Texas Operations as discontinued operations. Accordingly, the Distribution segment results exclude the results of the Texas Operations for all periods presented.

F-59

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth certain selected financial information for the Company’s segments for the year ended December 31, 2005, the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003. Financial information for the Transportation and Storage segment reflects the operations of Panhandle Energy beginning on its acquisition date of June 11, 2003 and the Company’s equity investment in CCE Holdings beginning on its acquisition date of November 17, 2004.

	Year			Six Months			Years
	Ended			Ended			Ended
	December 31,			December 31,			June 30,
Segment Data	2005			2004			2004			2003
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	505,233		$	242,743		$	490,883		$	24,522
Distribution		1,503,272			549,346			1,304,405			1,158,964
Total segment operating revenues		2,008,505			792,089			1,795,288			1,183,486
Corporate and other		10,925			2,249			4,486			5,014
	$	2,019,430		$	794,338		$	1,799,774		$	1,188,500

Depreciation and amortization:
Transportation and Storage	$	62,171		$	30,159		$	59,988		$	3,197
Distribution		63,278			32,511			57,601			56,396
Total segment depreciation and amortization		125,449			62,670			117,589			59,593
Corporate and other		944			706			1,166			1,049
	$	126,393		$	63,376		$	118,755		$	60,642

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	70,618		$	4,761		$	200		$	7
Corporate and other		124			(16	)		-			415
	$	70,742		$	4,745		$	200		$	422

Other income (expense), net:
Transportation and Storage	$	571		$	89		$	7,210		$	64
Distribution		(1,452	)		(66	)		1,944			2,209
Total segment other income (expense), net		(881	)		23			9,154			2,273
Corporate and other		(6,188	)		(18,103	)		(3,686	)		15,706
	$	(7,069	)	$	(18,080	)	$	5,468		$	17,979

Segment performance:
Transportation and Storage EBIT	$	281,344		$	94,971		$	200,912		$	9,699
Distribution EBIT		(43,928	)		19,330			120,838			144,971
Total segment EBIT		237,416			114,301			321,750			154,670
Corporate and other		(10,699	)		(20,705	)		(10,755	)		6,095
Interest		135,157			64,898			127,867			83,343
Dividends on preferred securities of subsidiary trust		-			-			-			9,480
Federal and state income taxes		70,877			13,927			69,103			24,273
Net earnings from discontinued operations		-			-			-			32,520
Preferred stock dividends		17,365			8,683			12,686			-
Net earnings	$	3,318		$	6,088		$	101,339		$	76,189

F-60

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year		Six Months		Years
	Ended		Ended		Ended
	December 31,		December 31,		June 30,
Segment Data	2005		2004		2004		2003
	(In thousands)
Total assets:
Transportation and Storage	$	3,155,549	$	2,348,354	$	2,197,289	$	2,212,467
Distribution		2,490,164		2,448,750		2,231,970		2,243,257
Total segment assets		5,645,713		4,797,104		4,429,259		4,455,724
Corporate and other		191,106		771,185		143,199		135,214
Total consolidated assets	$	5,836,819	$	5,568,289	$	4,572,458	$	4,590,938

Expenditures for long-lived assets:
Transportation and Storage	$	189,415	$	111,886	$	131,378	$	5,128
Distribution		84,896		56,442		78,791		67,327
Total segment expenditures for
long-lived assets		274,311		168,328		210,169		72,455
Corporate and other		2,306		10,109		15,884		7,275
Total consolidated expenditures for
long-lived assets	$	276,617	$	178,437	$	226,053	$	79,730

Significant Customers and Credit Risk. The following table provides information related to Panhandle Energy’s significant customers:

	Percent of						Percent of
	Transportation and						Company Total
	Storage Segment						Operating
	Revenues						Revenues
	For Year			For Six			For Year			For Six
	Ended			Months Ended			Ended			Months Ended
	December 31,			December 31,			December 31,			December 31,
Customer	2005			2004			2005			2004

BG LNG Services		17	%		16	%		4	%		5	%
ProLiance		16			17			4			5
Ameren Corp		11			11			3			3
CMS Energy and affiliates		8			9			2			3
Other top 10 customers		14			14			4			5
Remaining customers		34			33			8			10
Total percentage		100	%		100	%		25	%		31	%

F-61

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

22. Transition Period Comparative Data

The following table presents certain summarized financial information for the six months ended December 31, 2004 and 2003:

	Six Months Ended December 31,
	2004			2003
	(In thousands, except shares and per share amounts)
				(Unaudited)

Operating revenues	$	794,338		$	738,417

Operating income		106,931			119,266

Earnings before income taxes		28,698			57,077

Federal and state income taxes		(13,927	)		(22,362	)

Net earnings		14,771			34,715

Preferred stock dividends		(8,683	)		(4,004	)

Net earnings available for common stockholders	$	6,088		$	30,711

Net earnings available for common stockholders per share:
Basic	$	0.07		$	0.38
Diluted		0.07			0.37

Weighted average shares outstanding:
Basic		87,313,787			81,649,310
Diluted		89,717,427			82,531,182

23. Related Party Transactions

On November 5, 2005, SU Pipeline Management LP (Manager), a wholly-owned subsidiary of Southern Union, and Panhandle Eastern Pipe Line entered into an Administrative Services Agreement (Management Agreement) with CCE Holdings. Pursuant to the Management Agreement, Manager will provide administrative services to CCE Holdings and its subsidiaries. Manager will be responsible for all administrative and ministerial services not reserved to the executive committee or members of CCE Holdings. For performing these functions, CCE Holdings will reimburse Manager for certain defined operating and transition costs, and under certain circumstances may pay Manager an annual management fee. Transition costs are non-recurring costs of establishing the shared services pursuant to the Management Agreement, including but not limited to severance costs, professional fees, certain transaction costs, and the costs of relocating offices and personnel. Management fees are to be calculated based on a percentage of the amount by which certain earnings targets, as previously determined by the executive committee, are exceeded. Accrued management fees for 2005 totaled $4.3 million. No management fees were due under the Management Agreement for the period prior to 2005.

In 2004, following its investment in CCE Holdings, Southern Union billed CCE Holdings $1.8 million for certain corporate costs provided under the Management Agreement. In addition, transition costs of $6.0 million were charged to CCE Holdings by Panhandle Eastern Pipe Line. This amount, representing mainly severance and related costs, was recorded as a liability by Panhandle Eastern Pipe Line with an offsetting amount recorded in Accounts receivable - related parties. In 2005, Southern Union billed CCE Holdings $12.0 million for certain corporate costs provided under the Management Agreement.

At December 30, 2005, CCE Holdings paid CCE Acquisition LLC, a wholly-owned subsidiary of the Company, a distribution totaling $15 million. Such distribution was reflected as a return of investment by the Company.

At December 31, 2004, the Company held receivables outstanding with certain executives totaling approximately $2.7 million. All such balances were settled during 2005.

F-62

Table of Contents

24. Subsequent Events

On March 1, 2006, Southern Union completed the acquisition of Sid Richardson Energy Services, Ltd. and related entities. On February 15, 2006 and January 26, 2006, Southern Union entered into definitive agreements to sell the Rhode Island operations of its New England Gas Company division and the assets of its PG Energy natural gas distribution division, respectively. For additional information, see Note 3 - Acquisitions and Sales.

F-63

Table of Contents

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 December 31, 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and audits of its June 30, 2004 and 2003 consolidated financial statements 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, 2005 and 2004, and the results of their operations and their cash flows for the year ended December 31, 2005, the six month period ended December 31, 2004 and each of the two years in the period 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.

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, 2005 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, 2005, 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2006

F-64

Table of Contents

CCE Holdings, LLC

and Subsidiaries

Year ended December 31, 2005 and the period from inception (May 14, 2004) to December 31, 2004

with Report of Independent Registered Public Accounting Firm

Table of Contents

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firm	1


Audited Consolidated Financial Statements
Consolidated Balance Sheets	2
Consolidated Statements of Operations	3
Consolidated Statements of Members’ Equity	4
Consolidated Statements of Cash Flows	5
Notes to Consolidated Financial Statements	6-29

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Executive Committee of CCE Holdings, LLC and Subsidiaries:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of CCE Holdings, LLC and its subsidiaries (collectively, “the Company”) at December 31, 2005 and 2004, and the results of their operations and their cash flows for the year ended December 31, 2005 and the period from inception (May 14, 2004) through December 31, 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2006

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)

	December 31,			December 31,
	2005			2004
ASSETS

Current Assets
Cash and cash equivalents	$	31,904		$	5,821
Accounts receivable - customers, net of allowance of $98 and $0 in 2005 and 2004, respectively		20,357			20,248
Accounts receivable - associated companies		4,258			12,673
Transportation and exchange gas receivable		4,812			3,406
Other		8,652			11,930
Total Current Assets		69,983			54,078

Property, Plant and Equipment, at Cost
Plant in service		1,092,551			911,174
Construction work in progress		7,419			100,420
Less - Accumulated depreciation and amortization		(25,627	)		(2,777	)
Property, Plant and Equipment, Net		1,074,343			1,008,817

Other Assets
Investment in unconsolidated affiliate		1,010,440			998,549
Goodwill		113,289			129,042
Regulatory assets		64,869			63,321
Other		50,933			58,170
Total Other Assets		1,239,531			1,249,082

Total Assets	$	2,383,857		$	2,311,977


LIABILITIES AND MEMBERS’ EQUITY

Current Liabilities
Accounts payable - trade and other	$	5,419		$	14,700
Accounts payable - associated companies		11,094			10,739
Transportation and exchange gas payable		5,140			3,106
Accrued taxes, other than income		6,008			6,051
Accrued interest		5,410			5,188
Other		16,357			24,684
Total Current Liabilities		49,428			64,468

Deferred Credits		14,092			2,907

Long-term Debt		1,020,000			1,055,000

Commitments and Contingencies (Note 10)

Members’ Equity		1,300,337			1,189,602

Total Liabilities and Members’ Equity	$	2,383,857		$	2,311,977

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(In Thousands)

	Year Ended			From Inception (May 14, 2004) to
	December 31,			December 31,
	2005			2004

Revenues
Transportation	$	187,274		$	22,361
Gas and liquids sold and other		49,085			4,833

Total Revenues		236,359			27,194


Costs and Expenses
Operating and maintenance expenses		69,474			15,709
Amortization of regulatory assets		4,394			566
Depreciation and amortization		30,401			3,414
Taxes, other than income taxes		11,090			929

Total Costs and Expenses		115,359			20,618


Operating Income		121,000			6,576

Other Income (Expense)
Equity in earnings of unconsolidated affiliate		72,492			7,549
Interest expense and related charges, net		(58,143	)		(5,589	)
Other, net		5,386			66

Total Other Income		19,735			2,026

Net Income	$	140,735		$	8,602

_________________________________________________________________________________________

See accompanying notes.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

(In Thousands)

	Southern						Other Class B
	Union			GE			Interests
	(50.00%)			(30.02%)			(19.98%)			Total

Balance, at Inception (May 14, 2004)	$	-		$	-		$	-		$	-

Members’ contributions		590,500			590,500			-			1,181,000

Sale to Minority Interests		-			(235,964	)		235,964			-

Net income		4,301			2,583			1,718			8,602

Balance, December 31, 2004		594,801			357,119			237,682			1,189,602

Net income		70,367			42,249			28,119			140,735

Distribution to Members		(15,000	)		(9,006	)		(5,994	)		(30,000	)

Balance, December 31, 2005	$	650,168		$	390,362		$	259,807		$	1,300,337

_________________________________________________________________________________________

See accompanying notes.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended			From Inception (May 14, 2004) to
	December 31,			December 31,
	2005			2004
Cash Flows From Operating Activities
Net income	$	140,735		$	8,602
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		30,401			3,414
Amortization of regulatory assets		4,394			566
Equity in earnings of unconsolidated affiliate		(72,492	)		(7,549	)
Distributions received from unconsolidated affiliate		60,600			-
Other assets and liabilities, noncash adjustments		4,721			107
Amortization of debt costs		3,754			481
Changes in operating assets and liabilities:
Accounts receivable		8,306			(7,487	)
Transportation and exchange gas receivable		(1,406	)		(282	)
Accounts payable		(14,716	)		13,816
Transportation and exchange gas payable		2,034			(3,190	)
Accrued taxes		(43	)		246
Accrued interest		222			4,864
Other current assets and liabilities		6,066			10,233
Net Cash Provided by Operating Activities		172,576			23,821

Cash Flows From Investing Activities
Acquisition of CrossCountry Energy, LLC, net of cash acquired		-			(2,024,147	)
Other capitalized Acquisition costs		10,478			(5,032	)
Additions to property, plant and equipment		(88,121	)		(23,048	)
Other capital expenditures		(2,472	)		(184	)
Proceeds from sale of subsidiaries		-			175,000
Net Cash Used in Investing Activities		(80,115	)		(1,877,411	)

Cash Flows From Financing Activities
Members’ contributions		-			1,181,000
Debt proceeds		20,000			1,055,000
Debt repayments		(55,000	)		(352,000	)
Debt issuance costs		(1,378	)		(24,589	)
Member distributions		(30,000	)		-
Net Cash (Used in) Provided by Financing Activities		(66,378	)		1,859,411

Increase in Cash and Cash Equivalents		26,083			5,821

Cash and Cash Equivalents at Beginning of Period		5,821			-

Cash and Cash Equivalents, End of Period	$	31,904		$	5,821


Supplemental Disclosure of Cash Flow Information
Interest paid	$	54,736		$	810

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Basis of Presentation and Significant Accounting Policies

CCE Holdings, LLC (CCE Holdings, or the Company) is a Delaware limited liability company formed on May 14, 2004 to acquire 100 percent of CrossCountry Energy, LLC (CrossCountry). CCE Holdings is owned by a subsidiary of Southern Union Company (Southern Union) (50 percent), a subsidiary of GE Commercial Finance Energy Financial Services (GE) (approximately 30 percent) and four minority interest owners (approximately 20 percent in the aggregate). The Company has two classes of members’ equity—Class A Interests (owned indirectly by Southern Union) and Class B interests (owned indirectly by GE and the minority interest owners). GE sold part of its Class B interests to the minority interest owners, but retained the voting rights. There are a number of restrictions or conditions on the transferability of ownership interests of the Company including, among other things, timing of transfers, minimum qualifications of the transferee, relative post-transfer ownership of the members and mutual rights of first refusal on all proposed transfers.

CrossCountry was formed on November 20, 2003, as an indirect, wholly owned subsidiary of Enron Corp. (Enron). Pursuant to a Plan of Reorganization filed with the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court), Enron or its affiliates contributed or assigned to CrossCountry (i) on December 29, 2003, its interest in CrossCountry Citrus Corp. (CrossCountry Citrus); and (ii) on March 31, 2004, its interests in Transwestern Holding Company, Inc. (TW Holdings), CrossCountry Energy Services, LLC (CCES), Northern Plains Natural Gas Company (Northern Plains), and NBP Services Corporation (NBP Services).

TW Holdings owns 100 percent of Transwestern Pipeline Company, LLC (Transwestern). Transwestern owns and operates an interstate natural gas pipeline system stretching from Texas and Oklahoma, through the San Juan Basin to the California border. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets.

CrossCountry Citrus owns 50 percent of Citrus Corp. (Citrus)(see Note 12). The remaining 50 percent of Citrus is owned by a subsidiary of El Paso Corporation. Citrus, a holding company incorporated in 1986, owns 100 percent of Florida Gas Transmission Company (FGT), Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI). FGT, an interstate natural gas pipeline extending from south Texas to south Florida, is engaged in the interstate transmission of natural gas. Trading ceased new trading activities effective the fourth quarter of 1997, but continued to fulfill its obligations under the remaining gas purchase and gas sales contracts until the fourth quarter of 2004. At that time, Trading liquidated its remaining derivative contract without a material impact on the consolidated statement of operations. CESI primarily provided transportation management and financial services to customers of FGT, but has terminated its operations and maintenance business due to increased insurance costs and pipeline integrity legislation that affects operators.

CCES provides personnel and administrative services to the Transwestern and FGT pipelines (collectively, the Pipelines).

The Company acquired CrossCountry for $2.1 billion in cash, plus $0.4 billion of assumed debt on November 17, 2004 (the Acquisition). The Company sold the interests in Northern Plains and NBP Services to ONEOK, Inc. for $175.0 million concurrently with the Acquisition. No gain or loss was recognized in connection with the sale. The results of CrossCountry’s operations have been included in the Company’s consolidated financial statements since that date. With interests in approximately 7,500 miles of pipeline and approximately 4.2 billion cubic feet per day of natural gas capacity, the Company serves customers in four major geographical regions in 20 states.

The acquisition of CrossCountry by CCE Holdings was accounted for using the purchase method of accounting in accordance with U.S. generally accepted accounting principles (GAAP). The assets acquired and the liabilities assumed were recorded at fair value as of the acquisition date based on outside appraisals.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the fair values (which have been adjusted in 2005 from our original allocation, see Goodwill and Other Intangible Assets policy) of assets acquired and liabilities assumed at the date of Acquisition (in millions):

	November 17,
	2004
Current assets, including cash of $85.4	$	119.6
Noncurrent assets		2,377.9
Total assets acquired		2,497.5
Current liabilities		(33.1	)
Noncurrent liabilities		(2.9	)
Long-term debt		(352.0	)
Total liabilities assumed		(388.0	)
Net assets acquired	$	2,109.5

Cash acquired includes $70.0 million dividended from Citrus on the date of the Acquisition.

The property, plant and equipment is being depreciated over the average remaining useful life of the pipeline assets acquired (see Note 5). The intangible assets acquired, comprised of certain contracts and software costs, are estimated to have remaining useful lives ranging from 3 to 10 years.

The value allocated to the Company’s investment in Citrus exceeded the Company’s share of the underlying equity of Citrus by $351.9 million. The Company will amortize or accrete, pursuant to APB Opinion No. 18, the fair value in excess of book value of its investment in certain underlying Citrus tangible and intangible assets and liabilities, over their respective estimated remaining useful lives, as indicated below:

Fair value in excess of book value of	Estimated useful lives
investment attributable to (in millions):	(years)		Amount
Property, plant and equipment		40	$	34.0
Long-term debt (a)		4-20		(83.3	)
Deferred taxes (a)		40		(13.1	)
Other net liabilities		(b)		(21.6	)
Goodwill		(c)		433.8
Software		5		2.1
Total				351.9
Accumulated net accretion				13.4
Net fair value in excess of book value			$	365.3

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

(b) Includes $21.0 million of reserve established pursuant to the purchase agreement for the Acquisition, as amended, which represents the Company’s equity in a dispute being litigated by Citrus. In the event the dispute is settled in favor of Citrus, the Company will be obligated to remit its equity share in the settlement, net of taxes, to Enron. Above a settlement of a certain amount, the Company would retain a portion of such excess proceeds above the current book value. The remainder also is related to specific contingencies, and accordingly, this amount is not accreted.

(c) Pursuant to SFAS No. 142,“Goodwill and Other Intangible Assets,” and Accounting Principles Board Opinion (APBO) No. 18, “The Equity Method of Accounting for Investments in Common Stock,” this amount is not amortized; however, such amounts will be subject to annual impairment review under APBO No. 18.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Principles of Consolidation

The consolidated financial statements include the accounts of the Company 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. Investments that are variable interest entities are consolidated if the Company is allocated a majority of the entity’s residual gains and/or losses, including fees paid by the entity. All significant intercompany accounts and transactions are eliminated in consolidation. TW Holdings, Transwestern, CrossCountry Citrus, and CCES are wholly owned subsidiaries of the Company and are consolidated. The Company’s 50 percent investment in Citrus is accounted for using the equity method of accounting (see Note 12).

Regulatory Accounting

The Pipelines are subject to regulation by the Federal Energy Regulatory Commission (FERC). The Pipelines’ 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 GAAP for nonregulated entities (see Note 9).

Revenue Recognition

Revenues consist primarily of fees earned from natural gas transportation services. Reservation revenues on firm contracted capacity are recognized ratably over the contract period. For interruptible or volumetric-based services, revenues are recorded upon the delivery of natural gas to the agreed upon redelivery point. Revenues for all services are generally based on the heating value, denominated in British thermal units of gas delivered or subscribed, at a rate specified in the contract. Recognition of revenues received in advance of delivery of natural gas is deferred until the gas is delivered.

Because the Pipelines are subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by FERC to be refunded in a final order. The Pipelines establish reserves for these potential refunds, as appropriate. There were no such reserves at December 31, 2005 and 2004.

Derivative Instruments

Transwestern may engage in price risk management activities and accounts for these under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless the derivatives qualify and are designated as hedges of future cash flows, fair values, net investments or qualify and are designated as normal purchases and sales. For derivatives treated as hedges of future cash flows, the effective portion of changes in fair value is recorded in other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. Derivatives designated as normal purchases or sales are recorded and recognized in income using accrual accounting.

Citrus engages in price risk management activities, and the Company recognizes its equity in the resulting price risk management gains and losses as they are earned or incurred. Citrus accounts for such activities under SFAS No. 133. Earnings or expense from revaluation of Citrus’ price risk management assets and liabilities are included in equity in earnings of unconsolidated affiliate in the accompanying statements of operations. Citrus utilizes cash flow hedge accounting for non-trading purposes to hedge the impact of interest rate fluctuations. Unrealized gains and losses from Citrus’ cash flow hedges are recognized according to SFAS No. 133 as other comprehensive income, and subsequently recognized in earnings in the same periods as the hedged forecasted transaction affects earnings. In instances where the hedge no longer qualifies as 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 hedged item (see Note 12).

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt Issuance Costs

The Company capitalizes costs incurred in conjunction with the issuance of debt and amortizes over the life of the respective debt.

Property, Plant and Equipment

Property, Plant and Equipment (see Note 5) consists primarily of natural gas pipeline and related facilities, and is recorded at its original cost of construction or acquisition. The Company capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest associated with capital projects. The cost of repairs is charged to operating and maintenance expenses. Costs of extensions, replacements and renewals of units of property are capitalized. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and removal costs. No retirement gain or loss is included in the results of operations except in the case of sales or retirements of operating units.

Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted future cash flows are not sufficient to recover the assets’ carrying value. The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

An accrual of 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 totaled $2.7 million and $0.6 million for 2005 and the period from inception through December 31, 2004, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statement of operations.

Transportation and Exchange Gas Imbalances, Net

Natural gas imbalances occur as a result of differences in volumes of gas received and delivered. The Company records natural gas imbalance in-kind receivables and payables at the dollar weighted composite average of all current month gas transactions and dollar valued imbalances are recorded at contractual prices. The imbalances are settled periodically at the request of the party that is owed natural gas. Upon the requested settlement date, the party that owes the natural gas will settle the imbalance, based on the applicable transportation agreement, by either: (i) delivering the required physical volume of natural gas; or (ii) paying a cumulative dollar value amount as calculated per the operator balancing agreement. The dollar valued imbalances are settled at the contractual index rate.

Computer Software

The Company’s accounting policy for the costs of computer software (all of which is for internal use by the Company and its affiliates only) is to capitalize direct costs of materials and services consumed in developing or obtaining software, including payroll and payroll-related costs for employees who are directly associated with and who devote time to the software project. Costs are capitalized during the application development stage. All other costs are expensed as incurred. The Company amortizes the costs at a rate of 10 percent per year. Impairment is evaluated based on changes in the expected usefulness of the software. Computer software is included in Property, Plant and Equipment under Intangible Assets (see Note 5).

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Environmental Expenditures

Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate based on the nature of the costs incurred. Liabilities are recorded when environmental assessments and/or clean ups are probable and the costs can be reasonably estimated (see Note 10).

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.

Goodwill and Other Intangible Assets

Goodwill represents the cost of CCE Holdings in excess of the fair value of the tangible and intangible assets and liabilities. In 2005, CCE Holdings obtained third-party valuations of certain assets and liabilities and evaluated certain contingencies, including income tax exposures. The allocation of the purchase price was refined during 2005 with adjustments made where necessary based on the better indicators of value obtained.

The adjustments (reductions) to goodwill in 2005 are (in millions):

Line pack	$	(10.6	)
Enron working capital settlement		(10.2	)
Lease termination and build-out costs		3.1
Other post employment benefits		2.3
Miscellaneous		(0.3	)
	$	(15.7	)

Intangible assets are recorded at fair value and are amortized to expense over their estimated useful lives. Certain intangible assets (other than goodwill) are presented as a component of Property, Plant and Equipment (see Note 5).

Goodwill and intangible assets with indefinite useful lives are not amortized to expense, but are reviewed for impairment annually and whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the fair value exceeds its carrying value, then the asset is not impaired. If its carrying value exceeds its implied fair value, then an impairment loss equal to the excess is recognized. For goodwill, the determination of whether an impairment has occurred is based on estimates of Transwestern’s discounted future cash flows as well as multiples of comparable companies and acquisitions as compared to the carrying value of Transwestern’s net assets. No impairments of goodwill or other intangible assets were recognized during 2005 or the period from inception to December 31, 2004.

The cost of the Company’s investment in unconsolidated affiliate in excess of the fair value of the underlying equity of that affiliate that is attributable to goodwill (equity method goodwill) is not subject to impairment testing under SFAS 142, but is subject to review and revaluation under APBO No. 18 if value of the equity investment declines and the decline is other than temporary.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

System Gas

The Company accounts for system balancing gas using the fixed asset accounting model established under FERC Order No. 581. Under this approach, system gas volumes are classified as fixed assets and valued at historical cost. Encroachments upon system gas are valued at current market prices. Transwestern may sell system gas in excess of its system operational requirements.

Allowance for Doubtful Accounts

Transwestern establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. Transwestern 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 collectibilty. The allowance for doubtful accounts was $0.1 and $0.0 million at December 31, 2005 and 2004, respectively.

Income Taxes

As a limited liability company (LLC), the Company is not a taxable entity. Accordingly, no income taxes have been reflected in the accompanying financial statements. On or about the date of the Acquisition, TW Holdings, Transwestern and CrossCountry Citrus were converted to LLCs. As single-member LLCs, each wholly owned subsidiary of CCE Holdings is a disregarded entity for federal income tax purposes, and will be included in the federal partnership tax return of the Company. All items of taxable income and expense pass through to the LLC members. All of the goodwill recorded in the Acquisition is expected to be deductible for tax purposes by the Members. Pursuant to the Partnership Agreement between the members of CCE Holdings, the Company is required to distribute to its members cash in amounts sufficient to cover each member’s tax liability resulting from its proportionate share of CCE Holdings’ income.

Citrus is a taxable entity, and files a consolidated tax return with its subsidiaries. The Company’s equity earnings and distributions from Citrus are taxable to the Members.

Recent Accounting Pronouncements

FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” Issued by the Financial Accounting Standards Board (FASB) in May 2004, FASB Financial Staff Position (FSP) No. FAS 106-2 (FSP FAS 106-2) requires entities to record the impact of the Medicare Drug Prescription Act as an actuarial gain in the postretirement benefit obligation for postretirement benefit plans that provide drug benefits covered by that legislation. The company adopted this FSP as of March 31, 2005, the effect of which was not material to its financial statements. The effect of this FSP may vary as a result of any future changes to the Company’s benefit plans. The Company had no material impact of recording the impact of this FSP.

FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” Issued by the FASB in March 2005, this interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS 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 conditioned on a future event that may or may not be within the control of the entity. Accordingly, the entity is required to recognize a liability for the fair value of a conditional asset retirement obligation 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. Transwestern adopted FIN No. 47 on December 31, 2005 and recognized its estimated obligation by recording a $0.9 million deferred credit and an increase to property, plant and equipment related to certain asbestos removal related obligations.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On March 3, 2005, the FASB issued FASB Staff Position (FSP) FIN 46(R)-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), ‘Consolidation of Variable Interest Entities,’” to address whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (VIE) or potential VIE when specific conditions exist. The determination of whether an implicit variable interest exists should be based on whether the reporting enterprise may absorb variability of the VIE or potential VIE. This FSP is effective, for entities to which the interpretations of FIN 46(R) have been applied, in the first reporting period beginning after March 3, 2005. There is no impact on the Company’s financial statements of adopting this FSP.

On June 30, 2005, the FERC issued a final order on accounting for pipeline assessment costs that requires pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs (under the Pipeline Safety Improvement Act of 2002). The accounting release determined that assessment activities associated with an integrity management program must be accounted for as maintenance and charged to expense in the period incurred. Costs associated with any remediation or rehabilitation can be capitalized. The FERC accounting guidance is effective January 1, 2006, for regulatory accounting purposes. Transwestern expects to apply the order for its regulatory accounting beginning in 2006 and that there will be no impact on Transwestern as Transwestern already expenses such costs.

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

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for prior years to conform to the current year presentation with no material impact on reported net income, members’ equity or cash flows.

(2) Subsidiary Disposition

In conjunction with the Acquisition, the Company acquired Northern Plains, NBP Services and certain other entities (the Northern Plains Assets) and resold them concurrently with the Acquisition. As of the Acquisition date, Northern Plains, together with its wholly owned subsidiary Pan Border Gas Company (Pan Border), owned 82.5 percent of the general partnership interest and 500,000 limited partnership units in Northern Border Partners, L.P. (Northern Border). The remaining 17.5 percent of the general partnership interest was owned by Northwest Border Pipeline Company, a subsidiary of TransCanada Corporation. Northern Border is a master limited partnership formed in 1993 to acquire, own and manage pipeline and other midstream energy assets. As of the Acquisition date, Northern Border held a 70 percent general partner interest in Northern Border Pipeline, a 100 percent interest in each of Midwestern Gas Transmission and Viking Gas Transmission and a 33 percent interest in Guardian Pipeline, LLC. Additionally, Northern Border owned and operated gathering and processing assets in the Powder River, Wind River and Williston basins. As of the Acquisition date, NBP Services provided administrative and operating services to Northern Border. On November 17, 2004, CCE Holdings sold the Northern Plains Assets to ONEOK, Inc. for $175.0 million immediately upon closing its acquisition of CrossCountry.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) Long-Term Debt

Long-term debt at December 31, 2005 and 2004 was as follows (in thousands):

	2005		2004
TW Holdings
Term loan, LIBOR plus 0.875%, maturing November 17, 2009	$	-	$	230,000
Revolving Credit Facility, LIBOR plus 0.625%, maturing
December 21, 2010		230,000		-
5.64% Notes due November 17, 2014		125,000		125,000
5.79% Notes due November 17, 2016		100,000		100,000
		455,000		455,000
Transwestern
5.39% Notes due November 17, 2014		270,000		250,000
5.54% Notes due November 17, 2016		250,000		250,000
Term loan, LIBOR plus 0.75%, maturing November 17, 2009		-		100,000
Revolving Credit Facility for up to $230.0 million, at LIBOR
plus 0.45%, maturing December 21, 2010 (the Revolving
Facility)		45,000		-
Revolving loan for up to $130.0 million, at LIBOR plus
0.75%, maturing November 17, 2009		-		-
		565,000		600,000

Total outstanding		1,020,000		1,055,000
Less current maturities		-		-
Long-term debt	$	1,020,000	$	1,055,000

Aggregate annual maturities of long-term debt outstanding at December 31, 2005 were as follows (in thousands):

2006	$	-
2007		-
2008		-
2009		-
2010		275,000
Thereafter		745,000
	$	1,020,000

The TW Holdings term loan bears interest at a variable rate based on either LIBOR or the Prime Rate, at the option of TW Holdings. On December 31, 2005, Transwestern had $275.0 million outstanding under the Revolving Facilities which is due by December 21, 2010, the maturity date of the facilities. No principal payments are required under the credit agreements for the senior unsecured notes prior to their respective maturity dates. The TW Holdings term loan and senior notes (collectively, the Borrowings) are guaranteed by CrossCountry Citrus. Proceeds from the Borrowings, net of related costs, totaling $441.8 million were used to fund the Acquisition. The costs of the Borrowings were capitalized and are being amortized to interest expense on a straight-line basis over the life of each debt instrument. Under the credit agreement covenants, TW Holdings is required to maintain certain debt to cash flow and interest coverage ratios. At December 31, 2005, TW Holdings was in compliance with all debt covenants. The fair value of TW Holdings senior notes at December 31, 2005 was approximately $224.6 million. The fair value of long-term debt is based upon market quotations of similar debt at interest rates currently available. The book value of the Revolving Credit Facility at December 31, 2005 approximates its market value given the variable rate of interest. The interest rate in effect under the Revolving Credit Facility at December 31, 2005 was 4.995 percent, based on LIBOR plus 0.625 percent. The fair value of TW Holdings debt at December 31, 2004 approximated the book value of such debt because the interest rate at inception of the debt approximated the market rate at the end of the year.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 17, 2004, proceeds from the Transwestern senior notes, term loan and Revolver (collectively, the Refinancing), net of related costs, were used by Transwestern to retire its May 2004 debt and to fund the Acquisition. No principal payments are required under the Refinancing debt agreements prior to their respective maturity dates. The costs of the Refinancing in excess of the carrying value of the debt on Transwestern’s books were capitalized as a non-current asset and are being amortized to interest expense ratably over the life of each debt instrument. Under the credit agreement covenants, Transwestern is required to maintain certain debt to capital and interest coverage ratios. At December 31, 2005, Transwestern was in compliance with all such covenants. The fair value of Transwestern’s senior notes at December 31, 2005 was approximately $511.3 million. The fair value of long-term debt is based upon market quotations of similar debt at interest rates currently available. The book value of the Revolving Facility at December 31, 2005 approximates its market value given the variable rate of interest. The interest rate in effect under the Transwestern Revolving Facility at December 31, 2005 was 4.82 percent, based on LIBOR plus 0.45 percent. The fair value of Transwestern’s debt at December 31, 2004 approximated the book value of such debt, either because the debt was subject to a variable interest rate, or the interest rate at inception of the debt approximated the market rate at the end of the year.

On December 21, 2005, TW Holdings entered into an amendment and restatement to the Term Loan converting the loan to a revolving credit facility and extending the maturity date to December 21, 2010. The interest rate in effect under the revolving credit facility at December 31, 2005 was 4.995 percent, based on LIBOR plus 0.625 percent.

On December 21, 2005, Transwestern entered into an amended and restated agreement to the Term Loan and Revolver agreements converting the entire amounts into one revolving credit facility for up to $230.0 million. The Revolving Facility amendment allows the entire amount to be available for letters of credit and extends the maturity date to December 21, 2010.

The Company’s credit agreements contain certain other restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends.

(4) Derivative Instruments

During 2005 and the period from May 14, 2004 (Inception) to December 31, 2004, Transwestern’s commercial contracts were designated as normal purchases or normal sales. The contract types designated as normal include: (i) transportation; (ii) purchases of materials and services; (iii) system balancing agreements and third party storage; (iv) operational balancing agreements; and (v) operational gas purchases and sales.

Citrus uses derivatives to mitigate, or hedge, cash flow risk associated with its variable interest rates on long-term debt, and the Company recognizes its equity in the resulting hedging gains and losses as they are earned or incurred (see Note 12).

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(5) Property, Plant and Equipment

The principal components of the Company’s Property, Plant and Equipment at December 31, 2005 and 2004 are as follows (in thousands):

	Lives
	(Years)		2005			2004
Transmission Plant		40-83	$	1,055,908		$	890,572
General Plant		10		10,843			10,511
Intangible Assets		10-12		25,800			10,091
Construction Work-in-progress		-		7,419			100,420
Property, Plant and Equipment, at Cost				1,099,970			1,011,594
Less - Accumulated depreciation and amortization				(25,627	)		(2,777	)
Property, Plant and Equipment, Net			$	1,074,343		$	1,008,817

Included in gross property, plant and equipment at December 31, 2005 is an aggregate plant acquisition adjustment of $283.4 million, which represents costs allocated to Transwestern’s transmission plant as a result of its acquisition by the Company. This amount has not been included in the determination of tariff rates Transwestern charged to its regulated customers. The unamortized balance of this adjustment was $275.0 million and $282.2 million at December 31, 2005 and 2004, respectively and is being amortized over 39 years, the composite weighted average estimated useful life of the Company’s assets as of the Acquisition date.

Intangible assets include the following (in thousands):

	Lives
	(Years)		2005			2004
Intangible Assets included in Property, Plant and Equipment:
Computer software		5-10	$	23,281		$	10,091
Leasehold improvement		10		2,519			-
Intangible Assets				25,800			10,091
Less - Accumulated depreciation and amortization				(4,255	)		(342	)
Intangible Assets included in Property, Plant and Equipment - Net			$	21,545		$	9,749

Intangible Assets included in Other Assets:
Customer contracts	3	$	12,600		$	12,600
Less - Accumulated depreciation and amortization			(4,713	)		(513	)
Intangible Assets included in Other Assets - Net		$	7,887		$	12,087

The provision for depreciation and amortization is computed using the straight-line method based on estimated economic or FERC mandated lives. The Company’s composite depreciation rates are applied to the FERC functional groups of gross property having similar economic characteristics. Transmission Plant is depreciated at rates ranging from 1.2 percent to 2.86 percent per year. General Plant is depreciated at 10.0 percent per year. Intangible Assets are depreciated at rates ranging from 8.0 percent to 10.0 percent per year.

Amortization of intangible assets is estimated to be approximately $8.6 million in 2006, $7.4 million in 2007, $3.3 million in 2008, $3.1 million in 2009 and $2.9 million in 2010.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(6) Accounts Receivable and Related Activity

The Company has a concentration of customers in the electric and gas utility industries. This concentration 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. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral to the Company. The Company sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $0.6 million and $1.6 million at December 31, 2005 and 2004, respectively. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk.

During December 2005, one of Transwestern’s top ten customers, Calpine Energy, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. Transwestern recorded transportation revenues from Calpine of $5.0 million and $5.6 million for the years ended December 31, 2005 and 2004, respectively. Transwestern continues to transport gas for Calpine and receive payments from Calpine. Transwestern also holds certain security associated with the Calpine contract, but is exposed to potential revenue reductions if Calpine ceases performing and rejects the contract in bankruptcy and replacement shippers willing to pay the same rate are not found. It is not known at this time what impact, if any, Calpine’s bankruptcy will have on Transwestern.

The following customers accounted for a significant portion of the Company’s total revenues during 2005 and the period from inception to December 31, 2004 (in millions):

	2005		2004
Southern California Gas Company (SoCal)	$	44.1	$	6.2
BP Energy Company (BP)		26.9		5.2
Pacific Gas and Electric Company (PGE)		20.9		2.8

The Company had receivables of $1.5 million from SoCal, $2.5 million from BP and $2.0 million from PGE at December 31, 2005. The Company had receivables of $4.2 million from SoCal, $1.9 million from BP and $2.0 million from PGE at December 31, 2004.

Transwestern’s top customer, SoCal, had transportation contracts which expired on October 31, 2005. Effective November 1, 2005 the contracts were renegotiated and replaced with terms less favorable on rates and volumes for Transwestern and could have a significant impact on the results of operations in future periods if replacement shippers are not found.

(7) Balance Sheet Details

The detail of certain balance sheet items as of December 31, 2005 and 2004 follows (in thousands):

Other Current Assets	2005		2004
Prepaid right-of-way	$	3,238	$	3,238
Miscellaneous prepayments		4,331		7,606
Materials and supplies		957		936
Other		126		150
	$	8,652	$	11,930

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Assets	2005		2004
Prepaid right-of-way	$	12,628	$	15,891
Unamortized debt costs		26,675		28,746
Intangible assets - contracts, net		7,887		12,087
Deferred development costs		2,688		365
Annual regulatory commission costs		799		915
Other, net		256		166
	$	50,933	$	58,170

Other Current Liabilities
Capital and expense accruals (1)	$	3,542	$	13,091
Transition costs		334		5,319
Incentive plan accruals		3,506		-
Labor and related benefit accruals		2,270		652
Reserve for regulatory and other contingencies		3,591		2,244
Customer deposits		637		1,560
Other		2,477		1,819
	$	16,357	$	24,685

Deferred Credits
Environmental liabilities	$	10,175	$	2,907
Asset retirement obligation - asbestos		865		-
Retiree medical liabilities		3,026		-
Other miscellaneous		26		-
	$	14,092	$	2,907

___________________________

(1) The 2004 capital and expense accrual included $13.1 million for San Juan pipe and outside services.

(8) Employee Benefit Plans

The Company had no employees until November 17, 2004, the date of the Acquisition. From that date until November 30, 2004, the Company’s employees migrated, without lapse, from certain of Enron’s employee welfare and benefit plans to new employee welfare and benefit plans adopted by the Company.

Effective January 1, 2005, the Company and its subsidiaries adopted the CrossCountry Energy Savings Plans (the Plans). All employees of the Company and its subsidiaries are eligible to participate and, under 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 the Company to make discretionary profit sharing contributions for the benefit of all participants. The Company matches 50 percent of participant contributions under this plan up to a maximum of 4 percent 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 Plans were immediately vested. Administrative costs of the Plans and certain asset management fees are paid from Plan assets.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Enron initiated steps to terminate the Cash Balance Plan through a standard termination in 2003. The Cash Balance Plan was underfunded at December 31, 2003. In June 2004, the Pension Benefit Guaranty Corporation (PBGC) filed a complaint in the United States District Court for the Southern District of Texas to terminate the Cash Balance Plan and other pension plans of Enron debtor companies and affiliates (the Plans). If the PBGC successfully terminated the Plans in this suit, each member of the Enron “controlled group of corporations” within the meaning of Section 414 of the Tax Code, and certain other Enron affiliates, would be jointly and severally liable, under Title IV of ERISA, for the Plans’ unfunded benefit liabilities. Under certain circumstances, the PBGC may enforce ERISA Title IV liability through the imposition of liens. On September 10, 2004, Enron agreed to deposit $321.8 million in an escrow account to cover, among other things, the unfunded benefit liabilities relating to the Plans. The escrow account was funded with a portion of the proceeds from Enron’s sale of CrossCountry. Transwestern’s estimated share of the cost of terminating the plan was $5.9 million. Under the Purchase Agreement, Enron agreed (subject to a cap) to indemnify and hold harmless Transwestern, CrossCountry and certain other members of the CrossCountry group for, among other things, any joint and several liability arising under Title IV of ERISA or due to their status as participating employers in certain Enron benefit plans, including the Cash Balance Plan. Accordingly, the Company does not believe that the ultimate resolution of these matters will have a material adverse effect on its financial position, results of operations or cash flows.

Employee Retirement Benefits

Enron provided certain post-retirement medical, life insurance and dental benefits (OPEB) to eligible employees and their eligible dependents through November 30, 2004. During the period December 1, 2004 through February 28, 2005 coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits. Effective March 1, 2005 such benefits are provided under identical plans sponsored by Transwestern and CCES as single employer post-retirement benefit plans.

Transwestern and CCES were previously participating employers 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 provides benefits to employees of Transwestern and CCES 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 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 Transwestern and CCES, 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. Both motions remain pending in the Enron bankruptcy court. On February 6, 2006 the Nebraska action was dismissed.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

With regard to its sponsored plans, CCE Holdings has entered into a VEBA trust (the “VEBA Trust”) agreement with Bank One Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, sick, 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. CCE Holdings contributed $0.9 million to the VEBA Trust for the year ended December 31, 2005. Upon settlement of the Trust, any distribution of assets CCE Holdings receives from the Trust, estimated to be approximately $2.9 million per the Enron filing described above, will be contributed to the VEBA Trust.

Prior to 2005, the Company’s general policy was to fund accrued post-retirement health care costs as allocated by Enron. As a result of the change in 2005 from a multi employer plan to single employer plans, the Company 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.

The following table represents a reconciliation of CCE Holdings’ OPEB plan at December 31, 2005:


	Year ended
	December 31,
OPEB (in thousands)	2005

Change in Benefit Obligation
Benefit obligation at plan adoption (1)	$	6,734
Service cost		90
Interest cost		316
Actuarial gain		(2,917	)
Retiree premiums		726
Benefits paid		(833	)
Benefit obligation at end of year	$	4,116

Change in Plan Assets
Fair value of plan assets at plan adoption (1) (2)	$	2,862
Return on plan assets		162
Employer contributions		939
Retiree premiums		726
Benefits paid		(833	)
Fair value of plan assets at end of year	$	3,856

Funded Status
Funded status at end of year	$	(260	)
Unrecognized net actuarial gain		(2,766	)
Net liability recognized at December 31, 2005	$	(3,026	)

___________________________

(1)	For purposes of this reconciliation, the plan adoption date is considered to be January 1, 2005.

(2) Plan assets include the amount of assets expected to be received from the Enron Trust.

The weighted-average assumptions used to determine CCE Holdings’ benefit obligations for the year ended December 31, 2005 were as follows:


As of December 31, 2005

Discount rate	5.50	%
Rate of compensation increase	N/A

Health care cost trend rates
(graded to 4.65% by year 2012)	12.00	%

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

CCE Holdings’ OPEB benefit costs for the period presented consisted of the following:


	Year Ended
	December 31,
OPEB (in thousands)	2005


Service cost	$	89
Interest cost		316
Expected return on plan assets		(162	)
Amortization of prior service cost		-
Recognized actuarial gain		(151	)

Net periodic benefit cost	$	92

The weighted-average assumptions used to determine CCE Holdings’ OPEB benefit costs for the period presented were:

Year Ended December 31, 2005

Discount rate		5.75%
Rate of compensation increase		N/A
Expected long-term return on plan assets		5.00%

Health care cost trend rates
(graded to 4.75% by year 2012)		12.00%

CCE Holdings 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.

The sensitivity to changes in assumed health care cost trend rates for CCE Holdings’ OPEB is as follows:

	1 Point Increase		1 Point Decrease
(in thousands)
Effect on total service and interest cost components	$	7	$	(6	)
Effect on postretirement benefit obligation	$	125	$	(111	)

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.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

CCE Holdings’ OPEB weighted-average asset allocation by asset category for the $0.8 million of assets actually in the VEBA Trust at December 31, 2005 is as follows:

	Year Ended
	December 31,
	2005

Equity securities		0	%
Debt securities		0	%
Cash and cash equivalents		100	%
Total		100	%

(9) Rate Matters and Regulatory Issues

Rate matters and regulatory issues are regulated by the FERC, and are subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 allows companies whose service obligations and prices are regulated to record deferred charges (regulatory assets) representing costs they expect to recover from customers through inclusion in future rates. Likewise, costs recovered that should be excluded from the rate base are recorded as deferred credits (regulatory liabilities). If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write down these regulatory assets and liabilities.

The principal components of the Company’s regulatory assets at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004
Regulatory assets:
Accumulated reserve adjustment	$	43,799	$	44,387
AFUDC gross-up		9,191		7,978
Environmental costs (see Note 10)		4,902		-
South Georgia deferred tax receivable		2,638		2,686
Other post-retirement benefits (see Note 8)		1,135		-
Deferred contract reformation costs		505		1,909
Deferred loss on receivables		722		1,482
Litigation costs		633		1,500
Purchase gas adjustments alternative rate recovery		447		984
Other		897		2,395
	$	64,869	$	63,321

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2005 and 2004, all of the Company’s regulatory assets are considered probable of recovery in rates.

The accumulated reserve adjustment included in the table above resulted from a settlement agreement dated May 2, 1995 (May 2, 1995 Settlement) further described below. The settlement approved Transwestern’s proposal to refunctionalize certain facilities from production and gathering to transmission and from transmission to production and gathering. As directed by the FERC Order (Docket No. RP95-271-000) issued upon approval of the settlement, Transwestern established a regulatory asset for an accumulated reserve adjustment of $50.1 million, which represents the difference between recorded amounts of accumulated depreciation (determined on a vintage basis) and approved amounts of accumulated depreciation based on remaining reserves related to the gathering facilities. The accumulated reserve adjustment is being amortized at a 1.2 percent annual rate. Concurrent with the amortization, Transwestern records an entry to reduce depreciation expense and reduce accumulated amortization. Management believes that these entries are appropriate based on the intent of the settlement. Transwestern intends to continue to seek recovery of this asset in future rate case filings.

In the May 2, 1995 Settlement, Transwestern and certain of its current firm customers also agreed to contract settlement rates through the lives of these customers’ contracts, and agreed that Transwestern would be required to file a new rate case to become effective no later than November 1, 2006. The settlement was approved on July 27, 1995.

Transwestern filed on April 8, 2004 an application with the FERC in CP04-104-000 for an expansion project (Expansion Project) that increased incremental capacity by 375,000 dekatherms per day on the San Juan Lateral from the Blanco Hub, located in San Juan County, New Mexico, to the Gallup area located at the interconnection of the San Juan Lateral and Transwestern’s mainline. The Expansion Project expanded Transwestern’s natural gas transmission system through the construction of approximately 72.6 miles of pipeline looping on the existing San Juan Lateral and causing Transwestern to abandon, install, and modify facilities at three existing compressor stations for additional compression totaling 20,000 horsepower. The Expansion Project was approved by the FERC on August 5, 2004, and the facilities were placed in service on May 1, 2005 at a final estimated cost to construct of $123.9 million.

(10) Commitments and Contingencies

From time to time, in the normal course of business, the Company or its subsidiaries are involved in litigation, claims or assessments that may result in future economic detriment. The Company evaluates each of these matters and determines if loss accruals are necessary as required by SFAS No. 5, “Accounting for Contingencies.” The Company does not expect to experience losses that would be materially in excess of the amounts accrued at December 31, 2005.

Legal Proceedings

In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wy), the plaintiff has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mismeasurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which is filed with and approved by FERC. Transwestern’s legal exposure, if any, related to the ultimate resolution of this matter is not currently determinable.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transwestern is managing three threatened trespass actions related to right of way (ROW) on Tribal or allottee land. The first action involves an agreement with the United States Department of the Interior, Bureau of Indian Affairs (BIA) covering 44 miles of ROW on a total of 69 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee sent a letter dated January 16, 2004 to the BIA claiming Transwestern is trespassing. Discussions are ongoing with the BIA to approve the renewal application, which was filed in October 2002. The second action involves a 1990 Grant of Easement and Right of Way by the Secretary of the Interior covering 6.6 miles of Southern Ute land assigned by Northwest Pipeline Corporation (Northwest Pipeline) to Transwestern in 1996. Application was made to the BIA for approval of that assignment, but no action was taken. On May 27, 2003 and September 2, 2003, counsel for the Southern Ute Tribe sent letters to Transwestern alleging trespass. Under the operative regulations and the underlying agreements, Transwestern believes that the consent of the Tribe is not required to assign the ROW grant from Northwest Pipeline to Transwestern. A tentative settlement has been reached in this matter which extends the subject ROW, which expired in September, 2005 to September 2020. The third action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the BIA on behalf of the two allottees asserting trespass. Transwestern’s legal exposure related to this matter is not currently determinable. The settlement will not have a material impact on Transwestern’s financial position, results of operations or cash flows.

Effective December 16, 2004, Citicorp North America, Inc. (Citicorp) claimed, in its capacity as the Paying Agent and Co-Administrative Agent, that any recovery in the litigation captioned Enron Corp. et al. v. Citigroup, Inc. et al. (the Litigation), together with legal fees and expenses incurred by Citicorp in defending the Litigation, would be indemnity obligations (the Obligations) of Transwestern under its Credit Agreement dated November 13, 2001. Under the terms of the Purchase Agreement, CCE Holdings and certain of its subsidiaries are indemnified against the Obligations by Enron and certain of its subsidiaries. Accordingly, the Company does not believe that it has any material liability from Citicorp’s claims.

On December 30, 2005, CPW America Co. filed suit against Transwestern (CPW America Co. v. Transwestern Pipeline Company, LLC, 11^th Judicial District Court of Harris County, Texas) seeking $1.5 million, plus interest and fees, based upon a sworn account, breach of contract, breach of covenant of good faith and fair dealing, unjust enrichment and quantum meruit. CPW claims Transwestern failed to make full payment to CPW for pipe provided to Transwestern for the San Juan Expansion. Transwestern filed an answer to these claims on January 20, 2006 in which Transwestern denied any liability in this matter.

Phoenix Expansion Project

On November 22, 2005, FERC granted Transwestern’s request to use the pre-filing review process for Transwestern’s proposed Phoenix Expansion Project. The project has been assigned Docket No. PF06-4-000. The Phoenix Expansion Project, as currently proposed, consists of the construction and operation of approximately 260 miles of 36-inch diameter natural gas pipeline extending from the existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area. In addition, Transwestern proposes to complete the looping on its existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. Other major facilities include the abandonment and the replacement of the existing compression facilities at Transwestern’s Compressor Station No. 4. Transwestern is proposing to file its application on or before July 1, 2006, with a projected in-service date of early 2008. As of February 28, 2006 Transwestern has executed expansion agreements with shippers for volumes sufficient in Transwestern’s judgment to commence further development of the Phoenix Expansion Project. The project scope and structure are under discussion with the CCE Holdings members.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rates and Regulatory Matters

On August 1, 2002, the FERC issued an Order to Respond (August 1 Order) to Transwestern. The order required Transwestern, within 30 days of the date of the order, to provide written responses stating why the FERC should not find that: (i) Transwestern violated FERC's accounting regulations by failing to maintain written cash management agreements with Enron; and (ii) the secured loan transactions entered into by Transwestern in November 2001 were imprudently incurred and why the costs arising from such transactions should be passed on to ratepayers. Transwestern filed a response to the August 1 Order and subsequently entered into a settlement with the FERC staff that resolved, as to Transwestern, the issues raised by the August 1 Order. The FERC approved this settlement; however, a group of Transwestern’s customers filed a request for clarification and/or rehearing of the FERC order approving the settlement. This customer group claimed that there is an inconsistency between the language of the settlement agreement and the language of the FERC order approving the settlement. This alleged inconsistency relates to Transwestern’s ability to pass through to its ratepayers the costs of any replacement or refinancing of the secured loan transactions entered into by Transwestern in November 2001. Transwestern filed a response to the customer group’s request for rehearing and/or clarification and this matter is currently awaiting FERC action.

On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs (Pipeline Integrity Program) 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, 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 with certainty at this time. The required modifications and inspections are estimated to range from approximately $3.0 - $5.0 million per year, inclusive of remediation costs.

Environmental Matters

Transwestern 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 is expected to result in increased operating expenses. These increased operating expenses are not expected to have a material impact on the Company’s financial position or results of operations.

Transwestern conducts soil and groundwater remediation at a number of its facilities. The costs of such remediation totaled $4.4 million during 2005 and $0.2 million for the period from inception to December 31, 2004. The total future estimated cost of remediation activities is $13.6 million. Over the next five years the costs are expected to be: 2006 - $3.6 million; 2007 - $2.0 million; 2008 - $1.8 million; 2009 - $1.7 million and 2010 - $1.4 million. The expenditures thereafter are estimated to be $3.1 million for soil and groundwater remediation. Approximately $5.3 million of these costs were recorded in expense for 2005 for remediation of several compressor sites on the Transwestern system for the presence of polychlorinated biphenyls (PCBs) which are not eligible for recovery in rates. The accrual is recognized in other current liabilities and other deferred credits in the accompanying 2005 consolidated balance sheet. Transwestern also established a regulatory asset of $4.9 million for the portion of soil and groundwater remediation not related to PCBs and will request recovery of these costs in the next rate case (see Note 9).

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transwestern incurred, and continues to incur, certain costs related to PCBs that migrated into customer’s facilities. Because of the continued detection of PCBs in the customer’s facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities totaled $0.4 million in 2005. There were no costs incurred during the period from inception to December 31, 2004. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at December 31, 2005 and 2004. However, such future costs are not expected to have a material impact on the Company’s financial position or results of operations or cash flows.

Environmental regulations were recently modified for United States Environmental Protection Agency’s Spill Prevention, Control and Countermeasures (SPCC) program. Transwestern 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 reasonably estimated at this time, but Transwestern believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

Capital Commitments and Purchase Obligations

Transwestern and certain of its affiliates, as former members of the Enron consolidated tax group through November 16, 2004, are jointly and severally liable for the tax liability of the consolidated group for the years that they were members of the group pursuant to Treasury regulation §1.1502-6 or any state, local or foreign tax arising under the principles of successor or transferee liability. Management believes that the Company’s exposure to Enron’s consolidated tax liability is limited, in part because the purchase agreement (Purchase Agreement), dated June 24, 2004 (as amended by that certain Amendment No. 1 to Purchase Agreement, dated September 1, 2004, and that certain Amendment No. 2 to Purchase Agreement, dated November 11, 2004), for the Acquisition provided for an indemnification of the Transfer Group Companies, as defined therein, by Enron for any federal or state income tax liabilities in excess of $7.5 million.

Transwestern has operating leases, some of which are subject to a CPI-based adjustment, which extend existing rights-of-way along its natural gas pipeline system. Lease payments charged to expense were $6.5 million and $0.8 million during 2005 and the period from inception to December 31, 2004, respectively.

Future minimum payments under non-cancelable leases are as follows (in millions):

Year Ending	Operating
December 31,	Leases
2006	$	3.2
2007		3.3
2008		3.3
2009		3.3
2010		0.3
Thereafter		3.3
Total	$	16.7

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In addition to the lease payments, Transwestern recognizes noncash lease expense related to amortization of prepayments made in accordance with certain lease terms. In 2001, Transwestern paid $3.5 million in a lump sum for a right-of-way lease, which is being amortized to lease expense over the twenty-year period beginning January 1, 2003. In 2002, Transwestern paid $18.0 million in a lump sum for a right-of-way lease, which is being amortized to lease expense over the six-year period beginning January 1, 2004. Included in the above schedule for that six-year lease agreement are amounts that commenced January 1, 2004 at an initial annual payment of $2.3 million, subject to a CPI-based adjustment in future years. The remainder of the future minimum lease payments pertains to a 20-year lease agreement with annual payment requirements of $0.3 million that became effective on December 28, 2002.

(11) Related Party Transactions

In 2004, Transwestern was a party to compression services agreements with Enron Compression Services Company (ECS), an Enron affiliate that is not in bankruptcy. The agreements require Transwestern to pay ECS a compression service charge in cash and in-kind to provide electric horsepower capacity and related horsepower hours to be used to operate the Bisti, Bloomfield, and Gallup electric compressor stations located in New Mexico. ECS is required to pay Transwestern a monthly fee to operate and maintain the facilities. Transwestern and ECS entered into a Purchase and Settlement Agreement and Mutual Release dated April 30, 2004 (the Purchase and Settlement Agreement). The Purchase and Settlement Agreement (i) caused the sale of certain motor and drive systems of ECS to Transwestern; and (ii) amended and restated the agreements between Transwestern and ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services 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. Transwestern has 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 is administered by CCES, which has 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. Transwestern accrued administrative expenses from Enron and affiliated service companies of approximately $1.3 million and $0.7 million during 2005 and the period from inception to December 31, 2004, respectively.

Effective November 5, 2004, the Company entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a wholly owned subsidiary of Southern Union. Pursuant to the ASA, Manager is responsible for the operations and administrative functions of the enterprise, the Company and Manager will share certain operations of Manager and its affiliates, and the Company will be obligated to bear its share of costs of the Manager and its affiliates, as well as certain transition costs and, under certain conditions, pay annual management fees to Manager. 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. Transition costs are non-recurring costs of establishing the shared services, including but not limited to severance costs, professional fees, certain transaction costs, and the costs of relocating offices and personnel. Management fees are to be calculated based on a percentage of the amount by which certain earnings targets are exceeded. No management fees were due under the ASA for any portion of 2004. Based on 2005 operating results, the company has accrued $4.3 million for management fees which is included in Accounts payable - associated companies.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2004, following the Acquisition, the Company was billed $1.8 million by Southern Union for certain services provided under the ASA. In addition, transition costs of $6.0 million were charged to the Company by Panhandle Eastern Pipe Line Company, LP, (Panhandle) a wholly owned subsidiary of Southern Union. This amount, representing mainly severance and related costs, was recorded as operating and maintenance expenses in the accompanying 2004 statement of operations. In 2005, the Company was billed $12.0 million for shared services by Southern Union provided under the ASA, of which $10.4 million was expensed by the Company as part of operating and maintenance expense in the accompanying 2005 statement of operations and $1.6 million was charged to Citrus. Shared services are also exchanged between other affiliate companies.

In the period from inception to December 31, 2004 the Company: (i) prepaid $2.8 million of insurance costs allocated by Southern Union to be amortized ratably to expense over the policy period; (ii) recorded receivables aggregating $3.1 million from Citrus for services provided to Citrus by CCES; and (iii) recorded a receivable of $9.6 million from Citrus for amounts due from Citrus under the Cash Balance Plan, which the Company effectively paid in conjunction with the Acquisition and which was cash settled in 2005. At December 31, 2005 the Company has payables to Southern Union for shared services and payroll costs of $4.2 million and management fees of $4.3 million. The Company also has recorded receivables of $3.6 million and $0.7 million from Panhandle and affiliates and Citrus, respectively, for services provided and a payable of $2.5 million to Panhandle and affiliates for services received.

In connection with the financing of the Acquisition, Citrus paid a dividend totaling $70.0 million to the Company. The $991.0 million value allocated to the Company’s investment in Citrus in the purchase accounting for the Acquisition is net of this dividend.

On December 30, 2005 the Company paid distributions totaling $30.0 million to its members.

(12) Unconsolidated Affiliate

The Company accounts for its investment in its only unconsolidated affiliate, Citrus, in which it owns a 50 percent interest, using the equity method of accounting. As of December 31, 2005 and 2004, the Company’s investment in Citrus was $1,010.4 million and $998.5 million, respectively (see Note 1).

Summarized financial information for Citrus (100 percent, as reported by Citrus) is presented below (in thousands):

	Year Ended		Year Ended
	December 31,		December 31,
	2005		2004
Statement of Income Data
Operating revenues	$	476,049	$	512,418
Natural gas purchased		-		48,921
Net revenues		476,049		463,497
Operations, maintenance and other taxes		113,135		110,871
Depreciation and amortization		91,125		68,053
Operating income		271,789		284,573
Income before income tax		199,030		206,064
Net income		123,944		126,844

The Company’s Interest:
Allocated income (a)	$	61,972	$	5,488
Adjustments (b)		10,520		2,061
Equity in earnings of unconsolidated affiliate	$	72,492	$	7,549

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31,		December 31,
	2005		2004
Balance Sheet Data
Current assets	$	68,119	$	59,115
Property, plant and equipment, net		2,916,548		2,966,747
Other assets		104,720		116,074
Total assets	$	3,089,387	$	3,141,936

Current liabilities	$	76,350	$	87,396
Long-term debt		922,355		1,010,825
Other liabilities		800,894		759,309
Total liabilities	$	1,799,599	$	1,857,530

___________________________

(a)

Represents the Company’s equity in Citrus’ earnings for the year ended December 31, 2005 and the period from the date of Acquisition, November 17, 2004, through December 31, 2004.

(b)

Reflects (i) net accretion of $11.9 million and $1.5 million for 2005 and 2004, respectively, pursuant to APB Opinion No. 18, related to the fair value in excess of book value of the Company’s investment in certain underlying Citrus tangible and intangible assets and liabilities. See table below for further breakdown of accretion; (ii) $0.4 million for 2004, related to a deferred compensation plan settlement recognized as expense by Citrus, which was capitalized by the Company as a component of purchase accounting, under the line item “other net liabilities;” (iii) $(2.7) million for 2005, related to items recognized as income or expense by Citrus, which were capitalized by the Company as a component of purchase accounting, under the line item “goodwill” and (iv) $1.3 million and $0.2 million for 2005 and 2004, respectively, related to reversal of Citrus amortization of other comprehensive income, the remaining pro rata balance of which the Company capitalized as a component of purchase accounting (see Note 1).

Adjustments to the Company’s Equity in Citrus earnings (in millions):

	2005			2004
Net Accretion
Property, plant and equipment……………………	$	(0.8	)	$	(0.1	)
Long-term debt……………………………………		12.8			1.6
Deferred taxes……………………………………		0.3			0.1
Intangibles - software……………………………		(0.4	)		(0.1	)
Total Net Accretion………………………………………….		11.9			1.5
Citrus (income) expense offset (ii)(iii)(iv)………………….		(1.4	)		0.6
Total Adjustments……………………………………	$	10.5		$	2.1

Contingent Matters Potentially Impacting the Company’s Investment in Citrus Corp

Environmental Matters. - FGT is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted from the past releases primarily of hydrocarbons, and to some extent past releases of chlorinated compounds. FGT 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 financial position, results of operations or cash flows.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities - FGT is subject to regulation by certain state and federal authorities and has accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, that are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows FGT to defer expenses and revenues on its 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 income statements if it was 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 its rates and recovered from or refunded to its customers. Management’s assessment for FGT of the probability of their recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, FGT ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from its Consolidated Balance Sheet, resulting in an impact to the Company’s share of its equity earnings. At December 31, 2005, FGT’S regulatory asset and liability balances were $24.1 million and $9.0 million, respectively.

Federal Pipeline Integrity Rules

For FGT, the required modifications and inspections for the Pipeline Integrity Program (see Note 10) are estimated to be in the range of approximately $12-$22 million per year, inclusive of remediation costs. In the August 13, 2004 Settlement of the rate case, FGT has the right to make limited sections 4 filings to recover such costs beginning in April 2006 (if the threshold is met), via a surcharge, 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 in 2005 are expected to create a surcharge of $0.01 per MMBtu effective on April 1, 2006.

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 FERC Settlement dated December 21, 2004. The Settlement contains no reference to the FERC Docket No. AI05-1-000 regarding pipeline assessment costs. The Settlement provides that the final FERC order approving the Settlement shall constitute final approval of all necessary authorizations to effectuate the provisions of the Settlement. The Settlement became effective on March 1, 2005 and new tariff sheets to implement the Settlement were filed on March 15, 2005. FERC issued an order accepting the tariff sheets on May 20, 2005. FGT expects the cost of pipeline assessment programs, as a part of the integrity programs, to be approximately $8.8 million in 2006, and pursuant to its approved tariff and Settlement language, intends to capitalize such costs pending FERC review of its surcharge filing to be effective April 1, 2006.

Table of Contents

CCE HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Litigation

FGT Pipeline Relocation Costs - The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages, which may, over the next ten years, impact one or more of FGT’s mainline pipelines that are co-located in FDOT/FTE rights-of-way. Under certain conditions, the 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: (a) FGT is entitled to recover: (i) compensation for all or any part 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 in a prior relocation project (for which an invoice was presented to FDOT/FTE but FDOT/FTE refused to pay). FGT also seeks 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. Trial date is set for June 13, 2006.

FGT is planning to replace approximately 11.3 miles of its existing 18 and 24 inch pipelines located in FDOT/FTE right of way between Griffin Road and Atlantic Avenue in Broward County, Florida with a single 36 inch pipeline starting fourth quarter 2006. Estimated cost of this project is $110 million. FGT is also in discussions with the FDOT/FTE related to two other projects, Heft to Griffin (7.5 miles) and Atlantic to Sawgrass (6.8 miles that may require relocation and replacements of FGT’s 18 and 24 inch pipelines within FDOT/FTE right of way. The total actual amount of miles of pipe to be impacted ultimately for all of the FDOT/FTE widening projects, and the associated relocation and/or right-of-way costs, cannot be determined at this time.

Table of Contents

Citrus Corp. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2005, 2004 and 2003

with Report of Independent Registered Public Accounting Firm

Table of Contents

TABLE OF CONTENTS

	Page



Report of Independent Registered Public Accounting Firm	2


Audited Consolidated Financial Statements

Consolidated Balance Sheets	3
Consolidated Statements of Income	4
Consolidated Statements of Stockholders’ Equity	5
Consolidated Statements of Comprehensive Income	5
Consolidated Statements of Cash Flow	6
Notes to Consolidated Financial Statements	7-25

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Citrus Corp. and Subsidiaries:

In our opinion, the accompanying consolidated balance sheets and 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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.

/s/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2006

Table of Contents

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)


	December 31,			December 31,
	2005			2004
ASSETS

Current Assets
Cash and cash equivalents	$	21,406		$	11,645
Accounts receivable - customers, net of allowance for doubtful accounts of $23 and $33		41,072			41,475
Income tax receivable		872			-
Materials and supplies		3,077			3,113
Exchange gas receivable		508			1,273
Other		1,184			1,609
Total Current Assets		68,119			59,115

Property, Plant and Equipment, at Cost
Plant in service		4,118,518			4,085,138
Construction work in progress		9,693			12,202
Less - accumulated depreciation and amortization		(1,211,663	)		(1,130,593	)
Property, Plant and Equipment, Net		2,916,548			2,966,747

Other Assets
Unamortized debt expense		5,735			6,788
Regulatory assets		24,092			22,840
Other		74,893			86,446
Total Other Assets		104,720			116,074

Total Assets	$	3,089,387		$	3,141,936


LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities
Long-term debt due within one year	$	14,000		$	14,000
Accounts payable - trade and other		21,325			19,753
Accounts payable - affiliated companies		5,501			13,471
Accrued interest		15,091			15,415
Accrued income taxes		-			6,332
Accrued taxes, other than income		9,090			8,792
Exchange gas payable		5,182			6,539
Other		6,161			3,094
Total Current Liabilities		76,350			87,396

Deferred Credits
Deferred income taxes		758,775			746,035
Regulatory liabilities		9,049			5,303
Other		33,070			7,971
Total Deferred Credits		800,894			759,309

Long-Term Debt		922,355			1,010,825

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		(13,162	)		(15,800	)
Retained earnings		668,678			665,934
Total Stockholders' Equity		1,289,788			1,284,406

Total Liabilities and Stockholders' Equity	$	3,089,387		$	3,141,936

See accompanying notes

Table of Contents

CITRUS CORP. AND SUSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(In Thousands)


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2005			2004			2003
Revenues
Transportation of natural gas	$	476,049		$	467,422		$	442,010
Gas sales		-			44,996			104,370

Total Revenues		476,049			512,418			546,380

Costs and Expenses
Natural gas purchased		-			48,921			99,130
Operations and maintenance		78,829			81,306			117,086
Depreciation and amortization		91,125			68,053			64,522
Taxes, other than income taxes		34,306			29,565			27,436

Total Costs and Expenses		204,260			227,845			308,174


Operating Income		271,789			284,573			238,206

Other Income (Expense)
Interest expense and related charges, net		(79,290	)		(93,771	)		(103,109	)
Other, net		6,531			15,262			(10,327	)

Total Other Income (Expense)		(72,759	)		(78,509	)		(113,436	)

Income Before Income Taxes		199,030			206,064			124,770

Income Tax Expense		75,086			79,220			48,554

Net Income	$	123,944		$	126,844		$	76,216

See accompanying notes

Table of Contents

CITRUS CORP. AND SUSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In Thousands)


		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
		2005			2004			2003
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 (Loss):
Balance, beginning of period			(15,800	)		(17,247	)		(18,453	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges			2,638			1,447			1,206

Balance, end of period			(13,162	)		(15,800	)		(17,247	)

Retained Earnings
Balance, beginning of period			665,934			679,090			602,874
Net income			123,944			126,844			76,216
Dividends			(121,200	)		(140,000	)		-

Balance, end of period			668,678			665,934			679,090

Total Stockholders' Equity		$	1,289,788		$	1,284,406		$	1,296,115




CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)


	Year Ended					Year Ended			Year Ended
		December 31,				December 31,			December 31,
		2005				2004			2003

Net income		$	123,944		$	126,844		$	76,216
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges			2,638			1,447			1,206

Total Comprehensive Income		$	126,582		$	128,291		$	77,422

See accompanying notes

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2005			2004			2003

Cash Flows From Operating Activities
Net income	$	123,944		$	126,844		$	76,216
Adjustments to reconcile net income to net cash provided by
operating activities:

Depreciation and amortization		91,125			68,053			64,522
Amortization of hedge loss in other comprehensive income		2,638			1,447			1,206
Amortization of discount and swap hedge loss in long term debt		530			535			392
Amortization of regulatory assets and other deferred charges		3,380			5,205			12,000
Amortization of debt costs		1,053			922			1,840
Deferred income taxes		12,740			69,694			24,271
Price risk management fair market valuation revaluation		-			10,980			20,599
Price risk management gain on buy out of gas sales contract		-			(19,884	)		-
Allowance for funds used during construction		(1,441	)		(1,136	)		(5,804	)
Gain on sale of assets		(1,236	)		-			-
Changes in operating assets and liabilities:
Accounts receivable		403			(1,762	)		9,443
Materials and supplies		36			(198	)		422
Accounts payable		(10,567	)		(17,258	)		(7,029	)
Accrued interest		(324	)		(3,639	)		(2,291	)
Accrued income tax		(7,204	)		5,183			4,796
Accrued other tax		298			(1,556	)		1,241
Other current assets and liabilities		2,900			(7,926	)		9,863
Price risk management assets and liabilities		-			(23,162	)		7,150
Other assets and liabilities		36,140			2,169			14,561
Net Cash Provided by Operating Activities		254,415			214,511			233,398

Cash Flows From Investing Activities
Additions to property, plant and equipment		(37,306	)		(47,694	)		(142,334	)
Allowance for funds used during construction		1,441			1,136			5,804
Retirements and disposition of property, plant and equipment, net		(304	)		(1,288	)		(1,074	)
Proceeds from sale of assets		1,715			-			-
Net Cash Used in Investing Activities		(34,454	)		(47,846	)		(137,604	)

Cash Flows From Financing Activities
Dividends		(121,200	)		(140,000	)		-
Borrowings under the revolving credit facility		223,000			155,000			-
Payments on the revolving credit facility		(298,000	)		(38,000	)		-
Long-term debt finance costs		-			(746	)		-
Payments on long-term debt		(14,000	)		(256,500	)		(85,250	)
Net Cash Used in Financing Activities		(210,200	)		(280,246	)		(85,250	)

Net Increase (Decrease) in Cash and Cash Equivalents		9,761			(113,581	)		10,544

Cash and Cash Equivalents, Beginning of Period		11,645			125,226			114,682

Cash and Cash Equivalents, End of Period	$	21,406		$	11,645		$	125,226


Supplemental Disclosure of Cash Flow Information
Interest paid (net of amounts capitalized)	$	74,714		$	95,770		$	105,641
Income tax paid	$	67,018		$	4,432		$	19,488

See accompanying notes

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Reporting Entity

Citrus Corp. (Citrus), a holding company formed in 1986, owns 100 percent of the stock of Florida Gas Transmission Company (FGT), Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2005 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), as transferred by Southern in December 2003, and 50 percent by CrossCountry 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 is 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).

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).

Trading ceased all trading activities effective the fourth quarter of 1997, but continued to fulfill its obligations under the remaining gas purchase and gas sale contracts through the last quarter of 2004. During 2004, it sold its remaining contracts and no longer has any gas purchase or gas sale contracts.

CESI primarily provides transportation management and financial services to customers of FGT. CESI terminated its Operations and Maintenance (O&M) business in 2003, due to increased insurance costs and pipeline integrity legislation that affects operators.

(2)

Significant Accounting Policies

Principles of Consolidation - The consolidated financial statements include the accounts of Citrus and its wholly owned subsidiaries. All significant inter company transactions and accounts have been eliminated in consolidation.

Reclassifications - Certain reclassifications have been made to the consolidated financial statements for prior years to conform to the current year presentation with no impact on reported net income, stockholders’ equity or net cash provided by, or used in, operating, investing or financing activities.

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, which were $0.0 and $0.3 million at December 31, 2005 and 2004, respectively.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounting for 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 (see Note 4). Instruments utilized in connection with trading activities 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 hedged item in the statement of operations (see 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 (see Note 10) - Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities. 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 percent. FGT has provided for depreciation of assets net of estimated salvage value, on a straight-line basis, at an annual composite rate of 2.56 percent, 1.74 percent and 1.66 percent for 2005, 2004 and 2003, respectively. The increase was due to higher depreciation reflecting the settlement of FGT’s rate case effective April 1, 2005. The overall remaining useful life for FGT’s assets at December 31, 2005 is 39 years.

Property, Plant and Equipment 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 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 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 totaled $1.4, $1.1 and $5.8 million in 2005, 2004 and 2003, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying income statement.

The Company applies the provisions of SFAS No. 143, Accounting for Asset Retirement Obligation (ARO) 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. The Company adopted SFAS No. 143, beginning January 1, 2003.

FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” 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 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 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.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 (see 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.

Compressor Overhaul Expenditures - In 2003 FGT changed its method of accounting for compressor overhaul costs by adopting a method for current expense recognition of compressor overhaul costs as part of operation and maintenance expenses. This change was the result of the Company’s determination that such costs previously deferred would not be recovered through future tariff rates. In prior years, such costs were deferred and amortized ratably over the expected service life of the applicable overhaul item. An unamortized balance of $7.0 million applicable to the previous method was expensed in 2003. An additional amount of $6.5 million related to 2003 overhaul costs, which would have been deferred under the previous methodology, was also expensed. In 2004 the remaining unamortized overhaul costs of $0.5 million were expensed and an additional $4.8 million of overhaul costs related to 2004 overhauls were also expensed under the new methodology. In 2005 compressor overhaul expenses amounted to $4.7 million.

Income Taxes (see 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.

Trade Receivables - The Company establishes an allowance for doubtful accounts on trade receivables 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 trade accounts receivable charged against the allowance for doubtful accounts were $0.0, $0.0 and $0.3 million in 2005, 2004 and 2003, respectively.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Recent Accounting Pronouncements

FIN No. 46R-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities” issued by FASB in March 2005 addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (VIE) or a potential VIE when specific conditions exist. An implicit variable interest is an implied pecuniary interest in an entity that indirectly changes with changes in the fair value of the entity’s net assets exclusive of variable interests. Implicit variable interests may arise from transactions with related parties, as well as from transactions with unrelated parties. It will be effective, for entities to which the interpretations of FIN 46(R) have been applied, beginning December 31, 2005. As of March 31, 2005 the Company adopted this FSP, which had no impact on its consolidated financial statements.

FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvements and Modernization Act of 2003” (the Medicare Prescription Drug Act) issued by the FASB in May 2004 requires entities to record the impact of the Medicare Prescription drug Act as an actuarial gain in the post-retirement benefit obligation for post-retirement benefit plans that provide drug benefits covered by the legislation. The Company adopted this FSP as of March 31, 2005 and recognized an actuarial gain of $0.2 million during the year ended December 31, 2005. The effect of this FSP may vary as a result of any future changes to the Company’s benefit plans (see Note 6).

(3) Long-Term Debt and Other Financing Arrangements

Long-term debt outstanding at December 31, 2005 and 2004 was as follows (in thousands):

	2005			2004
Citrus
8.490% Notes due 2007-2009	$	90,000		$	90,000
		90,000			90,000
FGT
9.750% Notes due 1999-2008		19,500			26,000
10.110% Notes due 2009-2013		70,000			70,000
9.190% Notes due 2005-2024		142,500			150,000
7.625% Notes due 2010		325,000			325,000
7.000% Notes due 2012		250,000			250,000
Revolving Credit Agreement due 2007		42,000			117,000
Unamortized Debt Discount and Swap Loss		(2,645	)		(3,175	)
		846,355			934,825

Total Outstanding		936,355			1,024,825
Long-Term Debt Due Within One Year		(14,000	)		(14,000	)
	$	922,355		$	1,010,825

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Annual maturities of long-term debt outstanding as of December 31, 2005 were as follows (in thousands):

Year
2006	$	14,000
2007		86,000
2008		44,000
2009		51,500
2010		346,500
Thereafter		397,000
	$	939,000

On August 13, 2004 FGT entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50.0 million and terminating in August 2007. 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, 2005 and 2004 the amounts drawn under the 2004 Revolver were $42.0 million and $117.0 million, respectively, with a weighted average interest rate of 5.11 percent (based on LIBOR plus 0.70 percent) and 3.24 percent (based on LIBOR plus 0.80 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, 2005 and 2004 were $0.4 million and $0.7 million, respectively.

FGT may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if FGT and the Company’s consolidated debt does not exceed specific debt to total capitalization ratios, as defined. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

Citrus has note agreements that contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets, and the payment of dividends, and require maintaining certain restrictive financial covenants, including required ratios of consolidated funded debt to consolidated capitalization, consolidated funded debt to consolidated net tangible assets, and consolidated cash flow to consolidated fixed charges. The agreements relating to FGT's promissory notes 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, 2005 and 2004 the Company believes it was in compliance with both affirmative and restrictive covenants of the note agreements.

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 FGT and Citrus to be accelerated.

(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 was calculated 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 internal valuation 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 and $20.6 million for 2004 and 2003, respectively. During the fourth quarter of 2004 the Company sold its remaining derivative contract without a material impact on the consolidated statements of income.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 payment 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 payment will be paid to the third-party from any future proceeds resulting from the settlement of either the ENA bankruptcy claims or the Duke Energy LNG Sales, Inc. (Duke) litigation (see below).

Due to a dispute (see Note 14) during 2003 Duke purported to terminate and discontinued performance under a natural gas purchase and supply contract between it and Trading, which Trading subsequently terminated. As a result of this contract termination, during 2003 Trading discontinued the application of fair market value accounting for this contract, and wrote off the value of the related price risk management assets as a charge to Other Income (Expense) in the accompanying statement of income. Pursuant to the terms of the contract and also during 2003 Trading issued to Duke, the counterparty, a termination invoice for approximately $187.0 million. As a result of the ongoing litigation regarding this matter, the termination invoice amount was recognized, net of reserves (which includes certain other matters), as an offsetting gain to Other Income (Expense) and is recorded as a long term receivable (see Note 11) of $68.5 and $68.5 million at December 31, 2005 and 2004, respectively.

(5) Income Taxes

The principal components of the Company's net deferred income tax liabilities at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004

Deferred income tax assets Alternative minimum tax credit	$	-	$	9,577
Regulatory and other reserves		8,841		6,295
Other		176		120
		9,017		15,992

Deferred income tax liabilities
Depreciation and amortization		728,444		717,223
Deferred charges and other assets		27,972		27,295
Regulatory costs		4,901		13,264
Other		6,475		4,245
		767,792		762,027

Net deferred income tax liabilities	$	758,775	$	746,035

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Total income tax expense for the years ended December 31, 2005, 2004 and 2003 is summarized as follows (in thousands):

	2005		2004		2003
Current Tax Provision
Federal	$	53,526	$	7,561	$	19,215
State		8,820		1,965		5,068
		62,346		9,526		24,283
Deferred Tax Provision
Federal		11,079		60,808		21,930
State		1,661		8,886		2,341
		12,740		69,694		24,271

Total income tax expense	$	75,086	$	79,220	$	48,554

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company's effective tax rate for the years ended December 31, 2005, 2004 and 2003 are as follows (in thousands):

	2005			2004			2003

Statutory federal income tax provision	$	69,661		$	72,122		$	43,670
State income taxes, net of federal benefit		6,813			7,053			4,816
Other		(1,388	)		45			68

Income tax expense	$	75,086		$	79,220		$	48,554

Effective Tax Rate		37.7	%		38.4	%		38.9	%

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

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

(6) Employee Benefit Plans

During 2003 the employees of the Company were covered under Enron’s employee benefit plans. The Company’s participation in the Enron benefit plans terminated during 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 balance at December 31, 2005 is $1.8 million and is reported in Other Current Liabilities ($0.4 million) and in Other Deferred Credits ($1.4 million) (see Note 12). The anticipated proceeds from Enron for the bankruptcy claim described above was $0.5 million. Such amount was 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 (see Note 8).

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and $1.9 million for 2004 and 2003, respectively. 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 (see Note 8), and a charge to operating expense. In 2004, with the settlement of the rate case (see Note 9), FGT recognized a regulatory asset for its portion, $9.3 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 $1.9 million and $1.4 million for 2005 and 2004, respectively. At December 31, 2005 and 2004 FGT has a remaining regulatory asset balance for this matter of $6.0 million and $7.9 million, respectively. 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 the 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 plans 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, under 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 $0.3 million for the year ended December 31, 2005.

Other Post - Employment Benefits

Enron provided certain post-retirement medical, life insurance and dental benefits (OPEB) to eligible employees and their eligible dependents through November 30, 2004. The net periodic post-retirement benefit costs charged to the Company by Enron were $0.6 and $1.2 million for 2004 and 2003, respectively. Substantially all of these amounts relate to FGT and are being recovered through rates. During the period December 1, 2004 through February 28, 2005 coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits. Effective March 1, 2005 such benefits are provided under an identical plan sponsored by FGT as a single employer post-retirement benefit plan.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FGT was previously 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 provides 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 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. Both motions remain pending in the Enron bankruptcy court. On February 6, 2006 the Nebraska action was dismissed.

With regard to its sponsored plan, FGT has entered into a VEBA trust (the “VEBA Trust”) agreement with Bank One Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, sick, 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 $1.5 million to the VEBA Trust for the year ended December 31, 2005. Upon settlement of the Trust, any distribution of assets FGT receives from the Trust, estimated to be approximately $6.2 million per the Enron filing described above, will be contributed to the VEBA Trust.

Following its November 17, 2004 acquisition by CCEH, 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.

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.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table represents a reconciliation of FGT’s OPEB plan at December 31, 2005:


	Year ended
	December 31,
OPEB (in thousands)	2005

Change in Benefit Obligation
Benefit obligation at plan adoption (1)	$	9,872
Service cost		71
Interest cost		490
Actuarial gain		(3,522	)
Retiree premiums		757
Benefits paid		(1,003	)
Benefit obligation at end of year	$	6,665

Change in Plan Assets
Fair value of plan assets at plan adoption (1) (2)	$	6,240
Return on plan assets		352
Employer contributions		1,494
Retiree premiums		757
Benefits paid		(1,003	)
Fair value of plan assets at end of year	$	7,840

Funded Status
Funded status at end of year	$	1,175
Unrecognized net actuarial gain		(3,348	)
Net liability recognized at December 31, 2005	$	(2,173	)

___________________________

(1)	For purposes of this reconciliation, the plan adoption date is considered to be January 1, 2005.

(2) Plan assets include the amount of assets expected to be received from the Enron Trust.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used to determine FGT’s benefit obligations for the year ended December 31, 2005 were as follows:


As of December 31, 2005

Discount rate		5.50%
Rate of compensation increase		N/A

Health care cost trend rates
(graded to 4.65% by year 2012)		12.00%

FGT’s OPEB benefit costs for the period presented consisted of the following:


	Year Ended
	December 31,
OPEB (in thousands)	2005


Service cost	$	71
Interest cost		490
Expected return on plan assets		(352	)
Amortization of prior service cost		-
Recognized actuarial gain		(174	)

Net periodic benefit cost	$	35

The weighted-average assumptions used to determine FGT’s OPEB benefit costs for the period presented were:


Year Ended December 31, 2005

Discount rate		5.75%
Rate of compensation increase		N/A
Expected long-term return on plan assets		5.00%

Health care cost trend rates
(graded to 4.75% by year 2012)		12.00%

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.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The sensitivity to changes in assumed health care cost trend rates for FGT’s OPEB is as follows:

	One Percentage		One Percentage
	Point Increase		Point Decrease
(in thousands)
Effect on total service and interest cost components	$	19	$	(17	)
Effect on postretirement benefit obligation	$	341	$	(303	)

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 $1.2 million of assets actually in the VEBA Trust at December 31, 2005 is as follows:

	Year Ended
	December 31,
	2005

Equity securities		0	%
Debt securities		0	%
Cash and cash equivalents		100	%
Total		100	%

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(7) Major Customers

Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues for the years ended December 31, 2005, 2004 and 2003 were approximately as listed below (in millions), and in total represented 54%, 50% and 46% of total revenue, respectively.

Customers	2005		2004		2003

Florida Power & Light Company	$	181.5	$	189.5	$	186.6
Teco Energy, Inc.	$	76.1	$	69.0	$	66.1

At December 31, 2005 and 2004 the Company had receivables of approximately $14.8 million and $15.0 million from Florida Power & Light Company and approximately $5.4 million and $5.0 million from Teco Energy, Inc., and subsidiaries, respectively.

(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. The Bankruptcy Court heard arguments on Trading’s claim against ENA and the matter is awaiting decision.

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 (see 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 $4.5, $3.7 and $5.3 million for the years ended December 31, 2005, 2004 and 2003, respectively. The Company’s gas sales were approximately $0.0, $0.1 and $9.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. The Company also purchased gas from affiliates of Enron of approximately $0.0, $5.8 and $3.7 million and from affiliates of El Paso of approximately $0.0, $19.5 and $26.9 million for the years ended December 31, 2005, 2004 and 2003, 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 $6.3, $6.5 and $6.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2004 and 2003 totaled $2.4 and $2.3 million, respectively. Under related agreements, ECS is 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 2004 and 2003 for these services were $0.4 and $0.4 million, respectively. A Netting Agreement, dated 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 has 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 is administered by CrossCountry Energy Services, LLC (CCES), an affiliate of CCEH, which has 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 and $12.1 million, including insurance cost of approximately $6.7 and $6.9 million, for the year ended December 31, 2004 and 2003, respectively. The amount expensed for the seven months period ended July 31, 2005 was approximately $1.5 million.

Effective November 5, 2004 CCEH entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a wholly owned subsidiary of Southern Union. Pursuant to the ASA, Manager is responsible for the operations and administrative functions of the enterprise, CCEH and Manager will share certain operations of Manager and its affiliates, and CCEH will be obligated to bear its share of costs of the Manager and its affiliates, as well as certain transition costs. 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. Transition costs are non-recurring costs of establishing the shared services, including but not limited to severance costs, professional fees, certain transaction costs, and the costs of relocating offices and personnel.

The Company recognizes costs of shared services allocated under the ASA by Southern Union. Amounts expensed by the Company were $1.6 and $0.0 million in the years ended December 31, 2005 and 2004, respectively. Shared services are also exchanged between other affiliate companies.

In 2005, the Company paid a subsidiary of CCEH $9.6 million to settle the Cash Balance Plan obligation, which CCEH effectively paid in conjunction with the 2004 acquisition of the Company.

Citrus paid cash dividends to its shareholders of $121.2, $140.0 and $0.0 million in 2005, 2004 and 2003, respectively.

(9) Regulatory Matters

On October 1, 2003 FGT filed a general rate case, proposing rate increases for all services, based upon a cost of service of approximately $167.0 million for the pre-expansion system and approximately $342.0 million for the incremental system. By order issued October 31, 2003 FERC accepted and suspended the effectiveness of FGT’s proposed rates for the statutory period of five months, effective April 1, 2004. On August 13, 2004 FGT filed a Stipulation and Agreement of Settlement ("Settlement"), which established settlement rates and resolved all issues. The settlement rates became effective on April 1, 2005.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $12-$22 million per year, inclusive of remediation costs. In the August 13, 2004 Settlement of the rate case, FGT has the right to make limited sections 4 filings to recover such costs beginning in April 2006 (if the threshold is met), via a surcharge, 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 in 2005 are expected to create a surcharge of $0.01 per MMBtu effective on April 1, 2006.

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 with Southern Natural Gas Company’s proposed Cypress Pipeline project in Clay County, Florida. The project is expected to be in service in May 2007 and May 2009. The estimated cost of expansion is up to approximately $104 million.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(10) Property, Plant and Equipment

The principal components of the Company's Property, Plant and Equipment at December 31, 2005 and 2004 are as follows (in thousands):

	2005			2004
Transmission Plant	$	2,812,586		$	2,783,798
General Plant		26,383			25,136
Intangible Plant		27,083			23,738
Construction Work-in-progress		9,693			12,202
Acquisition Adjustment		1,252,466			1,252,466
		4,128,211			4,097,340
Less: Accumulated depreciation and amortization		(1,211,663	)		(1,130,593	)
Property, Plant and Equipment, net	$	2,916,548		$	2,966,747

(11) Other Assets

The principal components of the Company's regulatory assets at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004
Ramp-up assets, net (1)	$	12,240	$	12,552
Cash balance plan settlement (see Note 6)		6,047		7,907
OPEB		2,173		-
Environmental non-PCB clean-up cost (see Note 13)		1,000		-
Other miscellaneous		2,632		2,381
Total Regulatory Assets	$	24,092	$	22,840

___________________________

(1) Ramp-up assets is a regulatory asset FGT was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.

The principal components of the Company's other assets at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004
Long-term receivables	$	72,570	$	73,077
Fuel tracker		-		11,165
Other miscellaneous		2,323		2,204
Total Other Assets - Other	$	74,893	$	86,446

(12) Deferred Credits

Regulatory liabilities were $9.0 million and $5.3 million at December 31, 2005 and 2004, respectively. These consisted of balancing tools, which 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.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company's other deferred credits at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004
Post construction mitigation costs	$	2,600	$	3,296
Construction prepayments		4,536		-
Customer deposits (see Note 15)		1,249		1,306
Phase IV retainage & Phase V surety bond		-		1,459
Fuel Tracker		14,477		-
Deferred compensation (see Note 6)		1,425		1,768
Environmental non-PCB clean-up cost reserve (see Note 13)		1,631		-
Tax contingency		2,594		-
Asset retirement obligation (see Note 2)		493		-
OPEB (see Note 6)		2,173		-
Miscellaneous		1,892		142
Total Deferred Credits - Other	$	33,070	$	7,971

(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 is expected to result in increased operating expenses. These increased operating expenses are not expected to 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: 2006 - $0.1 million, 2007 - $0.2 million, 2008 - $0.3 million, 2009 - $0.1 million and 2010 - $0.2 million. The expenditures thereafter are estimated to be $0.9 million for soil and groundwater remediation. The liability is recognized in other current liabilities and other deferred credits (Note 12) and totals $1.7 million. The anticipated costs to April 1, 2010 of $0.8 million have been expensed during the year ended December 31, 2005. FGT recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.0 million as a regulatory asset based on the probability of recovery in rates in its next rate case (Note 11).

As of December 31, 2004, no such liability was recognized since the liability 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) Commitments and Contingencies

In the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. The Company evaluates each of these matters and determines if loss accruals are necessary as required by SFAS No. 5, Accounting for Contingencies. The Company does not expect to experience losses that would be materially in excess of the amount accrued at December 31, 2005, 2004 and 2003.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FGT and Trading have 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’s claim includes rejection damages and delinquent amounts owed under certain transportation agreements, an unpaid promissory note, and other fees for services and imbalances. Subsequent to FGT’s filing its claims, ENA’s firm transportation agreements were permanently relinquished to a creditworthy party, which significantly reduced FGT’s rejection damages. 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. FGT and Enron agreed on the amount of the claim at $13.3 million, with payout subject to the bankruptcy proceedings. FGT assigned its claims to a third party and received $3.4 million in June 2005. In March 2005, ENA filed objections to Trading’s claim. The Bankruptcy court heard arguments on Trading’s claim and the matter is awaiting the court’s decision.

On March 7, 2003 Trading filed a declaratory order action, involving a contract between it and 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 seeks damages and a judicial determination that Duke has 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 has answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit, and that it has breached a “resale restriction” on the gas. Trading disputes that it has breached the agreement, or that any event has 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. 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. Trading has filed additional motions for summary judgment on the loss of supply issue and other remaining issues. Duke has cross-moved and the matters are fully briefed and awaiting decision. This is a disputed matter, and there can be no assurance as to what amounts, if any, Trading will ultimately recover. Management believes that the amount ultimately recovered will not be materially different than the amount recorded as a receivable at December 31, 2005 and that the ultimate resolution of this matter will not have a materially adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Management further believes that claims made by Duke against the Company with regard to this matter do not constitute a liability which would require adjustment to the Company’s consolidated financial statements in accordance with SFAS No. 5, Accounting for Contingencies.

The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages, which may, over the next ten years, impact one or more of FGT’s mainline pipelines that are co-located in FDOT/FTE rights-of-way. Under certain conditions, the 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: (a) FGT is entitled to recover: (i) compensation for all or any part 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 in a prior relocation project (for which an invoice was presented to FDOT/FTE but FDOT/FTE refused to pay). FGT also seeks 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. Trial date is set for June 13, 2006.

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FGT is planning to replace approximately 11.3 miles of its existing 18 and 24 inch pipelines located in FDOT/FTE right of way between Griffin Road and Atlantic Avenue in Broward County, Florida with a single 36” pipeline starting fourth quarter 2006. Estimated cost of this project is $110 million. FGT is also in discussions with the FDOT/FTE related to two other projects, Heft to Griffin (7.5 miles) and Atlantic to Sawgrass (6.8 miles) that may require relocation and replacements of FGT’s 18 and 24 inch pipelines within FDOT/FTE right of way. The total actual amount of miles of pipe to be impacted ultimately for all of the FDOT/FTE widening projects, and the associated relocation and/or right-of-way costs, cannot be determined at this time.

(15) Concentrations of Credit Risk and Other Financial Instruments

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 $1.2 and $1.3 million and prepayments of $0.5 and $1.2 million for 2005 and 2004, 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.

The carrying amounts and fair value of the Company's financial instruments at December 31, 2005 and 2004 are as follows (in thousands):

	2005		2004
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
Long-term debt	$ 939,000	$ 1,054,965	$ 1,028,000	$ 1,193,793

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reasonably approximate their fair value. The book value of the 2004 Revolver approximates its market value given the variable rate of interest. The fair value of long-term debt is based upon market quotations of similar debt at interest rates currently available (see Note 3).

Table of Contents

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(16) Accumulated Other Comprehensive Income

Accumulated other comprehensive income is comprised of deferred gains and (losses) in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges. Such amounts are being amortized over the terms of the hedged debt.

(in thousands)	Termination Date		Original Gain/(Loss)			Amortization Period		Annual Amortization			Balance at December 31, 2005			Balance at December 31, 2004

Interest rate lock on 7.625% $325 million note due 2010		December 2000	$	(18,724	)		10 years	$	1,872		$	9,206		$	11,078

Interest rate swap loss on 7.0% $250 million note due 2012		July 2002		(12,280	)		10 years		1,228			8,035			9,263

Interest rate swap gain on 9.19% $150 million note due 2005-2024		November 1994		9,236			20 years		(462	)		(4,079	)		(4,541	)
								$	2,638		$	13,162		$	15,800