SOUTHERN UNION CO - 10-K Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2004

X TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM JULY 1, 2004 TO DECEMBER 31, 2004

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.)

One PEI Center, Second Floor	18711
Wilkes-Barre, Pennsylvania	(Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (570) 820-2400

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 whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X No ___

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

Indicate by check mark whether the registrant is an Accelerated Filer (as defined in Exchange Act Rule 12b-2).

Yes X No ___

The aggregate market value of the Common Stock held by non-affiliates of the Registrant as of June 30, 2004 was $1,149,417,692 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2004). 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 ten percent of the Common Stock of the Company.

The number of shares of the registrant's Common Stock outstanding on February 28, 2005 was 105,555,332.

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 9, 2005, are incorporated by reference into Part III.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2004

Table of Contents

		Page
	PART I
ITEM 1.	Business.	1
ITEM 2.	Properties.	18
ITEM 3.	Legal Proceedings.	18
ITEM 4.	Submission of Matters to a Vote of Security Holders.	18
	PART II
ITEM 5.	Market for the Registrant’s Common Stock and Related Stockholder Matters.	19
ITEM 6.	Selected Financial Data.	21
ITEM 7.	Management's Discussion and Analysis of Results of Operations and Financial Condition.	22
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	51
ITEM 8.	Financial Statements and Supplementary Data.	53
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	53
ITEM 9A.	Controls and Procedures.	54
ITEM 9B.	Other Information.	55
	PART III
ITEM 10.	Directors and Executive Officers of the Registrant.	55
ITEM 11.	Executive Compensation.	55
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management.	55
ITEM 13.	Certain Relationships and Related Transactions.	55
ITEM 14.	Principal Accountants Fee and Services.	55
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K.	56
Signatures.
Index to the Consolidated Financial Statements.		F-1

PART I

ITEM 1. Business.

Our Business

Introduction

Southern Union Company (Southern Union and together with its subsidiaries, the Company) was incorporated under the laws of the State of Delaware in 1932. The Company owns and operates assets in the regulated 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, and its subsidiaries (hereafter collectively referred to as Panhandle Energy), the Company owns and operates more than 10,000 miles of interstate pipelines that transport up to 5.4 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 the Transwestern Pipeline (TWP) and Florida Gas Transmission Company (FGT) interstate pipelines, comprising more than 7,400 miles of interstate pipelines that transport up to approximately 4.1 Bcf/d which stretch from western Texas and the San Juan Basin to markets throughout the Southwest and to California, and from the Gulf Coast to Florida. Through Southern Union’s three regulated utility divisions -- Missouri Gas Energy, PG Energy and New England Gas Company, the Company serves over 962,000 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 twelve-month period ending June 30 to a twelve-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.

CCE Holdings’ Acquisition of CrossCountry Energy - On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron and its subsidiaries for a purchase price of approximately $2,450,000,000 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 $175,000,000 in cash. Following these transactions, CCE Holdings owns 100% of TWP and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of FGT. An affiliate of El Paso Corporation owns the remaining 50% of Citrus. The Company funded its $590,500,000 equity investment in CCE Holdings through borrowings of $407,000,000 under an equity bridge-loan facility, net proceeds of $142,000,000 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 $42,000,000 under its existing revolving credit facility. Subsequently, in February 2005 Southern Union issued 2,000,000 of its 5% Equity Units from which it received net proceeds of approximately $97,405,000, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $332,616,000, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note X - 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.

TWP and FGT are primarily engaged in the interstate transportation of natural gas and are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). TWP owns and operates a bi-directional interstate natural gas pipeline system (approximately 2,400 miles in length and having 2.0 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. FGT 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.

Acquisition of Panhandle Energy - On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation for approximately $581,729,000 in cash and 3,000,000 shares of Southern Union common stock (before adjustment for subsequent stock dividends) valued at approximately $48,900,000 based on market prices at closing of the Panhandle Energy acquisition and in connection therewith incurred transaction costs of approximately $31,922,000. At the time of the acquisition, Panhandle Energy had approximately $1,157,228,000 of debt principal outstanding that it retained. The Company funded the cash portion of the acquisition with approximately $437,000,000 in cash proceeds it received from the January 1, 2003 sale of its Texas operations, approximately $121,250,000 of the net proceeds it received from concurrent common stock and equity unit offerings (see Note X - Stockholders’ Equity) and with working capital available to the Company. The Company structured the Panhandle Energy acquisition and the sale of its Texas operations to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The acquisition was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted within the United States of America with the purchase price paid and acquisition costs incurred by the Company allocated to Panhandle Energy’s net assets as of the acquisition date. The Panhandle Energy assets acquired and liabilities assumed were recorded at their estimated fair value as of the acquisition date based on the results of outside appraisals. Panhandle Energy’s results of operations have been included in the Consolidated Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years.

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 the 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) which is a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings), 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, the 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 5.4 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.

Sale of Southern Union Gas and Related Assets - Effective January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets to ONEOK for approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In addition to Southern Union Gas, the sale involved the disposition of Mercado Gas Services, Inc. (Mercado), SUPro Energy Company (SUPro), Southern Transmission Company (STC), Southern Union Energy International, Inc. (SUEI), Southern Union International Investments, Inc. (Investments) and Norteño Pipeline Company (Norteño) (collectively, the Texas Operations). Southern Union Gas distributed natural gas as a public utility to approximately 535,000 customers throughout Texas, including the cities of Austin, El Paso, Brownsville, Galveston and Port Arthur. Mercado marketed natural gas to commercial and industrial customers. SUPro pro-vided propane gas services to approximately 4,000 customers located principally in Austin, El Paso and Alpine, Texas as well as Las Cruces, New Mexico and surrounding communities. STC owned and operated 118.8 miles of intra-state pipeline that served commercial, industrial and utility customers in central, southern and coastal Texas. SUEI and Investments participated in energy-related projects internationally. Energía Estrella del Sur, S. A. de C. V., a wholly-owned Mexican subsidiary of SUEI and Investments, had a 43% equity ownership in a natural gas distribution company, along with other related operations, which served 23,000 customers in Piedras Negras, Mexico, across the border from Southern Union Gas’ Eagle Pass, Texas service area. Norteño owned and operated interstate pipelines that served the gas distribution properties of Southern Union Gas and the Public Service Company of New Mexico. Norteño also transported gas through its interstate network to the country of Mexico for Pemex Gas y Petroquimica Basica. In accordance with accounting principles generally accepted in the United States of America, 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 respective periods.

Other Sales - In July 2001, the Company implemented a cash flow improvement plan that was designed to increase annualized pre-tax cash flow from operations by at least $50,000,000 by June 30, 2002. The three-part initiative was composed of strategies designed to achieve results enabling its utility divisions to meet their allowed rates of return, restructure its corporate operations, and accelerate the sale of non-core assets and use the proceeds exclusively for debt reduction. In connection with the cash flow improvement plan and other strategic initiatives, the Company sold certain non-core subsidiaries and assets described below during the period from July 1, 2001 through December 31, 2004.

Subsidiary or Asset Sold	Date Sold	Proceeds	Pre-Tax Gain (Loss)
ProvEnergy Power Company LLC (a)	October 2003	$ 2,175,000	$ (1,150,000)
PG Energy Services’ propane operations (b)	April 2002	2,300,000	1,200,000
Carrizo Springs Pipeline (c)	December 2001	1,000,000	561,000
South Florida Natural Gas and Atlantic Gas Corporation (d)	December 2001	10,000,000	(1,500,000)
Morris Merchants, Inc. (e)	October 2001	1,586,000	--
Valley Propane, Inc. (f)	September 2001	5,301,000	--
ProvEnergy Oil Enterprises (g)	August 2001	15,776,000	--
PG Energy Services’ commercial and industrial gas marketing contracts	July 2001	4,972,000	4,653,000

(a) Provided outsourced energy management services and owned 50% of Capital Center Energy Company LLC.

(b) Sold liquid propane to residential, commercial and industrial customers in northeastern and central Pennsylvania.

(d) South Florida Natural Gas was a natural gas division of Southern Union and Atlantic Gas Corporation was a propane subsidiary of the Company.

(e) Served as a manufacturers’ representative agency for franchised plumbing and heating supplies throughout New England.

(f) Sold liquid propane to residential, commercial and industrial customers in Rhode Island and Massachusetts.

(g )Operated a fuel oil distribution business through its subsidiary, ProvEnergy Fuels, Inc. for residential and commercial customers in Rhode Island and Massachusetts.

Business Segments

The Company’s operations include two reportable segments:

The Transportation and Storage segment, which is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy, which the Company acquired on June 11, 2003; 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.

For a more detailed description of the Company’s reportable segments, see Item 1. Business - Transportation and Storage Segment and Item 1. Business - Distribution Segment.

The Company’s operations also include certain 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, described below, 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 Note XXI - Reportable Segments).

PEI Power Corporation (Power Corp.), an exempt wholesale generator (within the meaning of the Public Utility Holding Company Act of 1935), generates and sells electricity provided by two power plants that share a site in Archbald, Pennsylvania. Power Corp. wholly owns one plant, a 25-megawatt cogeneration facility fueled by a combination of natural gas and methane. Power Corp. owns 49.9% of the second plant, a 45-megawatt natural gas-fired facility, through a joint venture with Cayuga Energy. These plants sell electricity to the broad mid-Atlantic wholesale energy market administered by PJM Interconnection, L.L.C.

Fall River Gas Appliance Company, Inc. rents water heaters and conversion burners (primarily for residential use) to over 13,300 customers and offers service contracts on gas appliances in the city of Fall River and the towns of Somerset, Swansea and Westport, all located in southeastern Massachusetts.

Valley Appliance and Merchandising Company (VAMCO) rents natural gas burning appliances and offers appliance service contract programs to residential customers. During the year ended June 30, 2002, VAMCO provided construction management services for natural gas-related projects to commercial and industrial customers.

·	PG Energy Services, Inc. (Energy Services) offers the inspection, maintenance and servicing of residential and small commercial gas-fired equipment to 16,200 residential and commercial users primarily in central and northeastern Pennsylvania.

·	Alternate Energy Corporation was an energy consulting firm that retained patents on a natural gas/diesel co-firing system and on "Passport" FMS (Fuel Management System) which monitors and controls the transfer of fuel on dual-fuel equipment.

The Company also has corporate operations that do not generate operating revenues. Corporate functions include Accounting, Corporate Communications, Human Resources, Information Technology, Internal Audit, Investor Relations, Environmental, Legal, Payroll, Purchasing, Risk Management, Tax and Treasury.

The Company also has a 50% equity investment in CCE Holdings. Southern Union records its share of CCE Holdings’ net income or loss as earnings from unconsolidated investments (see Note IX - Unconsolidated Investments, for the summarized financial information of CCE Holdings).

The Company also maintains a venture capital investment portfolio. The Company’s significant venture capital investments are listed below.

PointServe, Inc. (PointServe) -- The Company has a remaining investment of $2,603,000 in PointServe, a business-to-business online scheduling solution, after recording non-cash charges of $1,603,000 and $10,380,000 during the years ended June 30, 2004 and 2002, respectively, to recognize a decrease in 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.

Advent Networks, Inc. (Advent) - In December 2004, the Company recorded a total non-cash charge of $16,425,000 to recognize an other-than-temporary impairment of the carrying value of its investment in Advent. This impairment was comprised of a write-down of $4,925,000 and $11,500,000 to the Company’s investment and convertible notes receivable accounts, respectively. The Company reevaluated the fair value of its investment in Advent as a result of Advent's recent efforts to raise additional capital from private investors, which placed a significantly lower valuation on Advent than reflected in the carrying value of the Company’s investment in Advent. The foregoing, as well as certain other factors, led to the non-cash charge discussed above.

Advent believes that its UltraBand(TM) provides cable network overbuilders with a competitive advantage by delivering digital broadband services 40 times faster than digital subscriber lines. Nevertheless, the time and costs necessary to market the UltraBand(TM) technology to potential customers and investors has resulted in Advent experiencing significant strains on working capital and incurring continuing losses. Advent is a closely held, privately owned company and, as such, has no published market value.

After the non-cash write-down, the Company’s remaining investment in Advent as of December 31, 2004, is $508,000. This remaining investment may be subject to future market risk. Additionally, a wholly-owned subsidiary of the Company has guaranteed a $4,000,000 line of credit between Advent and a bank. Advent remains current and is not in default in this line of credit.

In addition to the investment by the Company, certain Southern Union executive officers, directors and employees beneficially own, in the aggregate, approximately 3% of the equity interest of Advent either directly or indirectly. The ownership by executive officers and directors of the Company is unrelated to any ownership by the Company, and those individuals vote their beneficial interest at their own discretion. Currently, Thomas F. Karam and John E. Brennan, officers and directors of the Company, serve as members of Advent’s Board of Directors.

The Company reviews its portfolio of 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: earnings trends and asset quality; near term prospects and financial condition of the issuer; financial condition and prospects of the issuer's region and industry; and Southern Union's intent and ability to retain the investment. If Southern Union determines that the decline in value of an investment security is other-than-temporary, it will record a charge on its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value.

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 also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy, which the Company acquired on June 11, 2003. For the six months ended December 31, 2004 and the year ended June 30, 2004, this segment represented 31 and 27 percent of the Company’s total operating revenues, respectively.

Panhandle Energy owns and operates a large natural gas pipeline network consisting of more than 10,000 miles of pipeline and has peak day delivery capacity of up to 5.4 Bcf/d of natural gas. The pipeline network, consisting of the Panhandle Eastern Pipe Line transmission system, the Trunkline transmission system and the Sea Robin transmission system provides approximately 500 customers in the Midwest and Southwest with a comprehensive array of transportation and storage services. Panhandle Eastern Pipe Line’s transmission system, with approximately 6,500 miles of pipeline, 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, with approximately 3,500 miles of pipeline, 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 and is comprised of approximately 400 miles of pipeline extending approximately 81 miles into the Gulf of Mexico.

In connection with its gas transmission and storage systems, Panhandle Energy owns and operates 48 compressor stations and has five gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma with an aggregate storage capacity of 72 Bcf. Panhandle Energy also has contracts with third parties for approximately 15 Bcf of storage for a total of approximately 87 Bcf of total storage capacity.

Through Trunkline LNG, Panhandle Energy owns and operates a LNG terminal in Lake Charles, Louisiana, which is one of the largest operating LNG facilities in North America based on its current sustainable send out capacity of approximately .63 Bcf/d. Trunkline LNG is currently in the process of expanding the terminal, which will increase sustainable send out capacity to approximately 1.2 Bcf/d and increase terminal storage capacity to 9 Bcf from the current 6.3 Bcf. BG LNG Services has contract rights for the .57 Bcf/d of additional capacity. Construction on the Trunkline LNG expansion project (Phase I) commenced in September 2003 and is expected to be completed with an estimated cost totaling $137,000,000, plus capitalized interest, by the end of 2005. On September 17, 2004, as modified on September 23, 2004, FERC approved Trunkline LNG’s further incremental LNG expansion project (Phase II). Phase II is estimated to cost approximately $77,000,000, plus capitalized interest, and would increase the LNG terminal sustainable send out capacity to 1.8 Bcf/d. 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 this facility.

In September 2004, Trunkline received approval from the FERC of a 30-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. On November 5, 2004, Trunkline filed an amended application with the FERC to change the size of the pipeline from 30-inch diameter to 36-inch diameter to increase throughput capacity for the expansion. The amendment was approved by FERC on February 11, 2005. The Trunkline natural gas pipeline loop associated with the LNG terminal is estimated to cost $50,000,000, plus capitalized interest.

A significant portion 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 contract to 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. For the six months ended December 31, 2004 and for the years ended June 30, 2004 and 2003 (from June 12 to June 30, 2003), Panhandle Energy’s combined throughput was 630 trillion British thermal units (TBtu), 1,321 TBtu and 69 TBtu, respectively.

The weighted average remaining life of firm transportation contracts at December 31, 2004 for Panhandle Eastern Pipe Line and Trunkline are 3 years and 10 years, respectively. Firm transportation contracts for Sea Robin represent only approximately 3 percent of annual flow and have a one-year remaining life but are evergreen and tied to the life of the reserves.

The weighted average remaining life of firm storage contracts at December 31, 2004 for Panhandle Eastern Pipe Line and Trunkline are 3 years.

Beginning January 2002, Trunkline LNG entered into a 22-year contract with BG LNG Services for all the uncommitted capacity at the Lake Charles, Louisiana facility.

Panhandle Energy and its subsidiaries have contracts with four significant customers: Proliance, BG LNG Services, CMS Energy and Ameren Corp. Revenues from these contracts represented 50 percent of the Transportation and Storage segment’s operating revenues for the six months ended December 31, 2004. Contracts with Proliance were extended in 2003 and have an average remaining term of 5 years. BG LNG Services’ contracts will expand with the completion of Phase I in late 2005 and Phase II in mid-2006, and are expected to increase annual gross reservation revenues by approximately $39,000,000 and $22,000,000, respectively, as these projects are completed (See Note XVI - 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 $11,000,000 and $5,000,000, respectively, from 2004 firm transport levels. Panhandle Energy has recently amended and extended through 2008 certain contracts with Consumers Energy, a subsidiary of CMS Energy, that were originally set to expire in late 2005. These 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. It is expected that the reduction in revenue will be such that, if the new contract had been in effect for the six months ended December 31, 2004, Panhandle Energy’s operating revenues and CMS Energy’s percent of such operating revenue would have been approximately two percent lower. The majority of Panhandle Eastern Pipe Line and Trunkline contracts with Ameren Corp subsidiaries Union Electric, Central Illinois Light Company, Illinois Power and Central Illinois Public Service expire in 2006.

Panhandle Energy’s customers may change throughout the year as a result of capacity release provisions that allow them to release all or part of their capacity, either permanently for the full term of the contract or temporarily. 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.

For the six months ended December 31, 2004 and for the year ended June 30, 2004, Panhandle Energy’s operating revenues were $242,743,000 and $490,883,000, respectively, of which 86 percent each was generated from transportation and storage services, 12 percent each from LNG terminalling services, and 2 percent each from other services, respectively. Aggregate sales to Panhandle Energy’s top ten customers accounted for 67 and 70 percent of the segment’s operating revenues for the six months ended December 31, 2004 and for the year ended June 30, 2004, respectively (see Item 7. Management’s Discussion and Analysis - Other Matters (Customer Concentrations)). 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 operating revenues for the six months ended December 31, 2004 or the year ended June 30, 2004.

For information about the operating revenues, operating income, assets and other financial information relating to the Transportation and Storage segment, see ITEM 7. Management’s Discussion and Analysis - Business Segment Results and Note XXI - Reportable Segments.

Regulation

Panhandle Energy is subject to regulation by various federal, state and local governmental agencies, including those specifically described below. See also Item 1. Business - Environmental.

FERC has comprehensive jurisdiction over Panhandle Eastern Pipe Line, Southwest Gas Storage, Trunkline, Trunkline LNG and Sea Robin as natural gas companies within the meaning of the Natural Gas Act of 1938. FERC 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, and Southwest Gas Storage hold certificates of public convenience and necessity issued by the 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 Secretary of Energy regulates the importation and exportation of natural gas and has delegated various aspects of this jurisdiction to FERC and the Department of Energy’s Office of Fossil Fuels.

Panhandle Energy is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of 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, see Item 7. Management’s Discussion and Analysis - Other Matters.

Competition

Panhandle Energy’s interstate pipelines compete with 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 flexibility, and reliability of service. Panhandle Energy’s direct competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas Pipeline Company of America, Northern Border Pipeline Company, Texas Gas Transmission Corporation, Northern Natural Gas Company and Vector Pipeline.

Natural gas competes with other forms of energy available to Panhandle Energy’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.

Distribution Segment

Services

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. Collectively, the utility divisions serve over 962,000 residential, commercial and industrial customers through local distribution systems consisting of 14,326 miles of mains, 9,654 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 occurring in the traditional winter heating season in the first and fourth calendar quarters. For the six months ended December 31, 2004 and the year ended June 30, 2004, this segment represented 69 and 73 percent of the Company’s total operating revenues, respectively.

For the six months ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002, the Distribution segment’s operating revenues were $549,346,000, $1,304,405,000, $1,158,964,000, and $968,933,000 respectively; average customers served totaled 946,123, 949,978, 944,657, and 935,229 respectively; and gas volumes sold or transported totaled 69,435 million cubic feet (MMcf), 173,119 MMcf, 188,333 MMcf and 166,793 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 six months ended December 31, 2004, or the year ended June 30, 2004.

For information about the operating revenues, operating income, assets and other financial information relating to the Distribution segment, see ITEM 7. Management’s Discussion and Analysis - Business Segment Results and Note XXI - Reportable Segments.

A description of each of the Company’s regulated utility divisions follows.

Missouri Gas Energy - Missouri Gas Energy, headquartered in Kansas City, Missouri, serves approximately 501,000 customers in central and western Missouri (including Kansas City, St. Joseph, Joplin and Monett) through a local distribution system that consists of approximately 8,132 miles of mains, 5,073 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 are regulated by the Missouri Public Service Commission (MPSC) (see Item 1. Business - Regulation and Rates).

The Missouri Gas Energy customers served, gas volumes sold or transported and weather-related information for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003 and 2002 are as follows:

	Six Months Ended
	December 31,				Year Ended June 30,
		2004			2004			2003			2002
Average number of customers:
Residential			429,292			432,037			430,861			428,215
Commercial			61,273			61,957			60,774			58,749
Industrial and irrigation			98			95			99			95
Total average customers served			490,663			494,089			491,734			487,059
Transportation customers			879			786			461			378
Total average gas sales and transportation customers			491,542			494,875			492,195			487,437

Gas sales in MMcf:
Residential			10,837			36,880			39,821			35,039
Commercial			5,082			16,026			17,399			15,686
Industrial and irrigation			152			338			391			417
Gas sales billed			16,071			53,244			57,611			51,142
Net change in unbilled gas sales			3,503			112			61			(16	)
Total gas sales			19,574			53,356			57,672			51,126
Gas transported			11,721			25,761			26,893			27,324
Total gas sales and gas transported			31,295			79,117			84,565			78,450

Gas sales revenues (thousands of dollars):
Residential		$	139,086		$	395,350		$	337,293		$	293,544
Commercial			58,054			163,826			138,676			122,619
Industrial and irrigation			1,923			3,943			3,930			3,841
Gas revenues billed			199,063			563,119			479,899			420,004
Net change in unbilled gas sales revenues			38,124			2,024			3,434			(2,278	)
Total gas sales revenues			237,187			565,143			483,333			417,726
Gas transportation revenues			4,095			8,702			8,439			8,202
Other revenues			4,261			7,013			5,017			3,199
Total operating revenues		$	245,543		$	580,858		$	496,789		$	429,127

Weather:
Degree days (a)			1,669			4,770			5,105			4,419
Percent of 10-year measure (b)			81	%		92	%		98	%		85	%
Percent of 30-year measure (b)			82	%		92	%		98	%		85	%

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

PG Energy - PG Energy, headquartered in Wilkes-Barre, Pennsylvania, serves approxi-mately 159,000 customers in northeastern and central Pennsylvania (including Wilkes-Barre, Scranton and Williamsport) through a local distribution system that consists of approximately 2,520 miles of mains, 1,515 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 are regulated by the Pennsylvania Public Utility Commission (PPUC) (see Item 1. Business - Regulation and Rates).

The PG Energy customers served, gas volumes sold or transported and weather-related information for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003 and 2002 are as follows:

	Six Months Ended
	December 31,				Year Ended June 30,
		2004			2004			2003			2002
Average number of customers:
Residential			142,152			142,422			141,769			141,223
Commercial			14,469			14,384			14,141			13,707
Industrial and irrigation			115			116			120			104
Public authorities and other			345			340			337			212
Total average customers served			157,081			157,262			156,367			155,246
Transportation customers			586			602			613			624
Total average gas sales and transportation customers			157,667			157,864			156,980			155,870

Gas sales in MMcf:
Residential			4,649			17,133			18,372			15,053
Commercial			2,130			6,505			6,732			5,325
Industrial and irrigation			150			379			376			277
Public authorities and other			99			290			334			145
Gas sales billed			7,028			24,307			25,814			20,800
Net change in unbilled gas sales			1,955			34			4			(22	)
Total gas sales			8,983			24,341			25,818			20,778
Gas transported			11,679			26,007			28,366			26,976
Total gas sales and gas transported			20,662			50,348			54,184			47,754

Gas sales revenues (thousands of dollars):
Residential		$	60,119		$	183,941		$	175,337		$	148,860
Commercial			23,699			62,407			56,730			46,307
Industrial and irrigation			1,512			3,376			2,895			2,509
Public authorities and other			1,057			2,676			2,667			1,233
Gas revenues billed			86,387			252,400			237,629			198,909
Net change in unbilled gas sales revenues			20,310			929			135			(276	)
Total gas sales revenues			106,697			253,329			237,764			198,633
Gas transportation revenues			5,968			13,872			15,389			14,445
Other revenues			523			1,713			1,515			4,779
Total operating revenues		$	113,188		$	268,914		$	254,668		$	217,857

Weather:
Degree days			2,301			6,240			6,654			5,373
Percent of 10-year measure			100	%		103	%		109	%		89	%
Percent of 30-year measure			98	%		100	%		106	%		86	%

New England Gas Company - New England Gas Company, headquartered in Providence, Rhode Island, serves approximately 302,000 custo-mers 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 3,674 miles of mains and 3,066 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 are regulated by the Rhode Island Public Utilities Commission (RIPUC) and Massachusetts Department of Telecommunications and Energy (MDTE), respectively (see Item 1. Business - Regulation and Rates).

The New England Gas Company’s customers served, gas volumes sold or transported and weather-related information for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003 and 2002 are as follows:

	Six Months Ended
	December 31,				Year Ended June 30,
		2004			2004			2003			2002
Average number of customers:
Residential			270,051			269,926			268,312			265,206
Commercial			25,358			25,798			25,442			21,696
Industrial and irrigation			207			226			225			3,472
Public authorities and other			50			47			41			43
Total average customers served			295,666			295,997			294,020			290,417
Transportation customers			1,248			1,242			1,462			1,505
Total average gas sales and transportation customers			296,914			297,239			295,482			291,922

Gas sales in MMcf:
Residential			6,633			24,194			25,481			19,975
Commercial			2,669			9,753			9,725			6,196
Industrial and irrigation			1,234			1,968			2,055			3,271
Public authorities and other			9			25			28			23
Gas sales billed			10,545			35,940			37,289			29,465
Net change in unbilled gas sales			3,074			(1,366	)		1,336			(333	)
Total gas sales			13,619			34,574			38,625			29,132
Gas transported			3,859			9,080			10,959			11,457
Total gas sales and gas transported			17,478			43,654			49,584			40,589

Gas sales revenues (thousands of dollars):
Residential		$	97,734		$	307,534		$	290,370		$	236,331
Commercial			35,509			111,712			97,091			65,316
Industrial and irrigation			11,581			16,542			15,045			20,804
Public authorities and other			193			437			511			275
Gas revenues billed			145,017			436,225			403,017			322,726
Net change in unbilled gas sales revenues			36,914			5,231			(12,657	)		(17,788	)
Total gas sales revenues			181,931			441,456			390,360			304,938
Gas transportation revenues			5,952			11,835			14,906			13,820
Other revenues			2,732			1,343			2,242			3,190
Total operating revenues		$	190,615		$	454,634		$	407,508		$	321,948

Weather:
Degree days			2,004			5,644			6,143			4,980
Percent of 10-year measure			98	%		102	%		111	%		88	%
Percent of 30-year measure			96	%		98	%		107	%		85	%

Gas Supply

The cost and reliability of natural gas service is dependent upon the Company's ability to contract for favorable mixes of long-term and short-term gas supply arrangements and through favorable fixed and variable trans-portation con-tracts. The Com-pany has been directly acquiring its gas supplies since the mid-1980s when inter-state pipeline sys-tems opened their systems for trans-portation service. The Company has the organization, personnel and equip-ment neces-sary to dispatch and moni-tor gas volumes on a daily, hourly and even a real-time basis to ensure reliable service to customers.

FERC required the "unbundling" of services offered by interstate pipe-line companies beginning in 1992. As a re-sult, gas pur-chasing and transportation decisions and associated risks have been shifted from the pipeline com-panies to the gas dis-tributors. The increased demands on distributors to effectively manage their gas supply in an environ-ment of volatile gas prices provides an advantage to distribution companies such as Southern Union who have demon-strated a history of con-tracting favorable and efficient gas supply arrangements in an open market system.

For the six months ended December 31, 2004, the majority of the gas requirements for the utility operations of Missouri Gas Energy and PG Energy were delivered under short- and long-term trans-portation 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 trans-portation contracts through four major pipeline companies. Collectively, these con-tracts have various expira-tion dates ranging from 2005 through 2018. Missouri Gas Energy and New England Gas Company have firm supply commit-ments for all areas that are supplied with gas purchased under short- and long-term arrangements. PG Energy has firm supply commit-ments 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 7 Bcf of storage capacity, respectively, to assist in meeting peak demands. Storage capacity, which remained unchanged for the six-month period ended December 31, 2004, approximated 31% of the utility operations’ annual distribution volumes, for the year ended June 30, 2004.

Gas sales and/or transportation contracts with interruption provisions, whereby 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 for higher priority customers, have been utilized for load management by Southern Union and the gas industry as a whole. In addition, during times of special supply problems, curtail-ments of deliveries to customers with firm contracts may be made in accordance with guidelines estab-lished by appropriate federal and state regulatory agencies. There have been no supply-related curtailments of deliveries to 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 have historic-ally competed with alterna-tive energy sources, particularly electri-city, propane, fuel oil, coal, natural gas liquids and other refined products available in their service areas. At present rates, the cost of electricity to residential and com-mer-cial customers in the Com-pany's regulated utility ser-vice 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 cus-to-mers has also 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. However, in no instance may PG Energy sell gas under this special arrange-ment for less than its average commodity cost of gas purchased during the month. Competition between 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. This competition, however, affects the nationwide market for natural gas. Addi-tionally, the general economic conditions in the Company's regulated utility service areas continue to affect certain customers and market areas, thus impacting the results of the Company's operations.

The Company’s regulated utility operations are not currently in significant direct competition with any other distributors of natural gas to residential and small commercial customers within their service areas. In 1999, the Commonwealth of Pennsylvania enacted the Natural Gas Choice and Competition Act, which extended the ability to choose suppliers to small commercial and residential customers. 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, higher-than-normal wholesale prices for natural gas has prevented suppliers from offering competitive rates.

Regulation and Rates

The utility operations are regulated as to rates 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 7. Management’s Discussion and Analysis - Other Matters (Regulatory).

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 cus-tomers 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.

Gas service rates are established by regulatory authorities to permit utilities the opportunity to recover operating, admin-istrative and financing costs, and the opportunity to earn a reasonable return on equity. Gas costs are billed to cus-tomers 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 signifi-cant 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 to its regulators using an his-toric 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 may not reflect the operating costs at the time new rates are put into effect. In Pennsylvania, a future test year is utilized for ratemaking purposes, there-fore, rate orders more closely reflect the operating costs at the time new rates are put into effect.

The monthly customer bill contains a fixed service charge, a usage charge for service to deliver gas, and a charge for the amount of natural gas used. While 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 regula-tions, including pipeline safety requirements of the United States Department of Transportation, 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.

Investment in CCE Holdings

As of December 31, 2004, CCE Holdings is owned 50% by Southern Union, 30% by EFS-PA, LLC (EFS-PA), a wholly-owned subsidiary of General Electric Commercial Finance Energy Financial Services (GE) and 20% by other institutional investors. CCE Holdings acquired 100% of the equity interests of CrossCountry Energy from Enron and its subsidiaries on November 17, 2004. CrossCountry Energy owns 100% of TWP and 50% of the stock of Citrus, which in turn owns 100% of FGT. An affiliate of El Paso Corporation owns the remaining 50% interest in Citrus. CrossCountry Energy operates the TWP and FGT natural gas pipeline networks, consisting of more than 7,400 miles of pipeline having the capacity to transport approximately 4.1 Bcf/d of natural gas.

TWP is an open-access interstate pipeline. Through its approximately 2,400-mile pipeline system having a mainline capacity of 2.0 Bcf/d, TWP transports natural gas from western Texas, Oklahoma, eastern New Mexico and the San Juan Basin in northwest New Mexico and southern Colorado primarily to the California market and to pipeline interconnects off the east end of its system. TWP has access to three significant gas basins for its gas supply: the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. 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 Western Texas) as well as markets in the west (California). This flexibility allows TWP to respond to regional supply and demand fundamentals and to optimize the utilization of its pipeline infrastructure. TWP’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

Currently, TWP is constructing 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 expansion will include looping of existing pipeline segments and additional horsepower at existing compressor stations. Currently, 310 MMcf/d of this expanded capacity has been subscribed under 10-year contracts. TWP filed a FERC certificate on April 7, 2004 and received authorization to proceed with construction in August 2004. TWP commenced compressor station construction in early October 2004 and expects to put the expansion facilities in-service in May 2005. Capital costs for the expansion project are expected to be approximately $150,000,000, split evenly over 2004 and 2005. As of December 31, 2004, TWP has spent $76,000,000 on the San Juan expansion.

The FGT pipeline system currently extends for approximately 5,000 miles from south Texas through the Gulf Coast region of the United States to south Florida, and has a mainline capacity of 2.1 Bcf/d. FGT’s pipeline system primarily receives natural gas from natural gas producing basins in the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 90% of the natural gas consumed in the state. In addition, FGT’s pipeline system operates and maintains more than 40 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to most major natural gas producing regions in the contiguous 48 states of the United States and Canada.

TWP and FGT earn the majority of their revenue by entering into firm transportation contracts, reserving capacity for customers to transport natural gas on their pipelines, whereby customers pay for transportation capacity on a system regardless of whether it is utilized. TWP and FGT also earn variable revenue from charges assessed on each unit of transportation provided. In addition, TWP and FGT gas volumes retained for the operation of their pipeline system are, if not physically burned in the systems’ compressors, sold as operational gas when conditions warrant. The weighted average remaining life of firm transportation contracts at December 31, 2004 for TWP and FGT are 3 years and 11 years, respectively.

TWP and FGT are subject to the rules and regulations of FERC.

TWP is subject to competition from other transporters into the southern California market, including El Paso Natural Gas Company, Kern River Gas Transmission Company, Pacific Gas and Electric Company and intrastate producers and affiliates of Southern California Gas Company.

Historically, the FGT pipeline system has been the only interstate natural gas pipeline system serving peninsular Florida. This changed on May 28, 2002, when Phase I of the Gulfstream expansion was placed into service. Gulfstream is sponsored by a joint venture of Duke Energy Corporation and The Williams Companies. FGT also serves the Florida panhandle, where it competes with Gulf South Pipeline Company and the natural gas transportation business of the South Georgia system, which is owned by Southern Natural Gas. FGT faces additional competition, to a lesser degree, from alternate fuels, including residual fuel oil, in the Florida market, as well as from proposed LNG regasification facilities.

Southern Union’s share of TWP’s (50%) and FGT’s (25%) results of operations for the six months ended December 31, 2004 (from November 17, 2004 to December 31, 2004) were recorded through the Company’s equity interest (50%) in CCE Holdings and are presented as earnings from unconsolidated investments in the Consolidated Statement of Operations. For summarized financial information concerning CCE Holdings’ for the period from November 17, 2004 to December 31, 2004, see Note IX - Unconsolidated Investments.

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 con-trol environmental impacts. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. For additional information concerning the impact of environmental regulation on the Company, see Item 7. Management’s Discussion and Analysis - Other Matters (Contingencies).

Real Estate

The Company owns certain real estate that is neither material nor critical to its operations.

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. 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.

Employees

As of January 31, 2005, the Company had 2,922 employees, of whom 2,046 are paid on an hourly basis and 876 are paid on a salary basis. Of the 2,046 hourly paid employees, unions represent 63%. Of those employees represented by unions, Missouri Gas Energy employs 36%, New England Gas Company employs 32%, Panhandle Energy employs 18% and PG Energy employs 14%.

Persons employed by segment are as follows: Distribution segment—1,807 persons; Transportation and Storage segment—1,012 persons; All Other subsidiary operations - 15 persons. In addition, the corporate office of Southern Union employed a total of 88 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, 2005, CCE Holdings had 701 employees.

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 PG Energy’s 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). During the year ended June 30, 2002, the Company agreed to five-year contracts with two bargaining units representing employees of New England Gas Company’s Providence operations (formerly ProvEnergy), which were effective May 2002; a four-year contract with one bargaining unit representing employees of New England Gas Company’s Cumberland operations, effective April 2002; and a four-year contract with one bargaining unit representing employees of New England Gas Company’s Fall River operations, effective April 2002.

Following its acquisition by the Company in June 2003, Panhandle Energy initiated a workforce reduction initiative designed to reduce the workforce by approximately 5 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 6 percent. Certain of the approximately $7,700,000 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 $6,000,000.

In August 2001, the Company implemented a corporate reorganization and restructuring which was initially announced in July 2001 as part of the cash flow improvement plan. Actions taken included (i) the offering of voluntary Early Retirement Programs (ERPs) in certain of its Distribution segment operations and (ii) a limited reduction in force (RIF) within its corporate operations. ERPs, providing for increased benefits for those electing retirement, were offered to approxi-mately 325 eligible employees across the Distribution segment operations, with approximately 59% of such eligible employees accepting. The RIF was limited solely to certain corporate employees in the Company's Austin and Kansas City offices where forty-eight employees were offered severance packages (see Item 7. Management’s Discussion and Analysis - Results of Operations (Business Restructuring Charges)).

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 six months ended December 31, 2004, or the years ended June 30, 2004, and 2003. During the year ended June 30, 2002, the Company and one of five bargaining units representing New England Gas Company employees (comprising approximately 8% of Southern Union’s total workforce at that time) were unable to reach agreement on the renewal of a contract that expired in January 2002. The resulting work stoppage, which did not have a material adverse effect on the Company’s results of operations, financial condition or cash flows for the year ended June 30, 2002, was settled in May 2002 when the Company and the bargaining unit agreed to a new five-year contract.

Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (the SEC). Any document that Southern Union files with the SEC may be read or copied at the SEC’s public reference room at 450 Fifth Street, N.W., 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.southernunionco.com. The information on Southern Union’s Web site is not incorporated by reference into and is not made a part of this report.

In August 2004, Southern Union, by and through the Audit Committee of the Board of Directors, adopted a New Code of Ethics and Business Conduct (the Code). The newly-adopted Code replaces a previously-existing Code and is designed to reflect recent commentaries and interpretations 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.

In October 2004, Southern Union, by and through the Corporate Governance Committee of its board of directors, adopted Corporate Governance Guidelines, which were revised in January 2005 (the 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 Companion 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 (570) 820-2418 or by writing to:

Southern Union Company

Attn: Corporate Secretary

One PEI Center

Wilkes-Barre, PA 18711

ITEM 2. Properties.

Transportation and Storage

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

Other

Power Corp. retains ownership of two electric power plants that share a site in Archbald, Pennsylvania. Power Corp. acquired the first plant, a 25-megawatt cogeneration facility fueled by a combination of natural gas and methane, in November 1997. During the year ended June 30, 2001, Power Corp. constructed an additional 45-megawatt, natural gas-fired plant through a joint venture with Cayuga Energy. Power Corp. owns 49.9% of the second plant.

ITEM 3. Legal Proceedings.

See Note XVIII - Commitments and Contingencies for a discussion of the Company's legal pro-ceedings. See ITEM 7. Management’s Discussion and Analysis - Other Matters (Cautionary Statement Regarding Forward-Looking Information).

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

Southern Union held its Annual Meeting of Stockholders on October 28, 2004. The following matter was submitted for a vote by Southern Union’s security holders:

(I)	A proposal to elect the following three persons to serve as Class II directors until the 2007 Annual Meeting of Stockholders or until their successors are duly elected and qualified was approved, and the number of votes for the nominees elected were as follows:

	Votes	Votes
Director	For	Withheld

Kurt A. Gitter	75,225,836	1,150,970
Adam M. Lindemann	62,061,565	14,315,241
George Rountree, III	74,916,441	1,460,365

PART II

ITEM 5. Market for the Registrant’s Common Stock and Related Stockholder Matters.

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 July 1, 2002 are set forth below:

	$/Share
	High		Low

January 1 to February 28, 2005	$	25.67	$	21.81

(Quarter Ended)
December 31, 2004		24.97		20.50
September 30, 2004		20.65		18.00

(Quarter Ended)
June 30, 2004		20.33		17.98
March 31, 2004		18.81		16.90
December 31, 2003		17.82		15.88
September 30, 2003		17.00		14.10

(Quarter Ended)
June 30, 2003		16.19		10.98
March 31, 2003		15.62		10.96
December 31, 2002		15.41		9.21
September 30, 2002		15.48		9.25

Holders

As of February 28, 2005, there were 6,878 holders of record of Southern Union's common stock, and 105,555,332 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.

On February 28, 2005, 85,954,252 shares of Southern Union's common stock were held by non-affiliates (any director or executive officer, any of their immediate family members, or any holder known to be the beneficial owner of 10% or more of shares outstanding).

Dividends

Provisions in certain of Southern Union’s long-term debt and its bank credit facilities limit the payment of cash or asset divi-dends 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.

Southern Union has 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 5%. There have been no cash dividends on its common stock during this period. On August 31, 2004, July 31, 2003, and July 15, 2002, the Company distributed its annual 5% common stock dividend to stockholders of record on August 20, 2004, July 17, 2003, and July 1, 2002, respectively. A portion of the 5% 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.

Equity Compensation Plans

Equity compensation plans approved by stockholders include (i) the 2003 Stock and Incentive Plan, and (ii) the 1992 Long-Term Stock Incentive Plan (the 1992 Plan) in which options are still outstanding but no shares are available for future grant as the 1992 Plan expired on July 1, 2002. Under both plans, stock options are issued at the fair market value on the date of grant and typically vest ratably over 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 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 and the number of shares remaining available for issuance as of December 31, 2004:

			Number of Securities
			Remaining Available for
			Future Issuance Under
	Number of Securities		Equity Compensation
	to be issued Upon	Weighted-Average	Plans (excluding
	Exercise of	Exercise Price of	securities
Plan Category	Outstanding Options	Outstanding Options	reflected in first column)
Plans approved by shareholders	2,941,391	$14.41	6,620,773
Plans not approved by shareholders	664,564	$ 9.70	--

ITEM 6. Selected Financial Data.

	As of and for the
	six months ended
	December 31,			As of and for the year ended June 30,
		2004(a)		2004(b)		2003(b)		2002(c)		2001(d)		2000(e)
		(dollars in thousands, except in share amounts)
Total operating revenues		$ 794,338		$ 1,799,774		$1,188,500		$ 980,614		$ 1,461,811			$	566,833
Net earnings (loss):
Continuing operations (f)		6,088		101,339		43,669		1,520		40,159				(10,251	)
Discontinued operations (g)		--		--		32,520		18,104		16,524				20,096
Available for common shareholders		6,088		101,339		76,189		19,624		57,285				9,845
Net earnings (loss) per diluted
common share (h):
Continuing operations		0.07		1.30		0.70		0.02		0.64				(.19	)
Discontinued operations		--		--		0.52		0.29		0.27				0.37
Available for common shareholders		0.07		1.30		1.22		0.31		0.91				0.18
Total assets		5,568,289		4,572,458		4,590,938		2,680,064		2,907,299				2,021,460
Stockholders’ equity		1,497,557		1,261,991		920,418		685,346		721,857				735,455
Current portion of long-term debt and
capital lease obligation			89,650		99,997		734,752		108,203		5,913			2,193
Long-term debt and capital lease
obligation, excluding current portion		2,070,353		2,154,615		1,611,653		1,082,210		1,329,631				733,744
Company-obligated mandatorily
redeemable preferred securities
of subsidiary trust		--		--		100,000		100,000		100,000				100,000
Average customers served (i)		946,123		948,831		945,705		942,849		970,927				605,000

(a)

The Company’s investment in CCE Holdings, which is accounted for using the equity method, is included in the Company’s Consolidated Balance Sheet at December 31, 2004. The Company’s share of net income or loss from CCE Holdings is recorded as earnings from unconsolidated investments in the Company’s Consolidated Statement of Operations since November 17, 2004.

(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 June 11, 2003. For these reasons, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years.

(c)

Effective July 1, 2001, the Company has ceased amortization of goodwill pursuant to the Financial Accounting Standards Board Standard 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 $8,990,000. See Note VII - Goodwill and Intangibles and Note XIV - 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 and are included in the Company's Consolidated Balance Sheet at June 30, 2001. The results of operations for the New England 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 the acquisitions is not comparable to the same periods in prior years.

(e)

The Pennsylvania Operations were acquired on November 4, 1999 and were accounted for as a purchase. The Pennsylvania Operations’ assets were included in the Company's Consolidated Balance Sheet at June 30, 2000 and its results of operations have been included in the Company's Consolidated Statement of Operations since November 4, 1999. For these reasons, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years.

(f)	Net earnings from continuing operations are net of dividends on preferred stock of $8,683,000 and $12,686,000 for the six months ended December 31, 2004 and the year ended June 30, 2004, respectively.

(g)

Effective January 1, 2003, the Company sold its Southern Union Gas Company natural gas operating division and related assets, which have been accounted for as discontinued operations in the Consolidated Statement of Operations for the respective periods presented in this document. Net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs, in accordance with generally accepted accounting principles. 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, Inc. in the sale of the Texas Operations.

(h)

Earnings per share for all periods presented were computed based on the weighted average number of shares of common stock and common stock equivalents out-standing during the period adjusted for the 5% stock dividends distributed on August 31, 2004, July 31, 2003, July 15, 2002, August 30, 2001 and June 30, 2000.

(i) Includes average customers served by continuing operations.

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

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 footnotes 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 Southern Union’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 Southern Union’s results of operations on a consolidated basis and on a segment basis for each reportable segment, and information relating to Southern Union’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.

Overview

On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron and its subsidiaries for a purchase price of approximately $2,450,000,000 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 $175,000,000 in cash. Following these transactions, CCE Holdings owns 100% of TWP and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of FGT. An affiliate of El Paso Corporation owns the remaining 50% of Citrus. The Company funded its $590,500,000 equity investment in CCE Holdings through borrowings of $407,000,000 under an equity bridge-loan facility, net proceeds of $142,000,000 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 $42,000,000 under its existing revolving credit facility. Subsequently, in February 2005 Southern Union issued 2,000,000 of its 5% Equity Units from which it received net proceeds of approximately $97,405,000, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $332,616,000, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note X - 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.

On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation for approximately $581,729,000 in cash and 3,000,000 shares of Southern Union common stock (before adjustment for subsequent stock dividends) valued at approximately $48,900,000 based on market prices at closing of the Panhandle Energy acquisition and in connection therewith incurred transaction costs of approximately $31,922,000. At the time of the acquisition, Panhandle Energy had approximately $1,157,228,000 of debt principal outstanding that it retained. The Company funded the cash portion of the acquisition with approximately $437,000,000 in cash proceeds it received from the January 1, 2003 sale of its Texas operations, approximately $121,250,000 of the net proceeds it received from concurrent common stock and equity unit offerings (see Note X - Stockholders’ Equity) and with working capital available to the Company. The Company structured the Panhandle Energy acquisition and the sale of its Texas operations to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The acquisition was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted within the United States of America with the purchase price paid and acquisition costs incurred by the Company allocated to Panhandle Energy’s net assets as of the acquisition date. The Panhandle Energy assets acquired and liabilities assumed were recorded at their estimated fair value as of the acquisition date based on the results of outside appraisals. Panhandle Energy’s results of operations have been included in the Consolidated Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years.

Effective January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets to ONEOK for approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance with accounting principles generally accepted within the United States of America, 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.

Business Strategy

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

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, Southern Union has been successful in reducing costs while integrating back-office and support functions with that of the Company’s local natural gas distribution operations. Further, Southern Union will continue to focus each of its gas distribution operations 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.

Strengthening the Company’s balance sheet while maintaining an investment grade rating and credit profile. Southern Union will continue to pursue opportunities to enhance its credit profile through further diversification of regulated cash flow and earnings sources and reduce its ratio of total debt to total capitalization 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 and CCE Holdings’ acquisition of CrossCountry Energy in November 2004 diversified the Company’s regulated cash flow and earnings sources. In addition, the completion of Southern Union’s common stock and equity units offerings in February 2005 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, Southern Union will continue to pursue growth opportunities through the expansion of its existing asset base. Identified opportunities include the Company’s current and planned expansion of Panhandle Energy’s LNG facility, the construction of laterals to transport the additional capacity created by such expansion, TWP’s current expansion of its San Juan lateral, and FGT’s proposed Phase VII expansion.

Selectively acquiring regulated businesses primarily within the natural gas industry. Southern Union’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 recently completed acquisition of Panhandle Energy and CCE Holdings’ acquisition of CrossCountry Energy, Southern Union will continue to evaluate opportunities within the regulated 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

The Company’s results of operations are discussed on a consolidated basis and on a segment basis for each of the two reportable segments. The Company’s reportable segments include the Transportation and Storage segment and the Distribution segment. Segment results of operations are presented on an operating income basis, which is one of the financial measures that the Company uses to internally manage its business. For additional segment reporting information, see Note XXI - Reportable Segments.

Consolidated Results -- Six Months Ended December 31, 2004 and 2003

The following table provides selected financial data regarding the Company’s consolidated results of operations for the six months ended December 31, 2004 and 2003:


	Six Months Ended December 31,
	2004			2003
	*(thousands of dollars)*
Operating income (loss):
Distribution segment	$	19,396		$	32,916
Transportation and storage segment		90,121			90,430
All other		(1,783	)		(736	)
Corporate		(803	)		(3,344	)
Total operating income		106,931			119,266

Other income (expenses):
Interest		(64,898	)		(66,600	)
Earnings from unconsolidated investments		4,745			112
Other, net		(18,080	)		4,299
Total other expenses, net		(78,233	)		(62,189	)

Earnings before income tax		28,698			57,077
Federal and state income tax		13,927			22,362
Net earnings		14,771			34,715

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

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

Net Earnings Available for Common Shareholders. Net earnings available for common shareholders were $6,088,000 ($.07 per diluted share, hereafter referred to as per share) for the six months ended December 31, 2004 compared with $30,711,000 ($.40 per share) for the same period in 2003. The $24,623,000 decrease was primarily due to the following:

·	a $13,520,000 decrease in operating income from the Distribution segment (see Business Segment Results - Distribution Segment);

·	a $309,000 decrease in operating income from the Transportation and Storage segment (see Business Segment Results - Transportation and Storage Segment);

·	a $1,047,000 increase in operating loss from subsidiary operations included in All Other category (see All Other Operations);

·	a $22,379,000 increase in other expense (see Other, Net); and

·	a $4,679,000 increase in preferred stock dividends (see Preferred Stock Dividends).

The above items were partially offset by the following:

·	a $2,541,000 decrease in corporate costs (see Corporate);

·	a $1,702,000 decrease in interest expense (see Interest Expense);

·	a $4,633,000 increase in earnings from unconsolidated investments (see Earnings from Unconsolidated Investments); and

·	a $8,435,000 decrease in income tax expense (see Federal and State Income Taxes).

All Other Operations. Operating loss from subsidiary operations included in the All Other category for the six months ended December 31, 2004 increased by $1,047,000, or 142%, to $1,783,000. The increase in All Other operating loss primarily reflects a $1,474,000 charge recorded by PEI Power Corporation in 2004 to provide for the estimated future debt service payments in excess of projected tax revenues for the tax incremental financing obtained for the development of PEI Power Park.

Corporate. Operating loss from Corporate operations for the six months ended December 31, 2004 decreased by $2,541,000, or 76%, to $803,000. The decrease in Corporate operating loss primarily relates to lower legal fees and provisions for legal matters in 2004, and the impact of the direct allocation and recording of various services provided by Corporate to CCE Holdings in 2004 which were not applicable in 2003 due to the timing of the Company’s investment in CCE Holdings. These items were partially offset by increased outside service fees related to Sarbanes-Oxley Section 404 documentation procedures.

Interest Expense. Total interest expense for the six months ended December 31, 2004 decreased by $1,702,000, or 3%, to $64,898,000. Interest expense in 2004 was positively impacted by decreased dividends of $3,160,000 on preferred securities of subsidiary trust (the Preferred Securities), decreased interest expense of $530,000 on the $311,087,000 bank note (the 2002 Term Note) and decreased interest expense of $339,000 related to other long-term debt of the Company. The decrease in the Preferred Securities dividends was due to the redemption of the Preferred Securities on October 31, 2003 (see Note XII - Preferred Securities). The decrease in the 2002 Term Note interest expense was due to the principal repayment of $85,000,000 of the 2002 Term Note since December 31, 2003. These reductions were partially offset by $2,740,000 of interest expense recorded in 2004 related to the $407,000,000 bridge loan (the Bridge Loan) that was used to finance a portion of the Company’s investment in CCE Holdings and 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). The average rate of interest on all debt increased from 5.1% in 2003 to 5.5% in 2004.

Interest expense on short-term debt for the six months ended December 31, 2004 decreased by $1,061,000, or 21%, to $3,920,000, primarily due to the decrease in the average amount of short-term debt outstanding from $240,383,000 during 2003 to $121,712,000 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 markets issuances over the amounts used for the redemption of securities. The average rate of interest on short-term debt increased from 2.1% to 2.8% in 2004.

Earnings from Unconsolidated Investments. Earnings from unconsolidated investments for the six months ended December 31, 2004 and 2003 were $4,745,000 and $112,000, respectively. The increase in earnings from unconsolidated investments in 2004 is primarily due to $4,645,000 of earnings from CCE Holdings, which the Company acquired an interest in on November 17, 2004.

Other, Net. Other expense, net for the six months ended December 31, 2004 was $18,080,000 compared with other income of $4,299,000 for the same period in 2003. Other expense in 2004 includes charges of $16,425,000 to reserve for the impairment of the Company’s investment in a technology company 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, net of $4,299,000 for the six months ended December 31, 2003 includes a gain of $6,123,000 on the early extinguishment of debt and income of $1,527,000 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 $1,603,000 and $1,150,000 to reserve for the impairment of Southern Union’s investments in a technology company and an energy-related joint venture, respectively, and $655,000 of legal costs associated with the collection of damages from former Arizona Corporation Commission James Irvin related to the Southwest litigation.

Federal and State Income Taxes. Federal and state income tax expense for the six months ended December 31, 2004 and 2003 was $13,927,000 and $22,362,000, respectively. The Company’s consolidated federal and state effective income tax rate was 49% and 39% in 2004 and 2003, respectively. The increase in the effective federal and state income tax rate in 2004 is primarily the result of the $70,000,000 taxable dividend paid by Citrus to CCE Holdings on November 17, 2004, that was used by CCE Holdings to fund a portion of its acquisition of CrossCountry Energy. The Company recorded $2,450,000 of tax expense on its share of the dividend ($35,000,000), which includes the benefit of a dividends received deduction.

As a result of the Citrus dividend, a deferred income tax asset was established for the difference between the book and tax basis in CCE Holdings and a corresponding valuation allowance in the amount of $11,942,000 was established. The valuation allowance will be released in future periods should the excess of tax basis over book basis decrease.

The Company’s overall state effective income tax rate increased .06% from 2003 to 2004 due to the effect of the state apportionment factors of CCE Holdings.

Preferred Stock Dividends. Dividends on preferred securities for the six months ended December 31, 2004, and 2003 were $8,683,000, and $4,004,000, respectively. On October 8, 2003, the Company issued $230,000,000 of 7.55% Non-Cumulative Preferred Stock, Series A to the public. See Note XII - Preferred Securities.

Employees. The Company’s operations employed 2,910 and 2,913 individuals as of December 31, 2004 and 2003, respectively. After gas purchases and taxes, employee costs and related benefits are the Company’s most significant expense. Such expense includes salaries, payroll and related taxes, and employee benefits such as health, savings, retirement and educational assistance. For information concerning labor agreements entered into by the Company during the relevant periods, see Item 1. Business - Employees.

Consolidated Results - Years Ended June 30, 2004, 2003 and 2002

The following table provides selected financial data regarding the Company’s consolidated results of operations for the years ended June 30, 2004, 2003 and 2002:

	Years Ended June 30,
	2004			2003			2002
	*(thousands of dollars)*
Operating income (loss):
Distribution segment	$	118,894		$	142,762		$	135,502
Transportation and storage segment		193,502			9,628			--
All other		(3,514	)		13			--
Business restructuring charges		--			--			(29,159	)
Corporate		(3,555	)		(10,039	)		(15,218	)
Total operating income		305,327			142,364			91,125

Other income (expenses):
Interest		(127,867	)		(83,343	)		(90,992	)
Dividends on preferred securities of subsidiary trust		--			(9,480	)		(9,480	)
Earnings from unconsolidated investments		200			422			1,420
Other, net		5,468			17,979			12,858
Total other expenses, net		(122,199	)		(74,422	)		(86,194	)

Federal and state income taxes		69,103			24,273			3,411
Net earnings from continuing operations		114,025			43,669			1,520

Discontinued operations:
Earnings from discontinued operations before
income taxes		--			84,773			29,801
Federal and state income taxes		--			52,253			11,697
Net earnings from discontinued operations		--			32,520			18,104

Net earnings		114,025			76,189			19,624

Preferred stock dividends		(12,686	)		--			--

Net earnings available for common shareholders	$	101,339		$	76,189		$	19,624

Net Earnings Available for Common Shareholders - 2004 Compared to 2003. Net earnings available for common shareholders were $101,339,000 ($1.30 per share) for the year ended June 30, 2004 compared with $76,189,000 ($1.22 per share) for the same period in 2003. The $25,150,000 increase reflects a $57,670,000 increase in net earnings available for common shareholders from continuing operations (hereafter referred to as net earnings from continuing operations) and a $32,520,000 decrease in net earnings from discontinued operations, as further discussed below.

Net earnings from continuing operations were $101,339,000 ($1.30 per share) for the year ended June 30, 2004 compared with $43,669,000 ($.70 per share) for the same period in 2003. The increase was primarily due to the following:

·	a $183,874,000 increase in operating income from the Transportation and Storage segment (see Business Segment Results - Transportation and Storage Segment);

·	a $6,484,000 decrease in corporate costs (see Corporate); and

·	a $9,480,000 decrease in dividends on preferred securities of subsidiary trust (see Dividends on Preferred Securities of Subsidiary Trust).

The above items were partially offset by the following:

·	a $23,868,000 decrease in operating income from the Distribution segment (see Business Segment Results - Distribution Segment);

·	a $3,527,000 decrease in operating income from subsidiary operations included in the All Other category (see All Other Operations);

·	a $44,524,000 increase in interest expense (see Interest Expense);

·	a $222,000 decrease in earnings from unconsolidated investments;

·	a $12,511,000 decrease in other income (see Other, Net);

·	a $44,830,000 increase in income tax expense (see Federal and State Income Taxes); and

·	a $12,686,000 increase in preferred stock dividends (see Preferred Stock Dividends).

Net earnings from discontinued operations were nil for the year ended June 30, 2004 compared with $32,520,000 ($.52 per share) for the same period in 2003. The Company sold its Texas operations effective January 1, 2003 (see Discontinued Operations).

Net Earnings Available for Common Shareholders - 2003 Compared to 2002. Net earnings available for common shareholders were $76,189,000 ($1.22 per share) for the year ended June 30, 2003 compared with $19,624,000 ($.31 per share) for the same period in 2002. The $56,565,000 increase reflects a $42,149,000 increase in net earnings from continuing operations and a $14,416,000 increase in net earnings from discontinued operations, as further discussed below.

Net earnings from continuing operations were $43,669,000 ($.70 per share) for the year ended June 30, 2003 compared with $1,520,000 ($.02 per share) for the same period in 2002. The increase was primarily due to the following:

·	a $7,260,000 increase in operating income from the Distribution segment (see Business Segment Results - Distribution Segment);

·	a $9,628,000 increase in operating income from the Transportation and Storage segment (see Business Segment Results - Transportation and Storage Segment);

·	a $13,000 increase in operating income from subsidiary operations included in the All Other category;

·	a total of $29,159,000 in business restructuring charges, recorded during 2002 with no comparable charge in 2003 (see Business Restructuring Charges);

·	a $5,179,000 decrease in corporate costs (see Corporate);

·	a $7,649,000 decrease in interest expense (see Interest Expense); and

·	a $5,121,000 increase in other income (see Other, Net).

The above items were partially offset by the following:

·	a $998,000 decrease in earnings from unconsolidated investments;

·	a $20,862,000 increase in income tax expense (see Federal and State Income Taxes).

Net earnings from discontinued operations were $32,520,000 ($.52 per share) for the year ended June 30, 2003 compared with $18,104,000 ($.29 per share) for the same period in 2002. The $14,416,000 increase was primarily due to the recording of an $18,928,000 after-tax gain on the sale of the Texas operations (see Discontinued Operations).

All Other Operations. Operating income from subsidiary operations included in the All Other category for the year ended June 30, 2004 decreased by $3,527,000, resulting in a net operating loss of $3,514,000. The decrease in All Other operating income primarily reflects a $2,985,000 charge recorded by PEI Power Corporation in 2004 to provide for the estimated future debt service payments in excess of projected tax revenues for the tax incremental financing obtained for the development of PEI Power Park.

Business Restructuring Charges. Business reorganization and restructuring initiatives were commenced in August 2001 as part of a previously announced cash flow improvement plan. Actions taken included (i) the offering of voluntary Early Retirement Programs (ERPs) in certain of its operating divisions and (ii) a limited reduction in force (RIF) within its corporate offices. ERPs, providing for increased benefits for those electing retirement, were offered to approximately 325 eligible employees across the Company's operating divisions, with approximately 59% of such eligible employees accepting. The RIF was limited solely to certain corporate employees in the Company's Austin and Kansas City offices where forty-eight employees were offered severance packages. In connection with the corporate reorganization and restructuring efforts, the Company recorded a charge of $30,553,000 during the quarter ended September 30, 2001. This charge was reduced by $1,394,000 during the quarter ended June 30, 2002, as a result of the Company’s ability to negotiate more favorable terms on certain of its restructuring liabilities. The charge included: $16,400,000 of voluntary and accepted ERP’s, primarily through enhanced benefit plan obligations, and other employee benefit plan obligations; $6,800,000 of RIF within the corporate offices and related employee separation benefits; and $6,000,000 connected with various business realignment and restructuring initiatives. All restructuring actions were completed as of June 30, 2002.

Corporate. Operating loss from corporate operations for the year ended June 30, 2004 decreased by $6,484,000, or 65%, to $3,555,000. The decrease in Corporate operating loss primarily reflects the impact of the direct allocation and recording of various services provided by Corporate to Panhandle Energy in 2004 that were not applicable for the same period in 2003 due to the timing of the Panhandle Energy acquisition.

Operating loss from Corporate operations for the year ended June 30, 2003 decreased by $5,179,000, or 34%, to $10,039,000. The decrease in Corporate operating loss primarily reflects the impact of the previously discussed business reorganization and restructuring initiatives that were commenced in August 2001.

Interest Expense. Total interest expense for the year ended June 30, 2004 increased by $44,524,000, or 53%, to $127,867,000. Interest expense in 2004 was impacted by interest expense on Panhandle Energy debt of $47,628,000 (net of $10,783,000 of amortization of debt premiums established in purchase accounting related to the Panhandle Energy acquisition) and by $3,160,000 related to dividends on preferred securities of subsidiary trust (see Dividends on Preferred Securities of Subsidiary Trust). This increase was partially offset by decreased interest expense of $4,366,000 on the $311,087,000 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 $200,000,000 of the 2002 Term Note since its inception. Panhandle Energy’s debt premium amortization is expected to be lower in 2005 than during 2004 due to post-acquisition debt retirements, while cash interest should be lower and partially offset the lower premium amortization. The average rate of interest on all debt decreased from 5.6% in 2003 to 5.1% in 2004.

Interest expense on short-term debt for the year ended June 30, 2004 decreased by $627,000, or 7%, to $8,041,000, primarily due to the decrease in the average amount of short-term debt outstanding from $223,350,000 to $163,200,000 during the year. The decrease in the average amount of short-term debt outstanding during 2004 was primarily due to cash generated from operations, the excess proceeds from capital markets issuances over the amounts used for the redemption of securities, and the reduction of the Company’s beginning of the year cash balances. Draws on short-term debt arise as Southern Union is required to make payments to natural gas suppliers in advance of the receipt of cash payments from the Company’s customers and to fund other working capital requirements, if other funds are not then available. The average rate of interest on short-term debt decreased from 2.4% to 2.0% in 2004.

Total interest expense for the year ended June 30, 2003 decreased by $7,649,000, or 8%, to $83,343,000. Interest expense decreased by $9,181,000 in 2003 on the $311,087,000 2002 Term Note due to reductions in LIBOR rates during 2003 and the principal repayment of $100,000,000 of the 2002 Term Note during 2003. The Company recorded $1,760,000 in interest on long-term debt related to the Panhandle Energy properties in 2003.

Interest expense on short-term debt for the year ended June 30, 2003 increased by $1,481,000, or 21%, to $8,668,000, primarily due to the increase in the average amount of short-term debt outstanding from $176,600,000 to $223,350,000 during the year. The increase in the average amount of short-term debt outstanding during 2003 was primarily due to (i) higher than normal short-term debt outstanding due to high gas costs and accounts receivable in 2003 and (ii) the repayment of various principal amounts of the 2002 Term Note and other long-term debt with borrowings under the Company’s credit facilities. The average rate of interest on short-term debt decreased from 3.2% to 2.4% in 2003.

Dividends on Preferred Securities of Subsidiary Trust. Dividends on preferred securities of subsidiary trust during the years ended June 30, 2004, 2003 and 2002 were nil, $9,480,000 and $9,480,000, respectively. Effective July 1, 2003, the Company adopted the Financial Accounting Standards Board (FASB) standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which requires dividends on preferred securities of subsidiary trusts to be classified as interest expense; the reclassification of amounts reported as dividends in prior periods is not permitted. In accordance with the Statement, $3,160,000 of dividends on preferred securities of subsidiary trust recorded by the Company during the period July 1, 2003 to October 31, 2003 were classified as interest expense in 2004 (see Interest Expense). On October 1, 2003, the Company called the Subordinated Notes for redemption, and the Subordinated Notes and Preferred Securities were redeemed on October 31, 2003 (see Note XII - Preferred Securities).

Other, Net. Other income, net for the year ended June 30, 2004 was $5,468,000 compared with $17,979,000 for the same period in 2003. Other income in 2004 includes a gain of $6,354,000 on the early extinguishment of debt and income of $2,230,000 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 $1,603,000 and $1,150,000 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 associated with the Company’s attempt to collect damages from former Arizona Corporation Commissioner James Irvin related to the Southwest litigation.

Other income, net, for the year ended June 30, 2003 of $17,979,000 includes a gain of $22,500,000 on the settlement of the Southwest litigation and income of $2,016,000 generated from the sale and/or rental of gas-fired equipment and appliances. These items were partially offset by $5,949,000 of legal costs related to the Southwest litigation and $1,298,000 of selling costs related to the Texas operations’ disposition.

Other income, net, for the year ended June 30, 2002 of $12,858,000 includes gains of $17,166,000 generated through the settlement of several interest rate swaps, the recognition of $6,204,000 in previously recorded deferred income related to financial derivative energy trading activity, a gain of $4,653,000 realized through the sale of marketing contracts held by Energy Services, income of $2,234,000 generated from the sale and/or rental of gas-fired equipment and appliances, a gain of $1,200,000 realized through the sale of the propane assets of Energy Services and $1,004,000 of realized gains on the sale of investment securities. These items were partially offset by a non-cash charge of $10,380,000 to reserve for the impairment of the Company’s investment in a technology company, $9,100,000 of legal costs associated with Southwest, and a $1,500,000 loss on the sale of South Florida Natural Gas and Atlantic Gas Corporation (the Florida Operations).

Federal and State Income Taxes. Federal and state income tax expense from continuing operations for the years ended June 30, 2004, 2003 and 2002 was $69,103,000, $24,273,000 and $3,411,000, respectively. The Company’s consolidated federal and state effective income tax rate was 38%, 36% and 69% in 2004, 2003 and 2002, respectively. The fluctuation in the effective federal and state income tax rate in 2004 compared with 2003 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 year in 2004. The fluctuation in the effective federal and state income tax rate in 2003 compared with 2002 is primarily the result of non-tax deductible write-off of goodwill in 2002 as a result of the sale of the Florida Operations, along with the change in the level of pre-tax earnings.

Preferred Stock Dividends. Dividends on preferred securities for the years ended June 30, 2004, 2003 and 2002 were $12,686,000, nil and nil, respectively. On October 8, 2003, the Company issued $230,000,000 of 7.55% Non-Cumulative Preferred Stock, Series A to the public. See Note XII - Preferred Securities.

Discontinued Operations. Net earnings from discontinued operations for the years ended June 30, 2004, 2003 and 2002 were nil, $32,520,000 and $18,104,000, respectively. The Company completed the sale of its Texas operations effective January 1, 2003, resulting in the recording of an after-tax gain on sale of $18,928,000 during 2003 that is reported in earnings from discontinued operations in accordance with the FASB standard, Accounting for the Impairment or Disposal of Long-Lived Assets. The after-tax gain on the sale of the Texas operations was impacted by the elimination of $70,469,000 of goodwill related to these operations which was primarily non-tax deductible.

Employees. The Company’s continuing operations employed 3,012, 3,041 and 1,855 individuals as of June 30, 2004, 2003 and 2002 respectively. After gas purchases and taxes, employee costs and related benefits are the Company’s most significant expense. Such expense includes salaries, payroll and related taxes, and employee benefits such as health, savings, retirement and educational assistance. For information concerning labor agreements entered into by the Company during the relevant periods, see Item 1. Business - Employees.

Business Segment Results

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. Collectively, the utility divisions serve over 962,000 residential, commercial and industrial customers through local distribution systems consisting of 14,326 miles of mains, 9,654 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 occurring in the traditional winter heating season in the first and fourth calendar quarters. For the six months ended December 31, 2004 and the year ended June 30, 2004, this segment represented 69 and 73 percent of the Company’s total operating revenues, respectively.

The Company’s management is committed to achieving profitable growth of its utility divisions in an increasingly competitive business environment and to enhance shareholder value. Management's strategies for achieving these objectives principally consist of: (i) to focus the divisions in meeting their allowable rates of returns; (ii) to manage capital spending and operating costs without sacrificing customer safety or quality of service; and (iii) to solidify the Company’s relationships with regulatory bodies that oversee the various operations. Further, when appropriate, management will continue to seek rate increases within each division. Management develops and con-tinually evaluates these strategies and their implementation by applying their experience and expertise in analyzing the energy industry, technological advances, market opportunities and general business trends. Each of these strategies, as implemented throughout the Company's existing divisions, reflects the Company's commitment to its natural gas utility business.

Distribution Segment Results - Six Months Ended December 31, 2004 and 2003

The following table provides summary data regarding the Distribution segment’s results of operations for the six months ended December 31, 2004 and 2003:

	Six Months Ended December 31,
	2004			2003
	*(thousands of dollars)*
Financial Results
Operating revenues	$	549,346		$	491,851
Cost of gas and other energy		(360,889	)		(311,102	)
Revenue-related taxes		(18,037	)		(17,461	)
Net operating revenues, excluding depreciation
and amortization		170,420			163,288
Operating expenses:
Operating, maintenance, and general		104,295			89,489
Depreciation and amortization		32,511			29,263
Taxes other than on income and revenues		14,218			11,620
Total operating expenses		151,024			130,372
Operating income	$	19,396		$	32,916

Operating Information
Gas sales volumes (MMcf)		42,176			41,328
Gas transported volumes (MMcf)		27,259			28,858
Weather:
Degree Days:
Missouri Gas Energy service territories		1,669			1,827
PG Energy service territories		2,301			2,268
New England Gas Company service territories		2,004			1,878
Percent of 30-year measure:
Missouri Gas Energy service territories		82	%		90	%
PG Energy service territories		98	%		96	%
New England Gas Company service territories		96	%		90	%

Operating Revenues. Operating revenues for the six months ended December 31, 2004 compared with the six months ended December 31, 2003 increased $57,495,000, or 12%, to $549,346,000 while gas purchase and other energy costs increased $49,787,000, or 16%, to $360,889,000. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 14% increase in the average cost of gas from $7.53 per thousand cubic feet (Mcf) in 2003 to $8.56 per Mcf in 2004, and a 2% increase in gas sales volumes to 42,176 million cubic feet (MMcf) in 2004 from 41,328 MMcf in 2003. The increase in the average cost of gas is due to increases in the average spot market prices throughout the Company’s distribution system as a result of current competitive pricing occurring within the entire energy industry. The increase in gas sales volumes is primarily due to colder weather in 2004 as compared with 2003 in two out of three of the Company’s service territories and growth in the number of customers served. Operating revenues in 2004 were also impacted by the $22,370,000 annual increase to base revenues granted to Missouri Gas Energy, effective October 2, 2004.

Gas purchase costs generally do not directly affect earnings since these costs are passed on to customers pursuant to purchase gas adjustment clauses. Accordingly, while changes in the cost of gas may cause the Company's operating revenues to fluctuate, net operating revenues are generally not affected by increases or decreases in the cost of gas. Increases in gas purchase costs indirectly affect earnings as the customer's bill increases, usually resulting in increased bad debt and collection costs being recorded by the Company.

Gas transportation volumes in 2004 decreased 1,599 MMcf, or 6%, to 27,259 MMcf at an average transportation rate per Mcf of $.53 in 2003 and $.59 in 2004. Gas transportation volumes were impacted by certain customers utilizing alternative energy sources such as fuel oil, customer closure of certain facilities and various customers reducing production.

Net Operating Revenues. Net operating revenues for the six months ended December 31, 2004 increased by $7,132,000, to $170,420,000. Net operating revenues and earnings are primarily dependent upon gas sales volumes and gas service rates. The level of gas sales volumes is sensitive to the variability of the weather as well as the timing of acquisitions. Sales volumes, which benefited from colder-than-normal weather in 2004 in the Company’s Pennsylvania and New England service territories, were negatively impacted by unusually mild tem-peratures in all of the Company’s service territories in 2003. Service rates in 2004 were positively impacted by the annual increase to base revenues granted to Missouri Gas Energy, previously noted. Missouri, Pennsylvania and New England accounted for 39%, 22% and 39%, respectively, of the Distribution segment’s net operating revenues in 2004 and 38%, 23% and 39%, respectively, in 2003.

Customers. The average number of customers served during the six months ended December 31, 2004, and 2003 was 946,123 and 942,022, respectively. Changes in customer totals between periods primarily reflect growth, net of attrition, throughout the Company’s service territories. Missouri Gas Energy served 491,542 customers in central and western Missouri. PG Energy served 157,667 customers in northeastern and central Pennsylvania, and New England Gas Company served 296,914 customers in Rhode Island and Massachusetts during the six months ended December 31, 2004.

Operating Expenses. Operating, maintenance and general expenses for the six months ended December 31, 2004 increased $14,806,000, or 17%, to $104,295,000. The increase is primarily due to $6,602,000 for environmental site remediation; $3,378,000 of increased bad debt expense resulting from the aging of higher customer receivables due to higher gas prices; $2,526,000 of increased outside service cost including collection agency fees, call center fees, distribution system inspection fees and information technology consulting fees; and increased employee payroll costs primarily due to general wage increases and increased overtime due to distribution system maintenance, meter turn-ons and Sarbanes-Oxley Section 404 documentation procedures.

As of December 31, 2004, the Company believes that its reserves for bad debts are adequate based on historical trends and collections. However, to the extent that the cost of gas remains above historical averages, the Company may experience increased pressure on collections and exposure to bad debts that can impact the operating results of this segment in 2005.

Depreciation and amortization expense for the six months ended December 31, 2004 increased $3,248,000 to $32,511,000. The increase was primarily due to a $2,298,000 charge to writedown the value of capitalized computer software costs recorded in property, plant and equipment, in addition to normal growth in plant.

Taxes other than on income and revenues, principally consisting of property, payroll and state franchise taxes increased $2,598,000 to $14,218,000 in 2004, primarily due to a $2,019,000 increase in property taxes in the Company’s Missouri service territory.

Distribution Segment Results -- Years Ended June 30, 2004, 2003 and 2002.

The following table provides summary data regarding the Distribution segment’s results of operations for the years ended June 30, 2004, 2003 and 2002:

	Years Ended June 30,
	2004			2003			2002
	*(thousands of dollars)*
Financial Results
Operating revenues	$	1,304,405		$	1,158,964		$	968,933
Cost of gas and other energy		(863,637	)		(723,719	)		(568,447	)
Revenue-related taxes		(45,395	)		(40,485	)		(33,410	)
Net operating revenues, excluding depreciation
and amortization		395,373			394,760			367,076
Operating expenses:
Operating, maintenance, and general		194,394			171,463			154,906
Depreciation and amortization		57,601			56,396			53,937
Taxes other than on income and revenues		24,484			24,139			22,731
Total operating expenses		276,479			251,998			231,574
Operating income	$	118,894		$	142,762		$	135,502

Operating Information
Gas sales volumes (MMcf)		112,271			122,115			101,036
Gas transported volumes (MMcf)		60,848			66,218			65,757
Weather:
Degree Days:
Missouri Gas Energy service territories		4,770			5,105			4,419
PG Energy service territories		6,240			6,654			5,373
New England Gas Company service territories		5,644			6,143			4,980
Percent of 30-year measure:
Missouri Gas Energy service territories		92	%		98	%		85	%
PG Energy service territories		100	%		106	%		86	%
New England Gas Company service territories		98	%		107	%		85	%

Operating Revenues. Operating revenues for the year ended June 30, 2004 compared with the year ended June 30, 2003 increased $145,441,000, or 13%, to $1,304,405,000 while gas purchase and other energy costs increased $139,918,000, or 19%, to $863,637,000. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 30% increase in the average cost of gas from $5.93 per Mcf in 2003 to $7.69 per Mcf in 2004, which was partially offset by an 8% decrease in gas sales volumes to 112,271 MMcf in 2004 from 122,115 MMcf in 2003. The increase in the average cost of gas is due to increases in the average spot market prices throughout the Company’s distribution system as a result of current competitive pricing occurring within the entire energy industry. The decrease in gas sales volumes is primarily due to warmer weather in 2004 as compared with 2003 in all of the Company’s service territories. Additionally impacting operating revenues in 2004 was a $4,910,000 increase in gross receipt taxes primarily due to an increase in gas purchase and other energy costs. Gross receipt taxes are levied on sales revenues billed to the customers and remitted to the various taxing authorities.

Gas transportation volumes for the year ended June 30, 2004 decreased 5,370 MMcf, or 8%, to 60,848 MMcf at an average transportation rate per Mcf of $.57 in 2004 and $.58 for the same period in 2003. Gas transportation volumes were impacted by certain customers utilizing alternative energy sources such as fuel oil, customer closure of certain facilities and various customers reducing production.

Operating revenues for the year ended June 30, 2003 compared with the year ended June 30, 2002 increased $190,031,000, or 20%, to $1,158,964,000 while gas purchase and other energy costs increased $155,272,000, or 27%, to $723,719,000. The increase in both operating revenues and gas purchase and other energy costs between periods was primarily due to a 21% increase in gas sales volumes to 122,115 MMcf in 2003 from 101,036 MMcf in 2002 and by a 5% increase in the average cost of gas from $5.63 per Mcf in 2002 to $5.93 per Mcf in 2003. The increase in gas sales volume is primarily due to colder weather in 2003 as compared with 2002 in all of the Company’s service territories. The increase in the average cost of gas is due to increases in average spot market gas prices throughout the Company’s distribution system as a result of seasonal impacts on demands for natural gas as well as the competitive pricing occurring within the entire energy industry. Additionally impacting operating revenues in 2003 was a $7,075,000 increase in gross receipt taxes primarily due to an increase in gas purchase and other energy costs.

Gas transportation volumes for the year ended June 30, 2003 increased 461 MMcf to 66,218 MMcf at an average transportation rate per Mcf of $.58 in 2003 and $.56 for the same period in 2002.

Net Operating Revenues. Net operating revenues for the year ended June 30, 2004 increased by $613,000, compared with an increase of $27,684,000 for the year ended June 30, 2003. Net operating revenues and earnings are primarily dependent upon gas sales volumes and gas service rates. The level of gas sales volumes is sensitive to the variability of the weather as well as the timing of acquisitions. Sales volumes, which benefited from colder-than-normal weather in 2004 and 2003 in the Company’s Pennsylvania and New England service territories, were negatively impacted by unusually mild tem-peratures in all of the Company’s service territories in 2002. Net operating revenues in 2003 were impacted by the RIPUC Settlement Offer of $5,227,000 filed by New England Gas Company related to excess revenues earned during the 21-month period covered by the Energize Rhode Island Extension settlement agreement. Missouri, Pennsylvania and New England accounted for 40%, 21% and 39%, respectively, of the segment’s net operating revenues in 2004 and 37%, 24% and 39%, respectively, in 2003.

Customers. The average number of customers served in the years ended June 30, 2004, 2003 and 2002 were 949,978, 944,657 and 935,229, respectively. Changes in customer totals between years primarily reflect growth, net of attrition, throughout the Company’s service territories. Missouri Gas Energy served 494,875 customers in central and western Missouri. PG Energy served 157,864 customers in northeastern and central Pennsylvania, and New England Gas Company served 297,239 customers in Rhode Island and Massachusetts during 2004.

Operating Expenses. Operating, maintenance and general expenses for the year ended June 30, 2004 increased $22,931,000, or 13%, to $194,394,000. The increase is primarily due to $8,917,000 of increased pension and other post retirement benefits costs primarily due to the impact of stock market volatility on plan assets, $6,371,000 of increased bad debt expense resulting from higher customer receivables due to higher gas prices, $1,596,000 of increased medical costs, $1,468,000 of increased insurance premiums and increased employee payroll costs due to general wage increases and increased overtime due to system maintenance and Sarbanes-Oxley Section 404 documentation procedures.

Depreciation and amortization expense for the year ended June 30, 2004 increased $1,205,000 to $57,601,000. The increase was primarily due to normal growth in plant.

Operating, maintenance and general expenses for the year ended June 30, 2003 increased $16,557,000, or 11%, to $171,463,000. The increase is primarily due to $6,370,000 of increased pension and other postretirement benefit costs as a result of volatility in the stock markets, $4,265,000 of increased insurance expense, and $3,547,000 of increased bad debt expense resulting from higher customer receivables due to higher gas prices and colder weather in 2003. The Company also experienced increases in employee payroll and other operating and maintenance costs as a result of the colder weather in 2003. These items were partially offset by realized savings in operating costs from the cash flow improvement plan (see Business Restructuring Charges).

Depreciation and amortization expense for the year ended June 30, 2003 increased $2,459,000 to $56,396,000. The increase was primarily due to normal growth in plant.

Taxes other than on income and revenues, principally consisting of property, payroll and state franchise taxes increased $1,408,000 to $24,139,000 for the year ended June 30, 2003, primarily due to an increase in state franchise taxes.

Transportation and Storage Segment -- The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy, which the Company acquired on June 11, 2003. For the six months ended December 31, 2004 and the year ended June 30, 2004, this segment represented 31 and 27 percent of the Company’s total operating revenues, respectively.

Panhandle Energy operates a large natural gas pipeline network, consisting of more than 10,000 miles of pipeline with approximately 87 Bcf of total available storage, which provides approximately 500 customers in the Midwest and Southwest with a comprehensive array of transportation and storage services. Panhandle Energy also operates one of the largest LNG terminal facilities in North America. Panhandle Energy’s operations are regulated as to rates and other matters by FERC, and are somewhat sensitive to the weather and seasonal in nature with a significant percentage of annual operating revenues and net earnings occurring in the traditional winter heating season.

Transportation and Storage Segment Results - Six Months Ended December 31, 2004 and 2003.

The following table provides summary data regarding the Transportation and Storage segment’s results of operations for the six months ended December 31, 2004, and 2003:

	Six Months Ended December 31,
	2004		2003
	*(thousands of dollars)*
Financial Results
Reservation revenue	$	171,624	$	176,268
LNG terminalling revenue		28,694		30,265
Commodity revenue		37,623		33,503
Other revenue		4,802		4,437
Total operating revenue		242,743		244,473
Operating expenses:
Operating, maintenance, and general		109,796		107,796
Depreciation and amortization		30,159		33,158
Taxes other than on income and revenues		12,667		13,089
Total operating expense		152,622		154,043
Operating income	$	90,121	$	90,430

Operating Information
Gas transported in trillions of British thermal units (Tbtu)		630		667

Operating Revenues. Operating revenues for the six months ended December 31, 2004 compared with the six months ended December 31, 2003 decreased $1,730,000, or 1%, to $242,743,000. The decrease in 2004 is primarily due to lower reservation revenues of $4,644,000 primarily due to replacement of expired contracts on Trunkline during 2004 at lower average reservation rates than were in effect in 2003, resulting from market conditions, and LNG terminalling revenues were $1,571,000 lower than in 2003 primarily due to decreased volumes received in 2004. These decreases were partially offset by an increase in commodity revenues of $4,120,000 primarily due to $6,488,000 of higher parking revenues, partially offset by the impact of a 6% 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. Operating, maintenance and general expenses for the six months ended December 31, 2004 increased $2,000,000, or 2%, to $109,796,000. The increase in 2004 was primarily due to increases in insurance of $2,988,000 and $1,700,000 of severance-related costs incurred in conjunction with the integration of CrossCountry Energy. These increases were partially offset by the net overrecovery of approximately $1,950,000 in 2004 of previously underrecovered fuel volumes, and a $1,318,000 reduction in contract storage expenses due to a reduction in contracted storage capacity.

Depreciation and amortization expense for the six months ended June 30, 2004 decreased $2,999,000 to $30,159,000 primarily due to preliminary purchase price allocations used in 2003 which were subsequently revised in 2004.

Transportation and Storage Segment Results - Years Ended June 30, 2004 and 2003 (from June 12, 2003 to June 30, 2003).

The results of operations from Panhandle Energy have been included in the Consolidated Statement of Operations since June 11, 2003. The following table provides summary data regarding the Transportation and Storage segment’s results of operations for the year ended June 30, 2004 and the period from June 12 to June 30, 2003.

				June 12, 2003
			Year Ended	to
			June 30, 2004	June 30, 2003
			*(thousands of dollars)*
Financial Results
Reservation revenue			$ 355,343	$ 17,117
LNG terminalling revenue			57,988	3,244
Commodity revenue			68,412	3,484
Other revenue			9,140	677
	Total operating revenues		490,883	24,522
Operating expenses:
	Operating, maintenance, and general		210,105	10,102
	Depreciation and amortization		59,988	3,197
	Taxes other than on income and revenues		27,288	1,595
		Total operating expense	297,381	14,894
		Operating income	$ 193,502	$ 9,628

Operating Information
Volumes transported (Tbtu)			1,321	69

Liquidity and Capital Resources

Operating Activities. The seasonal nature of Southern Union’s business results in a high level of cash flow needs to finance gas purchases and other energy costs, outstanding customer accounts receivable and certain tax pay-ments. Additionally, significant cash flow needs may be required to finance current debt service obligations. To provide these funds, as well as funds for its continuing construction and maintenance programs, the Com-pany has historically used cash flows from operations and its credit facilities. Because of available credit and the ability to obtain various types of market financing, combined with anticipated cash flows from operations, management believes it has adequate financial flexibility and access to financial markets to meet its short-term cash needs.

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 consum-mating business acquisitions. On November 17, 2004, the Company acquired a 50% equity interest in CCE Holdings and on June 11, 2003, the Company acquired Panhandle Energy (see Note II -- Acquisitions and Sales). Acquisitions require a substantial increase in expenditures that may need to be financed through cash flow from operations or future debt and equity offerings. 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. See Item 7. Management’s Discussion and Analysis - Other Matters (Cautionary Statement Regarding Forward-Looking Information).

Cash flows used in operating activities were $19,461,000 for the six months ended December 31, 2004 compared with cash flows used in operating activities of $8,780,000 for the same period in 2003. Cash flows provided by operating activities before changes in operating assets and liabilities for 2004 were $111,915,000 compared with $117,552,000 for 2003. Changes in operating assets and liabilities used cash of $131,376,000 in 2004 and $126,332,000 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.

Cash flows provided by operating activities were $339,230,000 for the year ended June 30, 2004 compared with cash flows provided by operating activities of $55,833,000 and $273,479,000 for the same periods in 2003 and 2002, respectively. Cash flows provided by operating activities before changes in operating assets and liabilities for 2004 were $306,475,000 compared with $146,639,000 and $176,295,000 for 2003 and 2002, respectively. Changes in operating assets and liabilities provided cash of $32,755,000 in 2004. Changes in operating assets and liabilities used cash of $90,806,000 in 2003 and provided cash of $97,184,000 in 2002. 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.

At December 31, 2004 and June 30, 2004, 2003 and 2002, the Company’s primary source of liquidity included borrowings available under the Company’s credit facilities. On May 28, 2004, the Company entered into a new five-year long-term credit facility in the amount of $400,000,000 (the Long-Term Facility) that matures on May 29, 2009. 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 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 (the Senior Notes). As of December 31, 2004, the commitment fees were an annualized 0.15%. A balance of $292,000,000, $21,000,000 and $251,500,000 was outstanding under the Company’s credit facilities at an effective interest rate of 3.20%, 2.64%, and 1.98% at December 31, 2004, June 30, 2004 and June 30, 2003, respectively. As of February 28, 2005, there was a balance of $220,000,000 outstanding under the Long-Term Facility.

The Company leases certain facilities, equipment and office space under cancelable and noncancelable operating leases. The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2005—$18,873,000; 2006—$18,397,000; 2007—$13,754,000; 2008—$8,340,000 2009--$4,196,000 and thereafter $6,935,000. The Company is also committed under various agreements to purchase certain quantities of gas in the future. At December 31, 2004, 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 $1,527,032,000. 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.

Investing Activities. Cash flows used in investing activities were $785,535,000 for the six months ended December 31, 2004 compared with $114,433,000 for the same period in 2003. Investing activity cash flow changes were primarily due to the acquisition of an interest in CCE Holdings and additions to property, plant and equipment.

During the six months ended December 31, 2004 and 2003, the Company expended $178,437,000 and $111,091,000, respectively, for capital expenditures excluding acquisitions. The Transportation and Storage segment expended $111,886,000 and $63,356,000 for capital expenditures during the six months ended December 31, 2004 and 2003, respectively. Included in these capital expenditures were a total of $66,893,000 and $28,157,000 relating to the LNG terminal Phase I and Phase II expansions and the Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal in 2004 and 2003, respectively. The remaining capital expenditures for the respective periods primarily related to Distribution segment system replacement and expansion. Included in these capital expenditures were $4,653,000 and $5,728,000 for the Missouri Gas Energy Safety Program during the six months ended December 31, 2004 and 2003, respectively. Cash flow provided by operations has historically been utilized to finance capital expenditures and is expected to be the primary source for future capital expenditures.

Cash flows used in investing activities was $227,009,000 for the year ended June 30, 2004 compared to $191,360,000 and $39,226,000 for the same periods in 2003 and 2002, respectively. Investing activity cash flow changes were primarily due to additions to property, plant and equipment, acquisition and sales of operations, and the settlement of interest rate swaps.

During the years ended June 30, 2004, 2003 and 2002, the Company expended $226,053,000, $79,730,000, and $70,698,000, respectively, for capital expenditures excluding acquisitions. The Transportation and Storage segment expended $131,378,000 and $5,128,000 for capital expenditures during the years ended June 30, 2004 and 2003 (from June 12 to June 30, 2003), respectively. Included in these capital expenditures were a total of $67,087,000 and $1,166,000 relating to the LNG terminal Phase I and Phase II expansions and the Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal in 2004 and 2003, respectively. The remaining capital expenditures for these three years primarily related to Distribution segment system replacement and expansion. Included in these capital expenditures were $6,878,000, $9,094,000, and $7,860,000 for the Missouri Gas Energy Safety Program in 2004, 2003 and 2002, respectively.

On November 17, 2004, the Company invested $590,500,000 in CCE Holdings, a joint venture in which Southern Union owns a 50% equity interest. CCE Holdings acquired 100% of the equity interests of CrossCountry Energy on November 17, 2004 for $2,450,000,000 in cash, including certain consolidated debt.

In June 2003, Southern Union acquired Panhandle Energy for approximately $581,729,000 in cash plus 3,000,000 shares of Southern Union common stock (before adjustment for any subsequent stock dividends). On the date of acquisition, Panhandle Energy had approximately $60,000,000 in cash and cash equivalents.

In January 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets for approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. During the years ended June 30, 2003 and 2002, the Company expended $13,410,000 and $23,215,000, respectively, for capital expenditures relating to the assets of these operations which have been classified as held for sale.

During the year ended June 30, 2004 and 2002, the Company sold non-core subsidiaries and assets which generated proceeds of $2,175,000 and $40,935,000, respectively, resulting in a net pre-tax loss of $1,150,000 in 2004 and net pre-tax gains of $4,914,000 in 2002.

In September 2001, the settlement of three interest rate swaps which the Company had negotiated in July and August of 2001 and which were not designated as hedges, resulted in a pre-tax gain and cash flow of $17,166,000.

The Company estimates expenditures associated with the Phase I and Phase II LNG terminal expansions and the Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal to be $107,000,000 in 2005 and $8,000,000 in 2006, plus capitalized interest. These estimates were developed for budget planning purposes and are subject to revision.

Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas safety program in its service territories (Missouri Gas Energy 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 permits the deferral, and subsequent recovery through rates, of depreciation expense, property taxes and associated carrying costs. The continuation of the Missouri Gas Energy Safety Program will result in significant levels of future capital expenditures. The Company estimates incurring capital expenditures of $7,720,000 in 2005 related to this program and approximately $167,630,000 over the remaining life of the program of 15 years.

Financing Activities. Cash flows provided by financing activities was $815,079,000 for the six months ended December 31, 2004 compared with $54,026,000 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 Subsidiary Trust. As a result of these financing transactions, the Company’s total debt to total capital ratio at December 31, 2004 was 65.7%, compared with 68.1% at December 31, 2003, respectively. The Company’s effective debt cost rate under the current debt structure is 5.32% (which includes interest and the amortization of debt issuance costs and redemption premiums on refinanced debt).

Cash flow used in financing activities was $179,247,000 for the year ended June 30, 2004 compared to cash flow provided by financing activities of $222,524,000 for the same period in 2003 and cash flow used in financing activities of $235,472,000 for the same period in 2002. 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 Subsidiary Trust. As a result of these financing transactions, the Company’s total debt to total capital ratio at June 30, 2004 was 64.0%, compared with 69.7% and 60.3% at June 30, 2003 and 2002, respectively. The Company’s effective debt cost rate under the debt structure at June 30, 2004 was 5.45% (which includes interest and the amortization of debt issuance costs and redemption premiums on refinanced debt).

On November 17, 2004, a wholly-owned subsidiary of the Company entered into a $407,000,000 Bridge Loan Agreement (the 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.

On February 9, 2005, the Company issued 14,913,042 shares of common stock at $23.00 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $332,616,000. The net proceeds were used to repay a portion of the 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, of $86,900,000. 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. Under the terms of the forward sale agreements, the Company 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) through the physical delivery of shares. Upon settlement, which occurred on November 16, 2004, Southern Union received approximately $142,000,000 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. 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 (see Item 7. Management’s Discussion and Analysis - Liquidity and Capital Resources (Investing Activities)).

On March 12, 2004, Panhandle Energy issued $200,000,000 of its 2.75% Senior Notes due 2007, the proceeds of which were used to fund the redemption of the remaining $146,080,000 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 $52,455,000 principal amount of Panhandle Energy’s 7.875% Senior Notes due 2004 that matured on August 15, 2004.

On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public through the issuance of 9,200,000 Depositary Shares, each representing a one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at the public offering price of $25.00 per share, or $230,000,000 in the aggregate. After the payment of issuance costs, including underwriting discounts and commissions, the Company realized net proceeds of $223,410,000. The total net proceeds were used to repay debt under the Company’s revolving credit facilities. The issuance of this Preferred Stock and use of proceeds is continued evidence of the Company’s commitment to the rating agencies to strengthen the Company’s balance sheet and solidify its current investment grade status.

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 $230,000,000 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 $747,370,000 outstanding principal amount of five of its series of senior notes outstanding at that point in time (the Panhandle Tender Offer) and also called for redemption all of the outstanding $134,500,000 principal amount of its two series of debentures that were outstanding (the Panhandle Calls). Panhandle Energy repurchased approximately $378,257,000 of the principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396,445,000 plus accrued interest through the purchase date. Panhandle Energy also redeemed approximately $134,500,000 of debentures through the Panhandle Calls for total consideration of $139,411,000, plus accrued interest through the redemption dates. As a result of the Panhandle Tender Offer, the Company has recorded a pre-tax gain on the extinguishment of debt of $6,354,000 during the year ended June 30, 2004. In August 2003, Panhandle Energy issued $300,000,000 of its 4.80% Senior Notes due 2008 and $250,000,000 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 $3,150,000 principal amount of its senior notes on the open market through two transactions for total consideration of $3,398,000, plus accrued interest through the repurchase date.

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 $146,700,000. 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 $22,000,000.

In connection with the acquisition of the New England Operations, the Company entered into a $535,000,000 Term Note on August 28, 2000 to fund (i) the cash portion of the consideration to be paid to Fall River Gas' stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of long- and short-term debt assumed in the New England mergers, and (iv) related acquisition costs. The Term Note, which initially expired on August 27, 2001, was extended through August 26, 2002. On July 16, 2002, the Company repaid the Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated July 15, 2002 (the 2002 Term Note) and borrowings under its revolving credit facilities. The 2002 Term Note is held by a syndicate of sixteen banks, led by JPMorgan Chase Bank, as Agent. Eleven of the sixteen banks were also among the lenders of the Term Note. The 2002 Term Note carries a variable interest rate that is tied to either the LIBOR or prime interest rates at the Company’s option. The interest rate spread over the LIBOR rate varies with the credit rating of the Senior Notes by Standard and Poor’s Rating Information Service (S&P) and Moody’s Investor Service, Inc. (Moody’s), and is currently LIBOR plus 105 basis points. As of December 31, 2004, a balance of $76,087,000 was outstanding on this 2002 Term Note at an effective interest rate of 3.52%. The 2002 Term Note requires semi-annual principal repayments on February 15^th and August 15^th of each year, with a payment of $35,000,000 being due August 15, 2005 and the remaining principal amount of $41,087,000 is due August 26, 2005. The Company expects to repay the balance of the 2002 Term Note with borrowings under the Long-Term Credit Facility. No additional draws can be made on the 2002 Term Note. See Item 7. Management’s Discussion and Analysis - Quantitative and Qualitative Disclosures About Market Risk.

The Company has an effective shelf registration statement, to be eligible to use it, at the time of the filing of our Form 10-K we need to have timely made all required filings for the past year. Due to the fact that we (and our independent registered public accounting firm) have not completed the procedures required by Section 404 of the Sarbanes-Oxley Act, as more fully described in Item 9A, this 10-K will not be timely filed. In addition, we filed a Form 8-K containing the financial statements of the entities acquired by our joint venture, CCE Holdings, one day late. Absent a waiver from the Staff of the Securities and Exchange Commission, we will be unable to use our Form S-3 until we file our Form 10-K for the year ended December 31, 2005. The inability to access the capital markets only applies to short-form registration using the Company’s shelf registration statement on Form S-3 and would not preclude the Company from long-form registration, from securities issuances in privately-negotiated transactions or from obtaining bank loans to meet any capital requirements.

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 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 S&P, a rating that it has held since March 2003 when it was downgraded from BBB+. S&P 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.

The Company had standby letters of credit outstanding of $8,582,000 at December 31, 2004, $58,566,000 at June 30, 2004 and $7,761,000 at June 30, 2003, which guarantees payment of insurance claims and other various commitments.

Other Matters

Stock Splits and Dividends. On August 31, 2004, July 31, 2003 and July 15, 2002, Southern Union distributed a 5% common stock dividend to stockholders of record on August 20, 2004, July 17, 2003 and July 1, 2002, respectively. A portion of the July 15, 2002, 5% stock dividend 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 data included herein and in the accompanying Consoli-dated Financial Statements and Notes thereto have been restated to give effect to the stock dividends.

Customer Concentrations. In the Transportation and Storage segment, aggregate sales to Panhandle Energy’s top 10 customers accounted for 67% and 70% of segment operating revenues and 21% and 19% of the Company’s total operating revenues for the six-months ended December 31, 2004 and year ended June 30, 2004, respectively. For the six months ended December 31, 2004, this included sales to Proliance Energy, LLC, a nonaffiliated local distribution company and gas marketer, which accounted for 17% of segment operating revenues; sales to BG LNG Services, a nonaffiliated gas marketer, which accounted for 16% of segment operating revenues; and sales to Ameren Corporation, another nonaffiliated gas marketer, which accounted for 11% of the segment operating revenues. For the year ended June 30, 2004, sales to Proliance Energy, LLC accounted for 17% of segment operating revenues; sales to BG LNG Services accounted for 16% of segment operating revenues; and sales to CMS Energy Corporation, Panhandle Energy’s former parent, accounted for 11% of the segment operating revenues. No other customer accounted for 10% or more of the Transportation and Storage segment operating revenues, and no single customer or group of customers under common control accounted for 10% or more of the Company’s total operating revenues for the six months ended December 31, 2004 or for the year ended June 30, 2004.

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations. As of December 31, 2004, the Company had guarantees related to PEI Power and Advent Network, Inc. (in which Southern Union has an equity interest) of $8,210,000 and $4,000,000, respectively, letters of credit related to insurance claims and other commitments of $8,582,000 and surety bonds related to construction or repair projects of approximately $3,570,000. 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 payments under such instruments.

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2004:

	Contractual Obligations (thousands of dollars)												2010 and
	Total		2005		2006		2007		2008		2009		thereafter
Long-term debt,
including capital leases (1) (2)	$	2,149,251	$	89,650	$	139,867	$	433,564	$	301,646	$	61,998	$	1,122,526
Short-term borrowing,
including credit facilities (1)		699,000		699,000		--		--		--		--		--
Gas purchases (3)		1,379,808		436,583		250,832		184,955		170,104		150,567		186,767
Missouri Gas Energy Safety Program		175,350		7,720		10,524		10,630		10,736		10,843		124,897
Storage contracts (4)		147,224		27,444		23,999		17,444		16,159		14,658		47,520
LNG facilities and pipeline expansion		115,608		107,379		8,229		--		--		--		--
Operating lease payments		70,495		18,873		18,397		13,754		8,340		4,196		6,935
Interest payments on debt		1,860,506		134,766		129,696		112,347		104,969		94,096		1,284,632
Benefit plan contributions		28,473		28,473		--		--		--		--		--
Non-trading derivative liabilities		14,989		6,707		6,194		2,088		--		--		--
Total contractual cash obligations	$	6,640,704	$	1,556,595	$	587,738	$	774,782	$	611,954	$	336,358	$	2,773,277

______________________________

(1)

The Company is party to certain debt agreements that contain 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 Note XIII - Debt and Capital Lease.

(2)	The long-term debt cash obligations exclude $14,688,000 of unamortized debt premium as of December 31, 2004.

(3)	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.

(4)	Charges for third party storage capacity.

Cash Management. On October 25, 2003, FERC issued the final rule in Order No. 634-A on the regulation of cash management practices. Order No. 634-A requires all FERC-regulated entities that participate in cash management programs (i) to establish and file with FERC for public review written cash management procedures including specification of duties and responsibilities of cash management program participants and administrators, specification of the methods for calculating interest and allocation of interest income and expenses, and specification of any restrictions on deposits or borrowings by participants, and (ii) to document monthly cash management activity. In compliance with FERC Order No. 634-A, Panhandle Energy filed its cash management plan with FERC on December 11, 2003.

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 (the 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 member 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. No management fees are due under the Agreement for any portion of 2004.

Contingencies. The Company is investigating the possibility that the Company or predecessor companies may have been associated with Manufactured Gas Plant (MGP) sites in its former gas distribution service territories, principally in Texas, Arizona and New Mexico, and present gas distribution service territories in Missouri, Pennsylvania, Massachusetts and Rhode Island. At the present time, the Company is aware of certain MGP sites in these areas and is investigating those and certain other locations. To the extent that potential costs associated with former MGPs are quantified, the Company expects to provide any appropriate accruals and seek recovery for such remediation costs through all appropriate means, including in rates charged to gas distribution customers, insurance and regulatory relief. At the time of the closing of the acquisition of the Company's Missouri service territories, the Company entered into an Environmental Liability Agreement that provides that Western Resources retains financial responsibility for certain liabilities under environmental laws that may exist or arise with respect to Missouri Gas Energy. In addition, the New England Division has reached agreement with its Rhode Island rate regulators on a regulatory plan that creates a mechanism for the recovery of environmental costs over a ten-year period. This plan, effective July 1, 2002, establishes an environmental fund for the recovery of evaluation, remedial and clean-up costs arising out of the Company's MGPs and sites associated with the operation and disposal activities from MGPs. Similarly, environmental costs associated with Massachusetts’ facilities are recoverable in rates over a seven-year period.

While the Company's evaluation of these Texas, Missouri, Arizona, New Mexico, Pennsylvania, Massachusetts and Rhode Island MGP sites is in its preliminary stages, it is likely that some compliance costs may be identified and become subject to reasonable quantification. Within the Company's gas distribution service territories certain MGP sites are currently the subject of governmental actions. See Item 7. Management’s Discussion and Analysis - Other Matters (Cautionary Statement Regarding Forward-Looking Information) and Note XVIII - Commit-ments and Contingencies.

The Company’s interstate natural gas transportation operations are subject to federal, state and local regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. Panhandle Energy has identified environmental impacts at certain sites on its gas transmission systems and has undertaken cleanup programs at those sites. These impacts resulted from (i) the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in compressed air systems; (ii) the past use of paints containing PCBs; (iii) the prior use of wastewater collection facilities; and (iv) other on-site disposal areas. Panhandle Energy communicated with the EPA and appropriate state regulatory agencies on these matters, and has developed and is implementing a program to remediate such contamination in accordance with federal, state and local regulations. Air quality control regulations include rules relating to regional ozone control and hazardous air pollutants. The regional ozone control rules, known as State Implementation Plans (SIP), are designed to control the release of nitrogen oxide (NOx) compounds. The rules related to hazardous air pollutants, known as Maximum Achievable Control Technology (MACT) rules, are the result of the 1990 Clean Air Act Amendments that regulate the emission of hazardous air pollutants from internal combustion engines and turbines. See Item 7. Management’s Discussion and Analysis - Other Matters (Cautionary Statement Regarding Forward-Looking Information) and Note XVIII - Commit-ments and Contingencies.

The Company has completed an investigation of a recent incident involving the release of mercury stored in a NEGC facility in Pawtucket, Rhode Island. On October 19, 2004, New England Gas Company discovered that a NEGC facility had been broken into and that mercury had been spilled both inside a building and in the immediate vicinity. Mercury had also been removed from the Pawtucket facility and a quantity had been spilled in a parking lot in the neighborhood. Mercury from the parking lot spill was apparently tracked into some nearby apartment units, as well as some other buildings. Spill cleanup has been completed at the NEGC property and nearby apartment units. Investigation of some other neighborhood properties has been undertaken, with cleanup necessitated 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, they are conducting inquiries regarding NEGC's compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and hazard communication requirements. NEGC has received a subpoena requesting documents relating to this matter. 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.

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 Southern Union. The trial of Southern Union’s claims against the sole-remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to Southern Union of nearly $400,000 in actual damages and $60,000,000 in punitive damages against former Commissioner Irvin. The District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages. Former Commissioner Irvin has appealed to the Ninth Circuit Court of Appeals. A decision on the appeal by the Ninth Circuit is expected in 2005. The Company intends to vigorously pursue collection of the award. With the exception of ongoing legal fees associated with the collection of damages from former Commissioner Irvin, the Company believes that the results of the above-noted Southwest litigation and any related appeals will not have a materially adverse effect on the Company's financial condition, results of operations or cash flows.

Through filings made on various dates, the staff of the MPSC has recommended that the Commission disallow a total of approximately $38,500,000 in gas costs incurred during the period July 1, 1997 through June 30, 2003. The basis of $32,100,000 of the total proposed disallowance is disputed by MGE and 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. The basis of $3,000,000 of the total proposed disallowance, applicable to the period July 1, 2000 through June 30, 2001, is disputed by MGE, was the subject of a hearing concluded in November 2003 and is presently awaiting decision by the Commission. The basis of $3,400,000 of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003, is disputed by MGE; no date for a hearing in this matter has been set.

In 1993, the U.S. Department of the Interior announced its intention to seek, through its Minerals 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, buyouts, and buy downs of gas sales contracts with natural gas pipelines. Southern Union Exploration Company (SX, the Company’s former exploration and production subsidiary) has received a final determination by an area office of the MMS that it is obligated to pay additional royalties on proceeds realized by SX as a result of a previous settlement between SX and Public Service Company of New Mexico (MMS Docket No. MMS-94-0184-IND). This claim has been on appeal to the Director of the MMS; the MMS has stayed the requirement that SX pay the claim pending the outcome of the appeal. The amounts claimed by the MMS, which involve leases on land owned by the Jicarilla Apache tribe, still have not been quantified fully. SX has also been issued, by the MMS Royalty Valuation Chief, an Order to Perform Major Portion Pricing and Dual Accounting on SX’s leases for the period from 1984 until 1995. SX has appealed the Order to the Director of the MMS. SX believes that it has several defenses to the Order to Perform. The amounts that may be claimed still have not been quantified fully. The Order to Perform has been stayed pending the outcome of the appeal. 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.

Additionally, 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 the MMS 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 Energy's pipelines may file with FERC to recover a portion of these costs from pipeline customers. Panhandle Energy believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

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 assets to be replaced 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. The majority of the Company's business activities are subject to various regulatory authorities. The Com-pany's financial condition and results of operations have been and will continue to be dependent upon the receipt of adequate and timely ad-justments in rates.

On September 21, 2004, the Missouri Public Service Commission issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22,370,000, effective October 2, 2004. The rate order, based on a 10.5% return on equity, also produced an improved rate design that should help stabilize revenue streams and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between customers and the Company.

On May 22, 2003, the 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 $5,277,000. 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 twelve-month period starting July 1, 2003.

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 $3,900,000 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 $2,049,000 of merger savings and to share incremental earnings with customers when the division’s Rhode Island operations return on equity exceeds 11.25%. 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, to recover environmental response costs over a 10-year period, puts into place a new weather normalization clause and allows for the sharing of nonfirm margins (non-firm margin 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 2% colder-than-normal and will recover the margin impact of weather that is greater than 2% warmer-than-normal. The non-firm margin incentive mechanism allows New England Gas Company to retain 25% of all non-firm margins earned in excess of $1,600,000.

In December 2002, FERC approved a Trunkline LNG certificate application to expand the Lake Charles facility to approximately 1.2 Bcf per day of sustainable send out capacity versus the current sustainable send out capacity of .63 Bcf per day and 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 totaling $137,000,000, plus capitalized interest, by the end of 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 $77,000,000, plus capitalized interest, and would increase the LNG terminal 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 this facility. Approximately $127,000,000 of costs are included in the line item Construction Work In Progress for the expansion projects through December 31, 2004.

In February 2004, Trunkline filed an application with the FERC to request approval of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal. Trunkline’s filing was approved on September 17, 2004, as modified on September 23, 2004. 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. On November 5, 2004, Trunkline filed an amended application with the FERC to change the size of the pipeline from 30-inch diameter to 36-inch diameter to better position Trunkline to provide transportation service for expected future LNG volumes and increase operational flexibility. The amendment was approved by FERC on February 11, 2005. The Trunkline natural gas pipeline loop associated with the LNG terminal is estimated to cost $50,000,000, plus capitalized interest. Approximately $21,000,000 of costs are included in the line item Construction Work In Progress for this project through December 31, 2004.

The Company continues to pursue certain changes to rates and rate structures that are intended to reduce the sensi--tivity of earnings to weather, including weather normalization clauses and higher monthly fixed customer charges for its regulated utility operations. New England Gas Company has a weather normalization clause in the tariff covering its Rhode Island operations.

Critical Accounting Policies. 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 perceived 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 Note I - Summary of Significant Accounting Policies.

Effects of Regulation -- The Company is subject to regulation by certain state and federal authorities. The Company, in its Distribution segment, has accounting policies which conform to the FASB Standard, 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 are then flowed 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 are $100,653,000 and $15,285,000 at December 31, 2004, and $99,314,000 and $11,164,000 at June 30, 2004 and $107,696,000 and $10,084,000 at June 30, 2003, respectively.

Long-Lived Assets -- Long-lived assets, including property, plant and equipment, goodwill and intangibles 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. Management’s determination of an asset’s fair value requires it to make long-term forecasts of future revenues and costs related to the asset, when the asset’s fair value is not readily apparent from other sources. 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.

During June 2004, 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 June 30, 2004, and December 31, 2004 pursuant to the FASB Standard, Goodwill and Other Intangible Assets, no impairment had been indicated.

In connection with the company's cash flow Improvement Plan announced in July 2001, the Company began the divestiture of certain non-core assets. As a result of prices of comparable businesses for various non-core properties and pursuant to the FASB Standard, Impairment of Long-Lived Assets and Assets to be Disposed Of, a goodwill impairment loss of $1,417,000 was recognized in depreciation and amortization on the Consolidated Statement of Operations for the quarter ended September 30, 2001.

Investments in Securities -- At December 31, 2004, the Company owned common and preferred stock in non-public companies whose value is not readily determinable. These investments were accounted for under the cost method. A judgmental aspect of accounting for these securities involves determining whether an other-than-temporary decline in value has been sustained. Management reviews these 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: earnings trends and asset quality; near term prospects and financial condition of the issuer; financial condition and prospects of the issuer's region and industry; and Southern Union's intent and ability to retain the investment. If management determines that a decline in value is other-than-temporary, a charge will be recorded on the Consolidated Statement of Operations to reduce the carrying value of the investment security to its estimated fair value.

In December 2004, the Company recorded a total non-cash charge of $16,425,000 to recognize an other-than-temporary impairment of the carrying value of its investment in Advent. This impairment was comprised of a write-down of $4,925,000 and $11,500,000 to the Company’s investment and convertible notes receivable accounts, respectively. The Company reevaluated the fair value of its investment in Advent as a result of Advent's recent efforts to raise additional capital from private investors, which placed a significantly lower valuation on Advent than reflected in the carrying value of the Company’s investment in Advent. The foregoing, as well as certain other factors, led to the non-cash charge discussed above. After the non-cash write-down, the Company’s remaining investment in Advent as of December 31, 2004, is $508,000. This remaining investment may be subject to future market risk. Additionally, a wholly-owned subsidiary of the Company has guaranteed a $4,000,000 line of credit between Advent and a bank. Advent remains current and is not in default in this line of credit.

In September 2003 and June 2002, 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 $1,603,000 and $10,380,000 during the quarters ended September 30, 2003 and June 30, 2002, 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 $2,603,000 at December 31, 2004 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.

Pensions and Other Postretirement Benefits - The Company follows the FASB Standards Employers’ Accounting for Pensions and 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 post-retirement 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 post-retirement 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.

Derivatives and Hedging Activities -- The Company follows the FASB Standard, 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 Note XI -- 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 Note XVIII - -- Commitments and Contingencies.

Purchase Accounting -- The Company’s acquisition of Panhandle Energy was accounted for using the purchase method of accounting in accordance with the FASB Standard, Business Combinations. CCE Holdings, a joint venture in which Southern Union owns a 50% 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 determination of fair value. The appraisals related to Southern Union’s acquisition of Panhandle Energy were finalized in 2004. The outside appraisals to be completed for CCE Holdings’ purchase of CrossCountry Energy are to be completed in 2005. Accordingly, any changes in the preliminary allocations of fair value due to the completion of the appraisals will be reflected through the Company’s investment in, and the equity earnings from, CCE Holdings at the time such changes are known.

Accounting Pronouncements

In accordance with FASB Financial Staff Position (FSP), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, (the Medicare Prescription Drug Act) the benefit obligation and net periodic post-retirement cost in the Company’s consolidated financial statements and accompanying notes do not reflect the effects of the Medicare Prescription Drug Act on the Company’s post-retirement healthcare plan because the Company is unable to conclude whether benefits provided by the plan are actuarially equivalent to Medicare Part D under the Medicare Prescription Drug Act. The method of determining whether a sponsor’s plan will qualify for actuarial equivalency was published January 21, 2005 by the Center for Medicare and Medical Services. Once the determination of actuarial equivalence for current and future years is complete, if eligible, the Company will account for the subsidy as an actuarial gain, pursuant to the guidelines of this standard.

In December 2004, the FASB issued 123R, Share-Based Payment (revised 2004). The Statement revises FASB Statement No. 123, Accounting for Stock-Based Compensation, supersedes the Accounting Principal Board Opinion, Accounting for Stock Issued to Employees and amends FASB Statement No. 95, Statement of Cash Flows. The Statement will be effective for the Company in the first interim reporting period beginning after June 15, 2005 and will require the Company to measure all employee stock-based compensation awards using a fair value method and record such expense in its consolidated financial statements. In addition, the adoption of the Statement will require additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed. The Act raises a number of issues with respect to accounting for income taxes. On December 21, 2004, the FASB issued a Staff Position regarding the accounting implications of the Act related to the deduction for qualified domestic production activities (FSP FAS 109-1) which is effective for periods subsequent to December 31, 2004. The guidance in the FSP otherwise applies to financial statements for periods ending after the date the Act was enacted. In FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the FASB decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. In most cases, a company’s existing deferred tax balances will not be impacted at the date of enactment. For some companies, the deduction could have an impact on their effective tax rate and, therefore, should be considered when determining the estimated annual rate used for interim financial reporting. The Company is currently evaluating the impact, if any, of this FSP on its consolidated financial statements.

In November 2004, the Federal Energy Regulatory Commission (FERC) issued an industry-wide Proposed Accounting Release that, if enacted as written, would require pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. The Company is currently evaluating the impact of this Release on its consolidated financial statements.

Cautionary Statement Regarding Forward-Looking Information. This Management’s Discussion and Analysis of Results of Operations and Financial Condition and other sections of this Annual Report on Form 10-K contain forward-looking statements that are based on current expectations, estimates and projections about the industry in which the Company operates, management’s beliefs and assumptions made by management. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates,” variations of such words and similar expressions are intended to identify such forward-looking statements. Similarly, statements that describe our objectives, plans or goals are or may be forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions, which are difficult to predict and many of which are outside the Company’s control. Therefore, actual results, performance and achievements may differ materially from what is expressed or forecasted in such forward-looking statements. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned not to put undue reliance on such forward-looking statements. Stockholders may review the Company’s reports filed in the future with the Securities and Exchange Commission for more current descriptions of developments that could cause actual results to differ materially from such forward-looking statements.

Factors that could cause actual results to differ materially from those expressed in our forward-looking statements include, but are not limited to: cost of gas; gas sales volumes; gas throughput volumes and available sources of natural gas; discounting of transportation rates due to competition; customer growth; abnormal weather conditions in Southern Union’s service territories; impact of relations with labor unions of bargaining-unit employees; the receipt of timely and adequate rate relief and the impact of future rate cases or regulatory rulings; the outcome of pending and future litigation; the speed and degree to which competition is introduced to Southern Union’s gas distribution business; new legislation and government regulations and proceedings affecting or involving Southern Union; unanticipated environmental liabilities; ability to comply with or to challenge successfully existing or new environmental regulations; changes in business strategy and the success of new business ventures, including the risks that the business acquired and any other businesses or investments that Southern Union has acquired or may acquire may not be successfully integrated with the business of Southern Union; 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; factors affecting operations such as maintenance or repairs, environmental incidents or gas pipeline system constraints; Southern Union’s, or any of its subsidiaries, debt securities ratings; the economic climate and growth in the energy industry and service territories and competitive conditions of energy markets in general; inflationary trends; changes in gas or other energy market commodity prices and interest rates; the current market conditions causing more customer contracts to be of shorter duration, which may increase revenue volatility; the possibility of war or terrorist attacks; the nature and impact of any extraordinary transactions such as any acquisition or divestiture of a business unit or any assets.

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, 2004, the Company had issued fixed-rate long-term debt aggregating $1,808,559,000 in principal amount (excluding premiums on Panhandle Energy’s debt of $14,687,000) and having a fair value of $1,962,864,000. 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 $80,304,000 if interest rates were to decline by 10% from their levels at December 31, 2004. In general, such an increase in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments in the open market prior to their maturity.

The Company's floating-rate obligations aggregated $1,039,693,000 at December 31, 2004 and primarily consisted of the Bridge Loan, the $200,000,000 Panhandle notes that were swapped to a floating rate, the 2002 Term Note, the debt assumed under the Panhandle Acquisition related to the Trunkline LNG facility, and amounts borrowed under the Long-Term Facility. 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 10% from December 31, 2004 levels, the Company's consolidated interest expense would increase by a total of approximately $311,000 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 the FASB Standard, 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 from June 30, 2004 to December 31, 2004 is not material to the Company.

See Note XIII - Debt and Capital Lease.

In connection with the acquisition of the Pennsylvania Operations, 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 $10,600,000 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 $10,600,000 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 $10,600,000 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%) 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, 2004, the interest rate on the TIF Debt was 4.5% and estimated incremental tax revenues are expected to cover approximately 45% of the 2005 annual debt service. Based on information available at this time, the Company believes that the amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2004. The balance outstanding on the TIF Debt was $8,210,000 as of December 31, 2004.

The Company is party to interest rate swap agreements with an aggregate notional amount of $193,827,000 as of December 31, 2004 that fix the interest rate applicable to floating rate long-term debt and which qualify for hedge accounting. For the six months ended December 31, 2004, the amount of swap ineffectiveness was not significant. As of December 31, 2004, floating rate LIBOR-based interest payments are exchanged for weighted average fixed rate interest payments of 5.88%, which does not include the spread on the underlying variable debt rate of 1.63%. As such, payments or receipts on interest rate swap agreements, in excess of the liability recorded, are recognized as adjustments to interest expense. As of December 31, 2004, June 30, 2004 and June 30, 2003, the fair value liability position of the swaps was $11,053,000, $14,445,000 and $26,058,000, respectively. As of December 31, 2004, approximately $1,150,000 of net after-tax gains included in accumulated other comprehensive income related to these swaps is expected to be reclassified to interest expense during the next twelve months as the hedged interest payments occur. Current market pricing models were used to estimate fair values of interest rate swap agreements.

The Company was also party to an interest rate swap agreement with a notional amount of $8,199,000 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 income 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 $250,000,000 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 $6,862,000 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, 2004, approximately $981,000 of net after-tax losses in accumulated other comprehensive income will be amortized into interest expense during the next twelve months.

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.

In March 2004, Panhandle Energy entered into interest rate swaps to hedge the risk associated with the fair value of its $200,000,000 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under FASB Standard, 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% 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, 2004 and June 30, 2004, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $3,936,000 and $4,960,000, respectively.

During the year ended June 30, 2004, the Company acquired natural gas commodity swap derivatives and collar transactions in order 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, 2004 and June 30, 2004, the fair values of the contracts, which expire at various times through March 2005, are included in the Consolidated Balance Sheet as assets and matching adjustments to deferred cost of gas of $2,597,000 and $1,337,000, respectively.

In March 2001, the Company discovered unauthorized financial derivative energy trading activity by a non-regulated, wholly-owned subsidiary. All unauthorized trading activity was subsequently closed in March and April of 2001 resulting in a cumulative cash expense of $191,000, net of taxes, and deferred income of $7,921,000 at June 30, 2001. For the six months ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002, the Company recorded $302,000, $605,000, $605,000 and $6,204,000, respectively, through other income relating to the expiration of contracts resulting from this trading activity. The remaining deferred liability of $205,000 at December 31, 2004 related to these derivative instruments will be recognized as income in the Consolidated Statement of Operations over the next year based on the related contracts. The Company established new limitations on trading activities, as well as new compliance controls and procedures that are intended to make it easier to identify quickly any unauthorized trading activities.

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.

We performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), and with the participation of personnel from our 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 Rule 13a-15(e) or Rule 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2004 and have communicated that determination to the Audit Committee of our Board of Directors.

Status of Management’s Report on Internal Control Over Financial Reporting

Securities 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.

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined 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.

The evaluation of the Company’s internal control over financial reporting is being, and has been, conducted under the direction of the Company’s senior management. The Company’s management is regularly discussing the results of its testing and any proposed improvements to its control environment with the Company’s Audit Committee.

In December 2004, the Company determined to change its fiscal year-end from June 30 to December 31. The Company’s change to a calendar year-end reporting period had the effect of accelerating, from June 30, 2005 to December 31, 2004, the first date for which the Company must comply with the requirements of Section 404. As previously disclosed in the Company’s Form 8-K, filed December 31, 2004, this accelerated timetable did not allow for timely completion of an evaluation of the Company’s internal control over financial reporting or the related testing of the Company’s internal control over financial reporting in order for management to complete its assessment of the effectiveness of the design and operation of internal control over financial reporting and for the Company’s independent registered public accounting firm to audit management’s assessment of the effectiveness of the Company’s internal control over financial reporting in time for filing with this Transition Report on Form 10-K for the six-month period ended December 31, 2004.

The certifications required by (i) 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002 and furnished herewith as Exhibits 32.1 and 32.2 and (ii) Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, filed with the Company’s Transition Report on Form 10-K as Exhibits 31.1 and 31.2, are qualified entirely by reference to the above discussion.

The Company will file an amendment to this Transition Report on Form 10-K to include (i) the reports of management and the Company’s independent registered public accounting firm as required by Section 404 of the Sarbanes-Oxley Act and (ii) revised certifications as required by Section 906 of the Sarbanes-Oxley Act and Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act. No assurances can be given that the Company’s completion of its evaluation of internal control, or related testing, will not result in the identification of internal control deficiencies or material weaknesses.

Changes in Internal Controls.

Although, as discussed above, management has not completed its assessment of the Company’s 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, 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.

ITEM 9B. Other Information.

All information required to be reported on Form 8-K for the quarter ended December 31, 2004 was appropriately reported.

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 2005 Annual Meeting of Stockholders under the captions Board of Directors -- Board Size and Composition, Board Committees and Meetings - Audit Committee and - Corporate Governance Committee and - Corporate Governance Guidelines and Code of Ethics, Report of the Audit Committee, and Executive Officers and Compensation -- Executive Officers Who Are Not Directors and Executive Compensation -- Section 16(a) Beneficial Ownership Reporting Compliance.

We have adopted a Code of Ethics which applies to our Chief Executive Officer, Chief Financial Officer, controller and other individuals in our finance department performing similar functions. The Code of Ethics is available on our website at www.southernunionco.com. If any substantive amendment to the Code of Ethics is made or any waiver is granted thereunder, including any implicit waiver, our Chief Executive Officer, Chief Financial Officer or other authorized officer will disclose the nature of such amendment or waiver on our website at www.southernunionco.com or in a Current Report on Form 8-K.

The CEO Certfication 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 November 19, 2004.

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 2005 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.

There is incorporated in this Item 12 by reference the information that will appear in the Company’s definitive proxy statement for the 2005 Annual Meeting of Stockholders under the captions Executive Officers and Compensation - Information Regarding Plans and Other Arrangements Not Subject to Shareholder 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 2005 Annual Meeting of Stockholders under the caption Certain Relationships.

ITEM 14. Principal Accountants Fee 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 2005 Annual Meeting of Stockholders under the caption Independent Auditors.

PART IV

ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.

(a)(1) and (2) Financial Statements and Financial Statement Schedules. See Index to Consolidated Financial Statements set forth on page F-1.

(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.)

3(a) Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Transition Report on Form 10-K for the year ended June 30, 1994 and incorporated herein by reference.)

3(b) Amendment to Restated Certificate of Incorporation of Southern Union Company which was filed with the Secretary of State of Delaware and became effective Octber 26, 1999. (Filed as Exhibit 3(a) to Southern Union's Quarterly Report on Form 10-Q for the quarter ended December 31, 1999 and incorporated herein by reference.)

3(c) Amended and Restated By-Laws of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union's Current Report on Form 8-K dated January 25, 2005 and incorporated herein by reference.)

3(d) 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 Manahatten 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) Officers' 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 dated 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/k/a JP Morgan Chase Bank) (filed as Exhibit 4.4. to Southern Union's Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

4(g) Certificate of Trust of Southern Union Financing I. (Filed as Exhibit 4-A to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(h) Certificate of Trust of Southern Union Financing II. (Filed as Exhibit 4-B to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(i) Certificate of Trust of Southern Union Financing III. (Filed as Exhibit 4-C to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(j) Form of Amended and Restated Declaration of Trust of Southern Union Financing I. (Filed as Exhibit 4-D to Southern Union’s Registration State-ment on Form S-3 (No. 33-58297) and incorporated herein by reference.)

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

4(l) Form of Supplemental Indenture to Subordinated Debt Securities Indenture with respect to the Subordinated Debt Securities issued in connection with the Southern Union Financing I Preferred Securities. (Filed as Exhibit 4-H to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(m) Form of Southern Union Financing I Preferred Security (included in 4(e) above.) (Filed as Exhibit 4-I to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(n) Form of Subordinated Debt Security (included in 4(i) above.) (Filed as Exhibit 4-J to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(o) Form of Guarantee with respect to Southern Union Financing I Preferred Securities. (Filed as Exhibit 4-K to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) 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.)

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) Letter Agreement dated as of July 26, 2004, between Southern Union Company and Merrill Lynch International. (Filed as Exhibit 99.1 to Southern Union’s Current Report on Form 8-K filed on August 31, 2004 and incorporated herein by reference.)

4(w) Letter Agreement dated as of July 26, 2004, between Southern Union Company and JPMorgan Chase Bank, London Branch, acting through J.P. Morgan Securities Inc. as agent. (Filed as Exhibit 99.2 to Southern Union’s Current Report on Form 8-K filed on August 31, 2004 and incorporated herein by reference.)

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

10(a) First Amendment to Third Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein dated November 9, 2004.

10(b) Third Amendment to Amended and Restated Term Loan Credit Agreement between Southern Union Company and the Banks named therein dated November 9, 2004.

10(c) 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(d) 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(e) 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(f) 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) [Reserved].

10(h) 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(i) Secured Promissory Note and Security Agreements between Thomas F. Karam and Southern Union Company dated December 20, 1999. (Filed as Exhibit 10(b) to Southern Union's Quarterly Report on Form 10-Q for the quarter ended December 31, 1999 and incorporated herein by reference.)

10(j) Promissory Note between Dennis K. Morgan and Southern Union Company dated January 28, 2000. (Filed as Exhibit 10(k) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 2002 and incorporated herein by reference.)

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) Employment agreement between David W. Stevens and Southern Union Company dated October 31, 2002. (Filed as Exhibit 10 to Southern Union’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2002 and incorporated herein by reference.)

10(n) Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4.1 to Form S-8, SEC File No. 333-112527, filed on February 5, 2004 and incorporated herein by reference.)(*)

10(o) 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(p) 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.)

14 Code of Ethics.

21 Subsidiaries of the Registrant.

23 Consent of Independent Registered Public Accounting Firm.

24 Power of Attorney.

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

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

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

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

(b) Reports on Form 8-K. Southern Union filed the following Current Reports on Form 8-K during the three months ended December 31, 2004.

DateFiled Description of Filing

11/10/2004

Filing under Item 1.01, the Amended and Restated Limited Liability Company Agreement between CCE Holdings, LLC, CCE Acquisition, LLC (a wholly-owned subsidiary of the Company) and EFS-PA, LLC, dated November 5, 2004; and the Administrative Services Agreement between CCE Holdings, LLC and SU Pipeline Management LP (a wholly-owned subsidiary of the Company), dated November 5, 2004.

11/22/2004

Filing under Item 2.01, the press release issued by Southern Union Company announcing that CCE Holdings, LLC on November 17, 2004, completed the acquisition of 100% of the equity interests of Cross Country Energy, LLC from Enron Corp. and completed the divestiture of its interests in Northern Plains Natural Gas Company, LLC and NBP Services, LLC to ONEOK, Inc.; and filing under Item 2.03, a description of the guarantee provided by Panhandle Energy related to the bridge financing entered into by Southern Union on November 17, 2004 of $407,000,000 to fund a portion of Southern Union’s equity investment in CCE Holdings, LLC.

11/22/2004

Filing under Item 7.01, the investor call presentation “CrossCountry Energy Acquisition” presented by Southern Union Company on November 22, 2004.

12/01/2004

Filing under Item 5.02, the press release issued by Southern Union Company announcing the election of Herbert H. Jacobi as a new Class III director effective December 1, 2004.

12/21/2004

Filing under Item 5.03, the press released issued by Southern Union Company announcing the Board of Directors of the Company amended the Company’s Bylaws (i) to change from a June 30 fiscal year end to a December 31 calendar year end, and (ii) to provide that future annual meetings of stockholders will be held on the last Tuesday in April, or on such other date as determined by the Board.

(*)	Indicates Management Compensation Plan.

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, 2005.

SOUTHERN UNION COMPANY

By /s/ THOMAS F. KARAM

Thomas F. Karam

President and Chief Operating 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, 2005.

Signature/Name	Title
GEORGE L. LINDEMANN*	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)

JONE E. BRENNAN*	Director

DAVID BRODSKY*	Director

FRANK W. DENIUS*	Director

KURT A. GITTER, M.D.*	Director

HERBERT H. JACOBI*	Director

THOMAS F. KARAM	Director
Thomas F. Karam

ADAM M. LINDEMANN*	Director

THOMAS N. McCARTER, III*	Director

GEORGE ROUNTREE, III*	Director

RONALD W. SIMMS*	Director

DAVID J. KVAPIL	Executive Vice President and Chief Financial Officer
David J. Kvapil	(Principal Financial Officer)

*By THOMAS F. KARAM
Thomas F. Karam
Attorney-in-fact

Page

Financial Statements:
Consolidated statement of operations - six months ended December 31, 2004 and
years ended June 30, 2004, 2003 and 2002	F-2
Consolidated balance sheet - December 31, 2004, June 30, 2004 and June 30, 2003	F-3 to F-4
Consolidated statement of cash flows - six months ended December 31, 2004 and
years ended June 30, 2004, 2003 and 2002	F-5
Consolidated statement of stockholders' equity and comprehensive income (loss) -
six months ended December 31, 2004 and years ended June 30, 2004, 2003 and 2002	F-6 to F-7
Notes to consolidated financial statements	F-8 to F-55
Report of independent registered public accounting firm

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

Six Months
Ended
December 31,				Years Ended June 30,
	2004			2004			2003			2002
(thousands of dollars, except shares and per share amounts)
Operating revenues: revenues:
Gas distribution	$	549,346		$	1,304,405		$	1,158,964		$	968,933
Gas transportation and storage		242,743			490,883			24,522			-
Other		2,249			4,486			5,014			11,681
Total operating revenues		794,338			1,799,774			1,188,500			980,614

Cost of gas and other energy		(361,256	)		(864,438	)		(724,611	)		(573,077	)
Revenue-related taxes		(18,037	)		(45,395	)		(40,485	)		(33,409	)
Net operating revenues, excluding depreciation
and amortization		415,045			889,941			423,404			374,128

Operating expenses:
Operating, maintenance and general		217,967			411,811			193,745			171,147
Business restructuring charges		--			--			--			29,159
Depreciation and amortization		63,376			118,755			60,642			58,989
Taxes, other than on income and revenues		26,771			54,048			26,653			23,708
Total operating expenses		308,114			584,614			281,040			283,003
Operating income		106,931			305,327			142,364			91,125

Other income (expenses):
Interest		(64,898	)		(127,867	)		(83,343	)		(90,992	)
Earnings from unconsolidated investments		4,745			200			422			1,420
Dividends on preferred securities of subsidiary trust		--			--			(9,480	)		(9,480	)
Other, net		(18,080	)		5,468			17,979			12,858
Total other expenses, net		(78,233	)		(122,199	)		(74,422	)		(86,194	)

Earnings from continuing operations before income taxes		28,698			183,128			67,942			4,931

Federal and state income taxes		13,927			69,103			24,273			3,411

Net earnings from continuing operations		14,771			114,025			43,669			1,520

Discontinued operations:
Earnings from discontinued operations before
income taxes		--			--			84,773			29,801
Federal and state income taxes		--			--			52,253			11,697
Net earnings from discontinued operations		--			--			32,520			18,104

Net earnings		14,771			114,025			76,189			19,624

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

Net earnings available for common shareholders	$	6,088		$	101,339		$	76,189		$	19,624

Net earnings available for common shareholders from
continuing operations per share:
Basic	$	0.07		$	1.34		$	0.72		$	0.03
Diluted	$	0.07		$	1.30		$	0.70		$	0.02

Net earnings available for common shareholders per share:
Basic	$	0.07		$	1.34		$	1.26		$	0.33
Diluted	$	0.07		$	1.30		$	1.22		$	0.31

Weighted average shares outstanding:
Basic		81,995,878			75,442,238			60,584,293			59,420,048
Diluted		85,298,894			77,694,607			62,523,110			62,596,907

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

ASSETS

	December 31,			June 30,
	2004			2004			2003
	*(thousands of dollars)*
Property, plant and equipment:
Plant in service	$	3,869,221		$	3,772,616		$	3,710,541
Construction work in progress		237,283			169,264			75,484
		4,106,504			3,941,880			3,786,025
Less accumulated depreciation and amortization		(778,876	)		(734,367	)		(641,225	)
Net property, plant and equipment		3,327,628			3,207,513			3,144,800

Current assets:
Cash and cash equivalents		30,053			19,971			86,997
Accounts receivable, billed and unbilled, net		333,492			181,924			192,402
Inventories		267,136			200,295			173,757
Deferred gas purchase costs		--			3,933			24,603
Gas imbalances - receivable		36,122			22,045			34,911
Prepayments and other		45,705			27,561			18,971
Total current assets		712,508			455,729			531,641

Goodwill		640,547			640,547			642,921

Deferred charges		199,064			190,735			188,261

Unconsolidated investments		631,893			20,856			22,682

Other		56,649			57,078			60,633
















Total assets	$	5,568,289		$	4,572,458		$	4,590,938

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (CONTINUED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,			June 30,
	2004			2004			2003
	*(thousands of dollars)*
Stockholders’ equity:
Common stock, $1 par value; authorized 200,000,000 shares;
issued 90,762,650 shares at December 31, 2004	$	90,763		$	77,141		$	73,074
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares at December 31, 2004		230,000			230,000			--
Premium on capital stock		1,204,590			975,104			909,191
Less treasury stock; 404,536, 404,536 and 282,333
shares, respectively, at cost		(12,870	)		(12,870	)		(10,467	)
Less common stock held in trust: 1,198,034, 1,089,147
and 1,114,738 shares, respectively		(17,980	)		(15,812	)		(15,617	)
Deferred compensation plans		14,128			11,960			9,960
Accumulated other comprehensive loss		(59,118	)		(50,224	)		(62,579	)
Retained earnings		48,044			46,692			16,856

Total stockholders' equity		1,497,557			1,261,991			920,418

Company-obligated mandatorily redeemable preferred
securities of subsidiary trust holding
solely subordinated notes of Southern Union		--			--			100,000

Long-term debt and capital lease obligation		2,070,353			2,154,615			1,611,653

Total capitalization		3,567,910			3,416,606			2,632,071

Current liabilities:
Long-term debt and capital lease obligation
due within one year		89,650			99,997			734,752
Notes payable		699,000			21,000			251,500
Accounts payable		183,018			122,309			112,840
Federal, state and local taxes		33,946			32,866			6,743
Accrued interest		36,934			36,891			40,871
Customer deposits		13,156			12,043			12,585
Gas imbalances - payable		102,567			72,057			64,519
Other		155,565			116,783			130,196

Total current liabilities		1,313,836			513,946			1,354,006

Deferred credits		321,049			292,946			322,154

Accumulated deferred income taxes		365,494			348,960			282,707

Commitments and contingencies

Total stockholders' equity and liabilities	$	5,568,289		$	4,572,458		$	4,590,938

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

Six Months
	Ended
	December 31,			Year Ended June 30,
	2004			2004			2003			2002
	(thousands of dollars)
Cash flows provided by (used in) operating activities:
Net earnings	$	14,771		$	114,025		$	76,189		$	19,624
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		63,376			118,755			60,642			58,989
Amortization of debt premium		(1,510	)		(14,243	)		(1,307	)		--
Deferred income taxes		12,082			67,455			78,747			28,397
Provision for bad debts		11,649			21,216			17,873			12,260
Provision for impairment of other assets		16,425			1,603			--			10,380
Financial derivative trading gains		(302	)		(605	)		(605	)		(6,204	)
Amortization of debt expense		1,064			4,143			2,919			2,936
Gain on sale of subsidiaries and other assets		--			--			(62,992	)		(6,414	)
Loss on sale of subsidiaries		--			1,150			--			1,500
Gain on settlement of interest rate swaps		--			--			--			(17,166	)
Gain on extinguishment of debt		--			(6,354	)		--			--
Business restructuring charges		--			--			--			24,440
Net cash provided (used by) assets held for sale		--			--			(23,698	)		48,618
Earnings from unconsolidated investments		(4,745	)		(200	)		(422	)		(1,420	)
Other		(895	)		(470	)		(707	)		355
Changes in operating assets and liabilities, net of
acquisitions:
Accounts receivable, billed and unbilled		(174,716	)		(6,181	)		(48,520	)		71,932
Gas imbalance receivable		(14,077	)		20,341			6,330			--
Accounts payable		53,304			7,649			22,865			(12,102	)
Gas imbalance payable		30,510			(1,278	)		4,851			--
Customer deposits		1,113			(542	)		5,013			(53	)
Deferred gas purchase costs		10,239			20,670			(21,006	)		53,436
Inventories		(66,841	)		(25,824	)		(34,583	)		1,044
Deferred charges and credits		22,743			13,773			(12,561	)		16,804
Prepaids and other assets		(11,974	)		8,978			2,541			(3,735	)
Taxes and other liabilities		18,323			(4,831	)		(15,736	)		(30,142	)
Net cash flows provided by (used) in operating activities		(19,461	)		339,230			55,833			273,479
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(178,437	)		(226,053	)		(79,730	)		(70,698	)
Acquisition of equity interest in unconsolidated investment		(605,388	)		--			--			--
Acquisitions of operations, net of cash received		--			--			(522,316	)		--
Notes receivable		--			(2,000	)		(6,750	)		(2,750	)
Purchase of investment securities		--			--			--			(938	)
Proceeds from sale of subsidiaries and other assets		--			2,175			437,000			40,935
Proceeds from sale of interest rate swaps		--			--			--			17,166
Net cash used in assets held for sale		--			--			(13,410	)		(23,215	)
Other		(1,711	)		(1,131	)		(6,154	)		274
Net cash flows used in investing activities		(785,536	)		(227,009	)		(191,360	)		(39,226	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in bank overdraft		7,405			1,820			(137	)		137
Issuance of long-term debt		--			750,000			311,087			--
Issuance costs of debt		(337	)		(8,530	)		(313	)		(921	)
Issuance of preferred stock		--			230,000			--			--
Issuance costs of preferred stock		--			(6,590	)		--			--
Issuance of common stock		228,287			--			168,682			--
Issuance of equity units		--			--			125,000			--
Issuance cost of equity units		--			--			(3,443	)		--
Purchase of treasury stock		--			(2,403	)		(2,181	)		(41,632	)
Dividends paid on preferred stock		(8,683	)		(8,393	)		--			--
Repayment of debt and capital lease obligation		(94,123	)		(908,773	)		(500,135	)		(145,131	)
Net (payments) borrowings under revolving credit facilities		678,000			(230,500	)		119,700			(58,800	)
Proceeds from exercise of stock options		4,530			4,122			3,047			8,346
Other		--			--			1,217			2,529
Net cash flows provided by (used in) financing activities		815,079			(179,247	)		222,524			(235,472	)
Change in cash and cash equivalents		10,082			(67,026	)		86,997			(1,219	)
Cash and cash equivalents at beginning of period		19,971			86,997			--			1,219
Cash and cash equivalents at end of period	$	30,053		$	19,971		$	86,997		$	--
Cash paid for interest, net of amounts capitalized for the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 an 2002 was $69,954,000, $143,715,000, $90,462,000 and $99,643,000, respectively. Cash refunded for income taxes in the years ended June 30, 2004 and 2002 was $10,875,000 and $4,214,000, respectively, while cash paid for income taxes for the six months ended December 31, 2004 and the year ended June 30, 2003 was $7,764,000 and $2,351,000, respectively. See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

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

&n bsp; Accumulated

&n bsp; Common Other Total

Common Preferred Premium Treasury Stock Comprehen- Stock-

Stock, $1 Stock, No on Capital Stock, at Held in sive Income Retained holders’

Par Value Par Value Stock Cost Trust (Loss) Earnings Equity

&n bsp; (thousands of dollars)

Balance July 1, 2001	$	54,553		--	$	676,324		$	(15,869	)	$	(11,697	)	$	13,443		$	5,103		$	721,857

Comprehensive income (loss):
Net earnings		--		--		--			--			--			--			19,624			19,624
Unrealized loss in investment
securities, net of tax benefit		--		--		--			--			--			(18,249	)		--			(18,249	)
Minimum pension liability
adjustment, net of tax benefit		--		--		--			--			--			(10,498	)		--			(10,498	)
Unrealized gain on hedging
activities, net of tax		--		--		--			--			--			804			--			804
Comprehensive income (loss)																					(8,319	)
Payment on note receivable		--		--		202			--			--			--			--			202
Purchase of treasury stock		--		--		--			(41,632	)		--			--			--			(41,632	)
5% stock dividend		2,618		--		22,091			--			--			--			(24,727	)		(18	)
Stock compensation plan		--		--		1,248			--			1,257			--			--			2,505
Sale of common stock held in trust		--		--		26			--			1,945			--			--			1,971
Exercise of stock options		884		--		8,021			(172	)		47			--			--			8,780
Balance June 30, 2002		58,055		--		707,912			(57,673	)		(8,448	)		(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
Balance June 30, 2003		73,074		--		909,191			(10,467	)		(5,657	)		(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
Balance June 30, 2004	$	77,141	$	230,000	$	975,104		$	(12,870	)	$	(3,852	)	$	(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		--		--		--		--			--			(62)			--			(62)
Comprehensive income																				5,877
Preferred stock dividends		--		--		--		--			--			--			(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
Balance December 31, 2004	$	90,763	$	230,000	$	1,204,590	$	(12,870	)	$	(3,852	)	$	(59,118	)	$	48,044		$	1,497,557

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.

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

I Summary of Significant Accounting Policies

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 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, and its subsidiaries (hereafter collectively referred to as Panhandle Energy), the Company owns and operates more than 10,000 miles of interstate pipelines that transport up to 5.4 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 Southern Union’s investment in CCE Holdings, LLC (CCE Holdings), the Company has an interest in and operates the Transwestern Pipeline (TWP) and Florida Gas Transmission Company (FGT) interstate pipelines, comprising more than 7,400 miles of interstate pipelines that transport up to approximately 4.1 Bcf/d from western Texas and the San Juan basin to markets throughout the Southwest and to California. Through Southern Union’s three regulated utility divisions -- Missouri Gas Energy, PG Energy and New England Gas Company, the Company serves over 962,000 natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island.

Basis of Presentation. Effective December 17, 2004, Southern Union’s board of directors approved a change in the Company’s fiscal year end from a twelve-month period ending June 30 to a twelve-month period ending December 31. As a requirement of this change, the consolidated financial statements include presentation of the transition period beginning on July 1, 2004 and ending on December 31, 2004. See also Note XXII - Transition Period Comparative Data.

Effective November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron Corp. and its affiliates. The Company’s investment in CCE Holdings, presented within unconsolidated investments in the Consolidated Balance Sheet, is accounted for using the equity method of accounting. Accordingly, Southern Union reports its share of CCE Holdings’ earnings within earnings from unconsolidated investments in the Consolidated Statement of Operations in the period in which such earnings are reported by CCE Holdings.

Effective June 11, 2003, the Company acquired Panhandle Energy from CMS Energy Corporation. The acquisition was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted in the United States of America with the purchase price paid and acquisition costs incurred by the Company allocated to Panhandle Energy’s net assets as of the acquisition date. The Panhandle Energy assets acquired and liabilities assumed have been recorded at their estimated fair value as of the acquisition date based on the results of outside appraisals. Panhandle Energy’s results of operations have been included in the Consolidated Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years.

Effective January 1, 2003, the Company completed the sale of its Southern Union Gas Company natural gas operating division and related assets to ONEOK, Inc. (ONEOK). In accordance with accounting principles generally accepted in the United States of America, 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. See Note II -- Acquisitions and Sales and Note XIX -- Discontinued Operations.

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. All dollar amounts in the tables herein, except per share amounts, are stated in thousands unless otherwise indicated. Certain reclassifications have been made to prior years' financial statements to conform with the current year presentation.

Purchase Accounting. The Company’s acquisition of Panhandle Energy was accounted for using the purchase method of accounting in accordance with the FASB Standard, Business Combinations. CCE Holdings, a joint venture in which Southern Union owns a 50% 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 determination of fair value. The appraisals related to Southern Union’s acquisition of Panhandle Energy were finalized in 2004. The outside appraisals to be completed for CCE Holdings’ purchase of CrossCountry Energy are to be completed in 2005. Accordingly, any changes in the preliminary allocations of fair value due to the completion of the appraisals will be reflected through the Company’s investment in, and the equity earnings from, CCE Holdings at the time such changes are known.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

Segment Reporting. The Financial Accounting Standards Board (FASB) Standard, 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 (i) the transportation and storage and (ii) 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.

Gas Utility 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 on transportation, storage and terminalling of natural gas are recognized as service is provided. Receivables are subject to normal trade terms and are reported net of an allowance for doubtful accounts. Prior to final Federal Energy Regulatory Commission (FERC) approval of filed rates, the Company is exposed to risk that FERC will ultimately approve the rates at a level lower than those requested. The difference is subject to refund and reserves are established, where required, for that purpose.

Earnings Per Share. The Company’s earnings per share presentation conforms to the FASB Standard, Earnings per Share. All share and per share data have been appropriately restated for all stock dividends and stock splits distributed through August 31, 2004 unless otherwise noted.

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

The following table illustrates the effect on net earnings and net earnings available for common shareholders per share if the Company had applied the fair value recognition provisions of the FASB Standard, Accounting for Stock-Based Compensation, as amended by the FASB Standard, Accounting for Stock-Based Compensation—Transition and Disclosure, to stock-based employee compensation:

	Six Months
		Ended
		December 31,		Year Ended June 30,
		2004		2004		2003		2002

Net earnings, as reported		$	14,771	$	114,025	$	76,189	$	19,624
Deduct total stock-based employee compensation
expense determined under fair value based method
for all awards, net of related taxes			496		1,699		1,373		953
Pro forma net earnings		$	14,275	$	112,326	$	74,816	$	18,671

Net earnings available for common shareholders per share:
Basic- as reported		$	0.07	$	1.34	$	1.26	$	0.33
Basic- pro forma		$	0.07	$	1.32	$	1.23	$	0.31

Diluted- as reported		$	0.07	$	1.30	$	1.22	$	0.31
Diluted- pro forma		$	0.06	$	1.29	$	1.21	$	0.30

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 grants in the years ended June 30, 2004 and 2002, respectively: dividend yield of nil for all years; volatility of 36.75% in 2004 and 33.5% for 2002; risk-free interest rate of 2.95% in 2004, and 3.75% in 2002; and expected life outstanding of 6 years for 2004 and 7 years for 2002. The weighted average fair value of options granted at fair market value at their grant date during the years ended June 30, 2004 and 2002 were $7.35 and $6.92, respectively. There were no options granted above fair market value at the grant date during the years ended June 30, 2004 and 2002, respectively. No options were granted during the six months ended December 31, 2004 or during the year ended June 30, 2003.

Accumulated Other Comprehensive Income. The Company reports comprehensive income and its components in accordance with the FASB Standard, Reporting Comprehensive Income. The main components of comprehensive income that relate to the Company are net earnings, unrealized holding gains and losses on investment securities, minimum pension liability adjustments and unrealized gains and losses on hedging activities, all of which are presented in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss).

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

	Six Months
	Ended
	December 31,				Year Ended June 30,
			2004			2004			2003			2002

Net earnings		$	14,771		$	114,025		$	76,189		$	19,624
Other comprehensive income (loss):
Unrealized loss in investment securities, net of tax benefit			--			(21	)		(581	)		(18,249	)
Unrealized gain (loss) on hedging activities, net of tax (benefit)			2,154			7,105			(5,562	)		406
Realized gain (loss) on hedging activities in net earnings,
net of tax (benefit)			(2,216	)		(5,497	)		(6	)		398
Minimum pension liability adjustment, net of tax (benefit)			(8,832	)		10,768			(41,930	)		(10,498	)
Other comprehensive income (loss)			(8,894	)		12,355			(48,079	)		(27,943	)
Comprehensive income (loss)		$	5,877		$	126,380		$	28,110		$	(8,319	)

Accumulated other comprehensive income (loss) reflected in the Consolidated Balance Sheet at December 31, 2004, includes unrealized gains and losses on hedging activities, and minimum pension liability adjustments.

Significant Customers and Credit Risk. 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. The Company has recorded an allowance for doubtful accounts totaling $12,807,000, $13,502,000 and $16,823,000 at December 31, 2004, June 30, 2004 and June 30, 2003, respectively, relating to its Distribution segment trade receivables.

In the Transportation and Storage segment, aggregate sales to Panhandle Energy’s top 10 customers accounted for 67% and 70% of segment operating revenues and 21% and 19% of the Company’s total operating revenues for the six-months ended December 31, 2004 and year ended June 30, 2004, respectively. For the six months ended December 31, 2004, this included sales to Proliance Energy, LLC, a nonaffiliated local distribution company and gas marketer, which accounted for 17% of segment operating revenues; sales to BG LNG Services, a nonaffiliated gas marketer, which accounted for 16% of segment operating revenues; and sales to Ameren Corporation, another nonaffiliated gas marketer, which accounted for 11% of the segment operating revenues. For the year ended June 30, 2004, sales to Proliance Energy, LLC accounted for 17% of segment operating revenues; sales to BG LNG Services accounted for 16% of segment operating revenues; and sales to CMS Energy Corporation, Panhandle Energy’s former parent, accounted for 11% of the segment operating revenues. No other customer accounted for 10% or more of the Transportation and Storage segment operating revenues, and no single customer or group of customers under common control accounted for 10% or more of the Company’s total operating revenues for the six months ended December 31, 2004 or for the year ended June 30, 2004. 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. The Company has recorded an allowance for doubtful accounts totaling $1,289,000, $1,422,000 and $4,138,000 at December 31, 2004, June 30, 2004 and June 30, 2003, respectively, relating to its Transportation and Storage segment trade receivables.

Inventories. 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, 2004, June 30, 2004 and June 30, 2003 was $161,676,000, $116,292,000 and $117,679,000, respectively, and consisted of 28,091,000, 19,918,000 and 20,853,000 million British thermal units (MMBtu), respectively.

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 is not expected to be consumed in operations in the next twelve months is reflected in non-current assets. Gas held for operations at December 31, 2004 was $116,752,000, or 20,936,000 MMBtu, of which $30,471,000 is classified as non-current. Gas held for operations at June 30, 2004 was $94,586,000, or 17,562,000 MMBtu, of which $28,999,000 is classified as non-current. Gas held for operations at June 30, 2003 was $57,647,000, or 11,657,000 MMBtu, of which $22,769,000 is classified as non-current.

Unconsolidated Investments. Investments in affiliates over which we may exercise significant influence, generally 20% to 50% ownership interests, are accounted for using the equity method. Any excess of our investment in affiliates, as compared to our 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 we may not exercise significant influence are accounted for under the cost method. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, or when a condition is identified that suggests a possible impairment. Write-downs associated with equity-method investments are recognized in earnings (losses) from unconsolidated investments in the Consolidated Statement of Operations, and write-downs associated with cost-method investments are recognized in other income (expense), net, in the Consolidated Statement of Operations.

Regulatory Assets and Liabilities. The Company is subject to regulation by certain state and federal authorities. The Company, in its Distribution segment, has accounting policies which conform to the FASB Standard, 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 are then flowed 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.

Goodwill and Other Intangible Assets. The Company accounts for its goodwill and other intangible assets in accordance with the FASB Standard, Accounting for Goodwill and Other Intangible Assets. Under this Statement, the Company has ceased amortization of goodwill. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value based test. See Note VII - Goodwill and Intangibles.

Fair Value of Financial Instruments. The carrying amounts reported in the balance sheet for cash and cash equiva-lents, accounts receivable, accounts payable, derivative instruments and notes payable approximate their fair value. The fair value of the Com-pany’s long-term debt is estimated using current market quotes and other estimation techniques.

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 which have reduced system gas are valued at the cost basis of the system gas, while net imbalances which have increased system gas and are owed back to customers are priced, along with the corresponding system gas, at market.

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 underrecovery 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 underrecovered. 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 the FASB Standard, Capitalization of Interest Cost. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets.

Derivative Instruments and Hedging Activities. The Company accounts for its derivatives and hedging activities in accordance with the FASB Standard, Accounting for Derivative Instruments and Hedging Activities, as amended (see Note XI - Derivative Instruments and Hedging Activities).

Asset Retirement Obligations. The Company accounts for its asset retirement obligations in accordance with the FASB Standard, Accounting for Asset Retirement Obligations (ARO). The Statement requires 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 should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Over time, 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. The adoption of the Statement did not have a material impact on the Company’s financial position, results of operations or cash flows for all periods presented.

Panhandle Energy has an ARO liability relating to the retirement of certain of its offshore lateral lines with an aggregate carrying amount of approximately $5,657,000, $6,407,000 and $6,757,000 as of December 31, 2004, June 30, 2004 and June 30, 2003, respectively. During the six months ended December 31, 2004, the change in the carrying amount of the ARO liability was attributable to $249,000 of accretion expense offset by $999,000 of liabilities settled and cash flow revisions. During the year ended June 30, 2004, the change in the carrying amount of the ARO liability was attributable to $395,000 of additional liabilities and $628,000 of accretion expense, offset by $1,373,000 of liabilities settled and cash flow revisions.

During the year ended June 30, 2003, the Company classified approximately $27,000,000 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 which were not liabilities under the Statement but represent other legal obligations.

Income Taxes. Income taxes are accounted for using the provisions of the FASB Standard, 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.

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.

New Pronouncements.

In December 2004, the FASB issued 123R, Share-Based Payment (revised 2004). The Statement revises FASB Statement No. 123, Accounting for Stock-Based Compensation, supersedes the Accounting Principal Board Opinion, Accounting for Stock Issued to Employees and amends FASB Statement No. 95, Statement of Cash Flows. The Statement will be effective for the Company in the first interim reporting period beginning after June 15, 2005 and will require the Company to measure all employee stock-based compensation awards using a fair value method and record such expense in its consolidated financial statements. In addition, the adoption the Statement will require additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed. The Act raises a number of issues with respect to accounting for income taxes. On December 21, 2004, the FASB issued a Staff Position regarding the accounting implications of the Act related to the deduction for qualified domestic production activities (FSP FAS 109-1) which is effective for periods subsequent to December 31, 2004. The guidance in the FSP otherwise applies to financial statements for periods ending after the date the Act was enacted. In FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the FASB decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. In most cases, a company’s existing deferred tax balances will not be impacted at the date of enactment. For some companies, the deduction could have an impact on their effective tax rate and, therefore, should be considered when determining the estimated annual rate used for interim financial reporting. The Company is currently evaluating the impact, if any, of this FSP on its consolidated financial statements.

II Acquisitions and Sales

On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy from Enron and its subsidiaries for a purchase price of approximately $2,450,000,000 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 $175,000,000 in cash. Following these transactions, CCE Holdings owns 100% of Transwestern Pipeline (TWP) and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of Florida Gas Transmission Company (FGT). An affiliate of El Paso Corporation owns the remaining 50% of Citrus. The Company funded its $590,500,000 equity investment in CCE Holdings through borrowings of $407,000,000 under an equity bridge-loan facility, net proceeds of $142,000,000 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 $42,000,000 under its existing revolving credit facility. Subsequently, in February 2005 Southern Union issued 2,000,000 of its 5% Equity Units from which it received net proceeds of approximately $97,405,000, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $332,616,000, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note X - 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 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 $16,000,000 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 (a)		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

(a)	Includes cash and cash equivalents of approximately $60 million.

In April 2002, PG Energy Services’ (Energy Services) propane operations, which sold liquid propane to residential, commercial and industrial customers, were sold for $2,300,000, resulting in a pre-tax gain of $1,200,000. In July 2001, Energy Services’ commercial and industrial gas marketing contracts were sold for $4,972,000, resulting in a pre-tax gain of $4,653,000.

In October 2001, Morris Merchants, Inc., which served as a manufacturers’ representative agency for franchised plumbing and heating contract supplies throughout New England, was sold for $1,586,000. In September 2001, Valley Propane, Inc., which sold liquid propane to residential, commercial and industrial customers, was sold for $5,301,000. In August 2001, ProvEnergy Oil Enterprises, Inc., which operated a fuel oil distribution business through its subsidiary, ProvEnergy Fuels, Inc. for residential and com-mercial customers, was sold for $15,776,000. No financial gain or loss was recognized on any of these sales transactions.

Pro Forma Financial Information

The following unaudited pro forma financial information for the years ended June 30, 2003 and 2002 is presented as though the following events had occurred at the beginning of the earliest period presented: (i) 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		2002
Operating revenues	$	1,671,114	$	1,467,630
Net earnings from continuing operations		132,458		56,073
Net earnings per share from continuing operations
Basic		1.76		0.75
Diluted		1.72		0.72

III Other Income (Expense), Net

Other expense for the six months ended December 31, 2004 of $18,080,000 includes a non-cash charge of $16,425,000 to reserve for the other-than-temporary impairment of the Company’s investment in a technology company (see Note IX -- 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 $5,468,000 includes a gain of $6,354,000 on the early extinguishment of debt and income of $2,230,000 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 $1,603,000 and $1,150,000 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 $17,979,000 includes a gain of $22,500,000 on the settlement of the Southwest litigation and income of $2,016,000 generated from the sale and/or rental of gas-fired equipment and appliances. These items were partially offset by $5,949,000 of legal costs related to the Southwest litigation and $1,298,000 of selling costs related to the Texas operations’ disposition.

Other income for the year ended June 30, 2002 of $12,858,000 includes gains of $17,166,000 generated through the settlement of several interest rate swaps, the recognition of $6,204,000 in previously recorded deferred income related to financial derivative energy trading activity of a former subsidiary, a gain of $4,653,000 realized through the sale of marketing contracts held by PG Energy Services Inc., income of $2,234,000 generated from the sale and/or rental of gas-fired equipment and appliances, a gain of $1,200,000 realized through the sale of the propane assets of PG Energy Services Inc. and $1,004,000 of realized gains on the sale of a portion of Southern Union's holdings in Capstone. These items were partially offset by a non-cash charge of $10,380,000 to reserve for the impairment of the Company’s investment in a technology company, $9,100,000 of legal costs associated with litigation from the unsuccessful acquisition of Southwest, and a $1,500,000 loss on the sale of the Florida Operations.

IV Cash Flow Information

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 invest-ments with a high credit quality financial institution which, 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, 2004, June 30, 2004 and June 30, 2003, such overdraft balances classified in accounts payable were approximately $9,225,000, $1,820,000 and nil, respectively.

V Earnings Per Share

The following table summarizes the Company’s basic and diluted earnings per share (EPS) calculations for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003, and 2002:

	Six Months
	Ended
	December 31,			Year Ended June 30,
		2004		2004		2003		2002

Net earnings available for common shareholders
from continuing operations		$	6,088	$	101,339	$	43,669	$	1,520
Net earnings from discontinued operations			--		--		32,520		18,104
Net earnings available for common shareholders		$	6,088	$	101,339	$	76,189	$	19,624

Weighted average shares outstanding -- basic			81,995,878		75,442,238		60,584,293		59,420,048
Weighted average shares outstanding -- diluted			85,298,894		77,694,607		62,523,110		62,596,907

Basic earnings per share:
Net earnings available for common shareholders
from continuing operations		$	0.07	$	1.34	$	0.72	$	0.03
Net earnings from discontinued operations			--		--		0.54		0.30
Net earnings available for common shareholders		$	0.07	$	1.34	$	1.26	$	0.33

Diluted earnings per share:
Net earnings available for common shareholders
from continuing operations		$	0.07	$	1.30	$	0.70	$	0.02
Net earnings from discontinued operations			--		--		0.52		0.29
Net earnings available for common shareholders		$	0 .07	$	1.30	$	1.22	$	0.31

Basic earnings per share is computed based on the weighted-average number of common shares outstanding during each period, reduced by total shares held in various rabbi trusts. 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, 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 Ended December 31,			Year Ended June 30,
	2004			2004			2003			2002
Weighted average shares outstanding		83,153,406			76,599,311			61,853,526			60,767,881
Less weighted average rabbi trust shares outstanding		(1,157,528	)		(1,157,073	)		(1,269,233	)		(1,347,833	)
Weighted average shares outstanding - Basic		81,995,878			75,442,238			60,584,293			59,420,048

Weighted average shares outstanding		83,153,406			76,599,311			61,853,526			60,767,881
Add assumed conversion of equity units		1,116,968			--			--			--
Add assumed exercise of stock options		1,028,520			1,095,296			669,584			1,829,026
Weighted average shares outstanding - Dilutive		85,298,894			77,694,607			62,523,110			62,596,907

During the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 and 2002, no adjustments were required in net earnings available for common shareholders for the earnings per share calculations.

During the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 and 2002, the Company repurchased nil, 122,203, 156,340 and 2,115,916 shares of its common stock outstanding, respectively. Substantially all of these repurchases occurred in private off-market large-block transactions.

Stock options to purchase 290,893 and 2,308,870, shares of common stock were outstanding during the years ended June 30, 2004 and 2003, respectively but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares during the respective period. There were no “anti-dilutive” options outstanding during the six month period ended December 31, 2004 and the year ended June 30, 2002. At December 31, 2004, 1,198,034 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans and 110,996 shares were held in a rabbi trust for certain employees who deferred receipt of Company shares for stock options exercised. 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, the Company issued 2,000,000 equity units at a public offering price of $50 per unit. Each equity unit consists of a 1/20^th interest in a $1,000.00 principal amount of the Company’s 4.375% Senior Notes due 2008 (see Note XIII - Debt and Capital Lease) and a forward stock purchase contract that obligates the holder to purchase Company 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 $24.61 and $30.76, respectively, which are subject to adjustments for future stock splits or stock dividends). The Company will issue between 3,250,711 shares and 4,063,389 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contract. Until the conversion date, the equity units will have a dilutive effect on earnings per share if the Company’s average common stock price for the period exceeds the maximum conversion price. See Note X - Stockholders’ Equity.

On June 11, 2003, the Company issued 2,500,000 equity units at a public offering price of $50 per unit. Each equity unit consists of a $50.00 principal amount of the Company’s 2.75% Senior Notes due 2006 (see Note XIII - Debt and Capital Lease) and a forward stock purchase contract that obligates the holder to purchase Company 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 $14.51 and $17.71, respectively, which are subject to adjustments for future stock splits or stock dividends). The Company will issue between 7,060,067 shares and 8,613,281 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contract. Until the conversion date, the equity units will have a dilutive effect on earnings per share if the Company’s average common stock price for the period exceeds the maximum conversion price. See Note X - Stockholders’ Equity

VI Property, Plant and Equipment

Plant. Plant in service and construction work in progress are stated at cost net of contributions in aid of construction and includes intangible assets and related amortization. The Company capitalizes all construction-related direct labor costs, as well as indirect construction costs. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of additions includes an allowance for funds used during construction and applicable overhead charges. Gain or loss is recognized upon the disposition of significant properties and other property constituting operating units. The Company capitalizes the cost of significant internally-developed computer software systems. See Note XIII -- Debt and Capital Lease.

	December 31,			June 30,
	2004			2004			2003

Distribution plant	$	1,707,174		$	1,662,345		$	1,611,098
Transmission plant		1,185,647			1,159,825			1,238,972
General-- LNG		388,703			388,459			297,694
General plant-- other		143,435			141,140			165,036
Underground storage plant		274,337			287,005			236,639
Gathering plant		46,074			39,746			56,076
Other		126,308			96,308			107,444
Total plant (a)		3,871,678			3,774,828			3,712,959
Less contributions in aid of construction		(2,457	)		(2,212	)		(2,418	)
Plant in service		3,869,221			3,772,616			3,710,541
Construction work in progress		237,283			169,264			75,484
		4,106,504			3,941,880			3,786,025
Less accumulated depreciation and amortization (a)		(778,876	)		(734,367	)		(641,225	)
Net property, plant and equipment	$	3,327,628		$	3,207,513		$	3,144,800

(a) Includes capitalized computerized software cost totaling:

Unamortized computer software cost	$	118,596		$	82,369		$	87,647
Less accumulated amortization		(40,378	)		(36,483	)		(27,663	)
Net capitalized computer software costs	$	78,218		$	45,886		$	59,984

Amortization expense of capitalized computer software costs for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003 and 2002 was $7,615,000, $10,017,000, $9,960,000 and $11,758,000, respectively. During the six months ended December 31, 2004, the Company recorded in amortization expense a $2,298,000 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 $34,224,000 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 over an average of 7 to 10 years, based on the useful life of each specific project.

Depreciation and Amortization. The Company computes depreciation expense using the straight-line method over periods ranging from 1 to 71 years. Depreciation rates for the utility and transmission plants are approved by the Company’s regulatory commissions. The composite weighted-average depreciation rates for the six months ended December 31, 2004 and for the years ended June 30, 2004, 2003 and 2002 were 3.3%, 3.2%, 3.1% and 3.3%, respectively.

VII Goodwill and Intangibles

The Company follows the FASB Standard Goodwill and Other Intangible Assets to account for goodwill and intangible assets. In accordance with this Statement, the Company has ceased amortization of goodwill. 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.

The following displays changes in the carrying amount of goodwill:

	Total
Balance as of July 1, 2001	$	652,048
Impairment losses		(1,417	)
Sale of subsidiaries and other operations		(7,710	)
Balance as of June 30, 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

In connection with the Company's cash flow improvement plan announced in July 2001, the Company began the divestiture of certain non-core assets. As a result of prices of comparable businesses for various non-core properties, a goodwill impairment loss of $1,417,000 was recognized in depreciation and amortization on the Consolidated Statement of Operations for the quarter ended September 30, 2001. As a result of the sale of the Florida Operations, goodwill of $7,710,000 was eliminated during the quarter ended December 31, 2001. As a result of the sale of the Texas Operations, goodwill of $70,469,000 (reclassified as a component of assets held for sale for all periods presented above, see Note XIX - Discontinued Operations) was also 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 $2,347,000 was eliminated during the quarter ended June 30, 2004. As of December 31, 2004, the Distribution segment has goodwill of $640,547,000. The Distribution segment is tested annually for impairment.

On June 11, 2003, the Company completed its acquisition of Panhandle Energy. Based on purchase price allocations which rely on estimates and outside appraisals, the acquisition resulted in no recognition of goodwill. In addition, based on the purchase price allocations and the outside appraisals, the acquisition resulted in the recognition of intangible assets relating to customer relationships of approximately $9,503,000. 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, 2004, the carrying amount of these intangibles was approximately $8,496,000 and is included in Property, Plant and Equipment on the Consolidated Balance Sheet. Amortization expense on the customer contracts for the six months ended December 31, 2004 and for the years ended June 30, 2004 and 2003 was approximately $224,000, $583,000 and $200,000, respectively.

VIII Deferred Charges and Deferred Credits

	December 31,		June 30,
	2004		2004		2003
Deferred Charges
Pensions	$	54,097	$	45,625	$	39,088
Unamortized debt expense		37,869		38,596		34,209
Income taxes		32,661		31,441		30,514
Retirement costs other than pensions		24,459		26,008		29,028
Service Line Replacement program		15,161		16,722		18,974
Environmental		16,332		12,220		14,304
Other		18,485		20,123		22,144
Total Deferred Charges	$	199,064	$	190,735	$	188,261

As of December 31, 2004, June 30, 2004 and June 30, 2003, the Company’s deferred charges include regulatory assets relating to Distribution segment operations in the aggregate amount of $100,653,000, $99,314,000 and $107,696,000, respectively, of which $60,611,000, $63,010,000 and $74,116,000, respectively, is being recovered through current rates. As of December 31, 2004, June 30, 2004 and June 30, 2003, the remaining recovery period associated with these assets ranges from 1 month to 199 months, 1 month to 208 months and from 6 months to 147 months, respectively. None of these regulatory assets, which primarily relate to pensions, retirement costs other than pensions, income taxes, Year 2000 costs, Missouri Gas Energy’s Service Line Replacement program and environmental remediation costs, are included in rate base. The Company records regulatory assets with respect to its Distribution segment operations in accordance with the FASB Standard, Accounting for the Effects of Certain Types of Regulation.

	December 31,		June 30,
	2004		2004		2003
Deferred Credits
Pensions	$	109,908	$	97,380	$	88,016
Retirement costs other than pensions		58,507		60,404		65,144
Costs of removal		29,337		28,519		27,286
Environmental		25,919		23,082		32,322
Derivative instrument liability		16,232		13,704		26,151
Customer advances for construction		14,740		13,518		12,008
Provision for self-insured claims		12,296		10,542		12,000
Investment tax credit		5,157		5,367		5,791
Other		48,953		40,430		53,436
Total Deferred Credits	$	321,049	$	292,946	$	322,154

As of December 31, 2004, June 30, 2004 and June 30, 2003, the Company’s deferred credits include regulatory liabilities relating to Distribution segment operations in the aggregate amount of $15,285,000, $11,164,000 and $10,084,000, respectively. These regulatory liabilities primarily relate to retirement benefits other than pensions, environmental insurance recoveries and income taxes. The Company records regulatory liabilities with respect to its Distribution segment operations in accordance with the FASB Standard Accounting for the Effects of Certain Types of Regulation.

IX Unconsolidated Investments

Unconsolidated affiliates primarily pertain to the Company’s investment in CCE Holdings, which is accounted for using the equity method. The Company’s share of net income or loss from CCE Holdings is recorded in earnings from unconsolidated investments.

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

	December 31, 2004		June 30, 2004		June 30, 2003

Equity Investment in CCE Holdings	$	615,861	$	-	$	-
Other Equity Investments		12,919		12,818		13,041
Other Investments, at Cost		3,113		8,038		9,641

Total Investments in Unconsolidated Affiliates	$	631,893	$	20,856	$	22,682

The Company’s investment balances include unamortized purchase price differences of $20,716,000, nil and nil as of December 31, 2004, June 30, 2004 and June 30, 2003, respectively. The unamortized 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 the FASB Standard Goodwill and Other Intangible Assets.

CCE Holdings. On November 17, 2004, CCE Holdings acquired CrossCountry Energy from Enron and its affiliates for $2,450,000,000 in cash, including certain consolidated debt. The Company contributed an equity investment of $590,500,000 to CCE Holdings to finance a portion of the cost of that 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% of the outstanding membership interests, and a wholly-owned subsidiary of General Electric (GE) owned all of the “Class B” membership interests of CCE Holdings, comprising 50% 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 30% of CCE Holdings, and these investors own 20% of CCE Holdings. CrossCountry Energy owns 100% of TWP and 50% of Citrus, which, in turn, owns 100% of FGT. An affiliate of El Paso Corporation owns the remaining 50% interest in Citrus. CrossCountry Energy is comprised of approximately 7,400 miles of natural gas pipelines with approximately 4.1 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.

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 (the 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 member 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. No management fees are due under the Agreement for any portion of 2004.

Southern Union and GE, through their respective wholly-owned subsidiaries, each have identical call options to purchase a 25% 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 (the Transfer Restriction Period) 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, or another investor, after ten years following the CrossCountry Energy acquisition. 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 Equity Investments. 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 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.

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

	As of December 31, 2004
	CCE Holdings		Other Equity Investments
Balance Sheet Data:
Current assets	$	64,482	$	1,255
Non-current assets		2,249,386		22,847
Current liabilities		65,670		833
Non-current liabilities		1,057,908		2,625

	For the Period Ended December 31, 2004

		CCE Holdings		Other Equity Investments

Income Statement Data: ^(a)
Revenues	$	27,195	$	1,919
Operating income		7,300		394
Net income		9,290		295
(a) The CCE Holdings summarized income statement information represents the results of operations from the date CCE Holdings acquired CrossCountry Energy on November 17, 2004 to December 31, 2004. CCE Holdings did not have any operations prior to the CrossCountry Energy acquisition.

See Note I, Summary of Significant Accounting Policies - Purchase Accounting.

Other Investments, at Cost. At December 31, 2004, the Company owned common and preferred stock in non-public companies, Advent Networks, Inc. (Advent) and PointServe, Inc. (PointServe), whose fair values are not readily determinable. These investments are accounted 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 Southern Union executive management, Board of Directors and employees also have an equity ownership in Advent.

The Company reviews its portfolio of 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: 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 Southern Union's intent and ability to retain the investment. If Southern Union determines that the decline in value of an investment security is other-than-temporary, it will record a charge in other income (expense), net on the Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value.

In December 2004, the Company recorded a total non-cash charge of $16,425,000 to recognize an other-than-temporary impairment of the carrying value of its investment in Advent. This impairment was comprised of a write-down of $4,925,000 and $11,500,000 to the Company’s investment and convertible notes receivable accounts, respectively. Based on Advent's recent efforts 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 began the process of reevaluating the fair value of its investment in Advent. The foregoing, as well as certain other factors, led to the non-cash charge discussed above. After the non-cash write-down, the Company’s remaining investment in Advent as of December 31, 2004, is $508,000. This remaining investment may be subject to future market risk. Additionally, a wholly-owned subsidiary of the Company has provided a guarantee for a $4,000,000 line of credit between Advent and a bank. Advent remains current and is not in default on this line of credit.

X Stockholders’ Equity

Stock Splits and Dividends. On August 31, 2004, July 31, 2003 and July 15, 2002, Southern Union distributed its annual 5% common stock dividend to stock-holders of record on August 20, 2004, July 17, 2003 and July 1, 2002, respectively. A portion of the 5% stock dividend distributed on July 15, 2002 was characterized as a distribution of capi-tal due to the level of the Company's retained earnings available for distribution as of the declaration date. Unless other-wise stated, all per share and share data included herein have been restated to give effect to the dividends.

Common Stock. On November 4, 2003, the stockholders of the Company adopted the 2003 Stock and Incentive Plan (2003 Plan) under which options to purchase 7,350,000 shares were provided to be granted to officers and key employees at prices not less than fair market value on the date of the grant, until September 28, 2013. The 2003 Plan allows for the granting of stock appreciation rights, stock awards, performance units, dividend equivalents, incentive options, non-statutory options, and other equity-based rights. Options granted under the 2003 Plan are exercisable for periods of ten years from the date of the 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.

The Company maintains its 1992 Long-Term Stock Incentive Plan (1992 Plan) under which options to purchase 8,491,540 shares of its common stock were provided to be granted to officers and key employees at prices not less than the fair market value on the date of grant, until July 1, 2002. The 1992 Plan allowed for the granting of stock appreciation rights, dividend equivalents, per-for-mance 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 20% per year for five years but may be a lesser or greater period as designated for a particular option grant.

In connection with the acquisition of the Pennsylvania Operations, the Company adopted the Pennsylvania Division 1992 Stock Option Plan (Pennsylvania Option Plan) and the Pennsylvania Division Stock Incentive Plan (Pennsyl-vania Incentive Plan). Under the terms of the Pennsylvania Option Plan, a total of 459,467 shares were provided to be granted to eligible employees. Stock options awarded under the Pennsylvania Option Plan may be either Incentive Stock Options or Nonqualified Stock Options. Upon acquisition, individuals not electing a cash payment equal to the difference at the date of acquisition between the option price and the market price of the shares as to which such option related, were converted to Southern Union options using a conversion rate that main-tained the same aggregate value and the aggregate spread of the pre-acquisition options. No additional options will be granted under the Pennsylvania Option Plan. During the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, options exercised were nil, nil and 15,538 options, respectively, and 443,929 options outstanding and exercisable still remain in the plan. Under the terms of the Pennsylvania Incentive Plan, a total of 220,635 shares were provided to be granted to eligible employees, officers and directors. Awards under the Pennsylvania Incentive Plan may take the form of stock options, restricted stock, and other awards where the value of the award is based upon the performance of the Company’s stock. Upon acquisition, individuals not electing a cash payment equal to the difference at the date of acquisition between the option price and the market price of the shares as to which such option related, were converted to Southern Union options using a conversion rate that maintained the same aggregate value and the aggregate spread of the pre-acquisition options. No additional options will be granted under the Pennsylvania Incentive Plan. During the six months ended December 31, 2004 and the years ended June 30, 2004 and 2003, no options were exercised and 220,635, 220,635 and 217,571 options, respectively, outstanding and exercisable still remain in the plan.

The following table provides information on stock options granted, exercised, canceled and outstanding under the 2003 Plan and the 1992 Plan for the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 and 2002:

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

Outstanding July 1, 2001		--		$	--		4,957,666		$	11.29
Granted		--			--		75,249			13.83
Exercised		--			--		(1,020,546	)		9.54
Canceled		--			--		(188,856	)		14.45
Outstanding June 30, 2002		--			--		3,823,513			11.65
Granted		--			--		--			--
Exercised		--			--		(662,982	)		4.65
Canceled		--			--		(185,161	)		14.67
Outstanding June 30, 2003					--		2,975,370			13.02
Granted		729,227			17.67		--			--
Exercised		--			-- -		(352,486	)		9.91
Canceled		--			--		(2,190	)		15.38
Outstanding June 30, 2004		729,227			17.67		2,620,694			13.44
Granted							--
Exercised							(340,068	)		13.32
Canceled		(51,450	)		17.67		(17,012	)		15.36
Outstanding December 31, 2004		677,777		$	17.67		2,263,614		$	13.44

The following table summarizes information about stock options outstanding under the 1992 Plan at December 31, 2004:

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

$ 0.00 - $ 7.99	120,779		0.8 years	$ 6.74	105,932	$ 6.74
8.00 - 11.99	271,058		2.3 years	10.22	271,058	10.22
12.00 - 13.99	503,785		3.7 years	13.26	469,484	13.26
14.00 - 17.99	1,367,992		5.4 years	14.74	1,159,090	14.62
	2,263,614				2,005,564

The weighted average remaining contractual life of options outstanding under the 2003 Plan, the Pennsylvania Option Plan and the Pennsylvania Incentive Plan at December 31, 2004 was 8.8, 1.6 and 3.4 years, respectively. There were no shares available for future option grants under the 1992 Plan at December 31, 2004.

The options exercisable under the various plans and corresponding weighted average exercise price at December 31, 2004, June 30, 2004, June 30, 2003 and June 30, 2002 are as follows:

Pennsylvania Pennsylvania

2003 1992 Option Incentive

Plan Plan Plan Plan

Options exercisable at:
December 31, 2004	21,000	2,005,564	443,929	220,635
June 30, 2004	--	2,008,066	443,929	217,571
June 30, 2003	--	1,966,753	443,929	214,507
June 30, 2002	--	2,145,327	459,467	211,442

Weighted average exercise price at::
December 31, 2004	$ 17.67	$ 13.29	$ 9.21	$ 10.70
June 30, 2004	--	13.12	9.21	10.65
June 30, 2003	--	12.29	9.21	10.60
June 30, 2002	--	9.51	9.12	10.55

Warrant. On February 10, 1994, Southern Union granted a war-rant to purchase up to 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 (non-cash) resulting in the issuance of 84,758 shares of Company common stock.

Retained Earnings. Under the most restrictive pro-visions in effect, under the terms of the indenture governing its Senior Notes, Southern Union will not declare or pay any cash or asset dividends on 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 Southern Union's common stock, unless no event of default exists and the Company meets certain financial ratio requirements. Currently, the Company is in compliance with the most restrictive provisions in the indenture governing the Senior Notes.

February 2005 Equity Issuances. On February 9, 2005, the Company issued 14,913,042 shares of common stock at $23.00 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $332,616,000. The net proceeds were used to repay a portion of a bridge loan used to finance a portion of Southern Union’s investment in CCE Holdings.

On February 11, 2005, the Company issued 2,000,000 equity units at a public offering price of $50 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $97,405,000. The proceeds were used to repay the balance of the bridge loan used to finance a portion of Southern Union’s investment in CCE Holdings and to repay borrowings under the Company’s credit facilities. Each 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 February 16, 2008, issued pursuant to the Company’s existing indenture. The equity units carry a total annual coupon of 5.00% (4.375% annual face amount of the senior notes plus 0.625% annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 25% over the $24.61 issuance price of the underlying shares of the Company’s common stock. The present value of the equity units contract adjustment payments will be initially charged to shareholders’ equity, with an offsetting credit to liabilities. The liability will be 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 purchase contracts will be reflected in the Company’s diluted earnings per share calculations using the treasury stock method.

July 2004 Equity Issuances. 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, of $86,900,000. 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. Under the terms of the forward sale agreements, the Company 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) through the physical delivery of shares. Upon settlement, which occurred on November 16, 2004, Southern Union received approximately $142,000,000 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. 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.

June 2003 Equity Issuances. 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 $146,700,000. 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 $22,000,000.

Also on June 11, 2003, the Company issued 3,000,000 shares of common stock from its treasury stock to CMS Energy Corporation to finance its acquisition of Panhandle Energy. The shares were valued at $16.30 per share, or $48,900,000, based on the closing price for the Company's common stock as of June 10, 2003.

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 $121,300,000. Each 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 equity units carry a total annual coupon of 5.75% (2.75% annual face amount of the senior notes plus 3.0% annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 22% 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 equity units contract adjustment payments was initially charged to shareholders’ 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 purchase contracts will be reflected in the Company’s diluted earnings per share calculations using the treasury stock method.

XI Derivative Instruments and Hedging Activities

The Company follows the FASB Standard, 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.

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 converts fixed-rate debt to floating. 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. The Company is party to interest rate swap agreements with an aggregate notional amount of $193,827,000 as of December 31, 2004 that fix the interest rate applicable to floating rate long-term debt and which qualify for hedge accounting. For the six months ended December 31, 2004, the amount of swap ineffectiveness was not significant. As of December 31, 2004, floating rate LIBOR-based interest payments are exchanged for weighted average fixed rate interest payments of 5.88%, which does not include the spread on the underlying variable debt rate of 1.63%. As such, payments or receipts on interest rate swap agreements, in excess of the liability recorded, are recognized as adjustments to interest expense. As of December 31, 2004, June 30, 2004 and June 30, 2003, the fair value liability position of the swaps was $11,053,000, $14,445,000 and $26,058,000, respectively. As of December 31, 2004, approximately $1,150,000 of net after-tax gains included in accumulated other comprehensive income related to these swaps is expected to be reclassified to interest expense during the next twelve months as the hedged interest pay-ments occur. Current market pricing models were used to estimate fair values of interest rate swap agreements.

Fair Value Hedges. In March 2004, Panhandle Energy entered into interest rate swaps to hedge the risk associated with the fair value of its $200,000,000 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under FASB Standard, 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% 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, 2004 and June 30, 2004, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $3,936,000 and $4,960,000, respectively.

Trading and Non-Hedging Activities. During the year ended 2004, the Company acquired natural gas commodity swap derivatives and collar transactions in order 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, 2004 and June 30, 2004, the fair values of the contracts, which expire at various times through March 2005, are included in the Consolidated Balance Sheet as assets and matching adjustments to deferred cost of gas of $2,597,000 and $1,337,000, respectively.

XII Preferred Securities

On May 17, 1995, Southern Union Financing I (Subsidiary Trust), a consolidated wholly-owned subsidiary of Southern Union, issued $100,000,000 of 9.48% Trust Originated Preferred Securities (Preferred Securities). In con-nection with the Subsidiary Trust’s issuance of the Preferred Securities and the related purchase by Southern Union of all of the Sub-sidiary Trust’s common securities, Southern Union issued to the Subsidiary Trust $103,092,800 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, the Company called the Subordinated Notes 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 $230,000,000 offering of preferred stock by the Company on October 8, 2003, as further described below.

XIII Debt and Capital Leases

	December 31,		June 30,
	2004		2004		2003
Southern Union Company
7.60% Senior Notes due 2024	$	359,765	$	359,765	$	359,765
8.25% Senior Notes due 2029		300,000		300,000		300,000
2.75% Senior Notes due 2006		125,000		125,000		125,000
Term Note due 2005		76,087		111,087		211,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029		112,421		113,435		115,884
7.70% debentures, due 2027		--		--		6,756
Capital lease and other, due 2004 to 2007		117		277		9,179
		973,390		1,009,564		1,127,671

Panhandle Energy
2.75% Senior Notes due 2007		200,000		200,000		--
4.80% Senior Notes due 2008		300,000		300,000		--
6.05% Senior Notes due 2013		250,000		250,000		--
6.125% Senior Notes due 2004		--		--		292,500
7.875% Senior Notes due 2004		--		52,455		100,000
6.50% Senior Notes due 2009		60,623		60,623		158,980
8.25% Senior Notes due 2010		40,500		40,500		60,000
7.00% Senior Notes due 2029		66,305		66,305		135,890
Term Loan due 2007		258,433		263,926		275,358
7.95% Debentures due 2023		--		--		76,500
7.20% Debentures due 2024		--		--		58,000
Net premiums on long-term debt		14,688		16,199		61,506
		1,190,549		1,250,008		1,218,734

Total consolidated debt and capital lease		2,163,939		2,259,572		2,346,405
Less current portion		89,650		99,997		734,752
Less fair value swaps of Panhandle Energy		3,936		4,960		--
Total consolidated long-term debt and capital lease	$	2,070,353	$	2,154,615	$	1,611,653

The Company has $2,163,939,000 of long-term debt recorded at December 31, 2004, of which $89,650,000 is current. Debt of $1,819,310,000, including net premiums of $14,688,000 and unamortized interest rate swaps of $3,936,000, is at fixed rates ranging from 2.75% to 10.25%, and the Company also has floating rate debt, including notes payable, totaling $1,039,693,000 bearing an average interest rate of 3.33% as of December 31, 2004. The variable rate bank loans are unsecured with the exception of the $258,433,000 Panhandle Energy Term Loan that is fully collateralized by the Trunkline LNG facilities.

The maturities of long-term debt and capital lease payments for each of the next five years ending December 31 are: 2005 -- $89,650,000; 2006 -- $139,867,000; 2007 -- $433,564,000; 2008 -- $301,646,000; 2009 -- $61,998,000 and thereafter $1,122,527,000.

Each note, debenture or bond above is an obligation of Southern Union Company or a unit of Panhandle Energy, as noted above. The Panhandle Energy Term Loan due 2007 is debt related to Panhandle’s Trunkline LNG Holdings subsidiary, and is non-recourse to other units of Panhandle Energy or Southern Union Company. The remainder of Panhandle Energy’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union Company are direct obligations of Southern Union Company, 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 its 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 its 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.

The 8.25% Notes and the 7.60% Senior Notes traded at $1,215 and $1,130 (per $1,000 note), respectively on, December 31, 2004 as quoted by a major brokerage firm. The carrying amount of long-term debt at December 31, 2004, June 30, 2004 and June 30, 2003 was $2,163,939,000, $2,259,572,000 and $2,346,405,000, respectively. The fair value of long-term debt at December 31, 2004, June 30, 2004 and June 30, 2003 was $2,242,158,000, $2,336,292,000 and $2,408,532,000, respectively.

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.

Term Note. On July 16, 2002, the Company issued a $311,087,000 Term Note dated July 15, 2002 (the 2002 Term Note). The 2002 Term Note carries a variable interest rate that is tied to either the LIBOR or prime interest rates at the Company’s option. The interest rate spread over the LIBOR is currently LIBOR plus 105 basis points. As of December 31, 2004, a balance of $76,087,000 was outstanding on the 2002 Term Note at an effective interest rate of 3.52%. The 2002 Term Note requires semi-annual principal repayments on February 15^th and August 15^th of each year, with a payment of $35,000,000 being due August 15, 2005 and the remaining principal amount of $41,087,000 is due August 26, 2005. The Company expects to repay the balance of the 2002 Term Note with borrowings under the Long-Term Credit Facility. No additional draws can be made on the 2002 Term Note.

Additional Debt. In connection with the Panhandle Energy acquisition, the Company added a principal amount $1,157,228,000 in debt, which had a fair value of $1,207,617,000 as of the June 11, 2003 acquisition date. The debt included senior notes and debentures with interest rates ranging from 6.125% to 8.25% and floating rate debt totaling $275,358,000, all of which is non-recourse to Southern Union.

Panhandle Refinancing. In July 2003, Panhandle Energy announced a tender offer for any and all of the $747,370,000 outstanding principal amount of five of its series of senior notes outstanding at that point in time (the Panhandle Tender Offer) and also called for redemption all of the outstanding $134,500,000 principal amount of its two series of debentures that were outstanding (the Panhandle Calls). Panhandle Energy repurchased approximately $378,257,000 of the principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396,445,000 plus accrued interest through the purchase date. Panhandle Energy also redeemed approximately $134,500,000 of debentures through the Panhandle Calls for total consideration of $139,411,000, 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 $6,354,000 during the year ended June 30, 2004. In August 2003, Panhandle Energy issued $300,000,000 of its 4.80% Senior Notes due 2008 and $250,000,000 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 $3,150,000 principal amount of its senior notes on the open market through two transactions for total consideration of $3,398,000, plus accrued interest through the repurchase date.

Capital Lease. The Company completed the installation of an Automated Meter Reading (AMR) system at Missouri Gas Energy during the quarter ended September 30, 1998. The installation of the AMR system involved an investment of approxi-mately $30,000,000, which is accounted for as a capital lease obligation. As of December 31, 2004, June 30, 2004 and June 30, 2003, the capital lease obligation outstanding was nil, nil and $8,793,000, respectively. This system has significantly improved meter reading accuracy and timeliness and provided electronic accessibility to meters in residential customers’ basements, thereby assisting in the reduction of the number of estimated bills. Depreciation on the AMR system is provided at an average straight-line rate of approximately 5% per annum of the cost of such property.

Notes Payable. On May 28, 2004, the Company entered into a new five-year long-term credit facility in the amount of $400,000,000 (the Long-Term Facility) that matures on May 29, 2009. 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 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 (the Senior Notes). As of December 31, 2004, the commitment fees were an annualized 0.15%. A balance of $292,000,000, $21,000,000 and $251,500,000 was outstanding under the Company’s credit facilities at an effective interest rate of 3.20%, 2.64%, and 1.98% at December 31, 2004, June 30, 2004 and June 30, 2003, respectively. As of February 28, 2005, there was a balance of $220,000,000 outstanding under the Long-Term Facility.

Bridge Loan. On November 17, 2004, an indirect, wholly-owned subsidiary of the Company entered into a $407,000,000 Bridge Loan Agreement (the 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%. The effective interest rate under the Bridge Loan agreement during the period was 3.50%. The Bridge Loan was repaid in February 2005, with 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.

XIV Employee Benefits

Pension and Other Post-Retirement Benefits. The Company maintains eight trusteed non-contributory defined benefit retirement plans (Plans) which cover substantially all employees, except Panhandle Energy employees (see Panhandle Energy, below). The Company funds the Plans’ cost 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 has two supplemental non-contributory retirement plans for certain executive employees and other post-retirement benefit plans for its employees.

Due to the change in year end to December 31, 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, 2003 and 2002.

Post-retirement 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 retirement and other post-retirement benefit plans at December 31, 2004, June 30, 2004 and June 30, 2003.

Pension Benefits Post-Retirement Benefits

	December 31,			June 30,						December 31,			June 30,
	2004			2004			2003			2004			2004			2003
Change in Benefit Obligation:
Benefit obligation at beginning of period	$	386,493		$	350,860		$	317,012		$	152,425		$	90,344		$	76,596
Service cost		3,689			6,533			5,655			2,091			3,993			1,177
Interest Cost		11,412			22,591			22,899			4,607			8,739			5,579
Benefits paid		(10,217	)		(20,649	)		(20,046	)		(3,346	)		(6,263	)		(6,676	)
Actuarial loss		9,095			21,796			26,350			14,484			7,687			13,357
Acquisition		--			--			--			--			42,752			--
Plan amendments		446			7,703			1,095			(1,308	)		5,173			311
Settlement recognition		(2,402	)		(2,341	)		(2,105	)		--			--			--
Benefit obligation at end of period	$	398,516		$	386,493		$	350,860		$	168,953		$	152,425		$	90,344

Change in Plan Assets:
Fair value of plan assets at beginning of period	$	276,154		$	237,376		$	284,911		$	34,004		$	21,332		$	22,408
Return on plan assets		1,980			55,725			(30,900	)		160			3,211			27
Employer contributions		11,320			6,043			5,516			7,144			15,724			5,572
Benefits paid		(10,217	)		(20,649	)		(20,046	)		(3,346	)		(6,263	)		(6,675	)
Settlement recognition		(2,402	)		(2,341	)		(2,105	)		--			--			--
Fair value of plan assets at end of period	$	276,835		$	276,154		$	237,376		$	37,962		$	34,004		$	21,332

Funded Status:
Funded status at end of period	$	(121,680	)	$	(110,339	)	$	(113,484	)	$	(130,991	)	$	(118,421	)	$	(69,012	)
Unrecognized net actuarial loss		130,164			114,344			134,752			41,017			25,972			20,343
Unrecognized prior service cost		13,439			13,737			7,179			3,409			5,038			130
Prepaid/ (accrued) at measurement date		21,923			17,742			28,447			(86,565	)		(87,411	)		(48,539	)
Contributions subsequent to
measurement date		1,044			3,750			4,534			1,815			2,151			4,675
Net asset (liability) recognized at
end of period	$	22,967		$	21,492		$	32,981		$	(84,750	)	$	(85,260	)	$	(43,864	)

Amounts recognized in the Consolidated Balance Sheet:
Prepaid benefit cost	$	28,705		$	28,172		$	27,597		$	--		$	--		$	--
Accrued benefit liability		(101,487	)		(87,448	)		(89,366	)		(84,750	)		(85,260	)		(43,864	)
Intangible asset		10,923			10,366			3,671			--			--			-
Accumulated other comprehensive loss		84,826			70,402			91,079			--			--			-
Net asset (liability) recognized	$	22,967		$	21,492		$	32,981		$	(84,750	)	$	(85,260	)	$	(43,864	)

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were $365,101,000, $332,329,000, and $229,799,000, respectively, as of December 31, 2004; were $355,095,000, $319,902,000, and $228,704,000, respectively, as of June 30, 2004; and were $323,116,000, $291,811,000, and $197,911,000, respectively, as of June 30, 2003.

The accumulated post-retirement benefit obligation and fair value of plan assets for post-retirement benefit plans with accumulated post-retirement benefit obligations in excess of fair value of plan assets were $168,953,000 and $37,962,000, respectively, as of December 31, 2004; were $152,425,000 and $34,004,000, respectively, as of June 30, 2004; and were $90,344,000 and $21,332,000, respectively, as of June 30, 2003.

The minimum pension liability as of December 31, 2004 increased by $14,424,000 primarily as a result of the decrease in the discount rate, an increase in benefits earned and lower than assumed investment returns. The minimum pension liability as of June 30, 2004 decreased by $20,677,000 due primarily to an increase in the fair value of plan assets attributable to higher than expected investment return. The minimum pension liability as of June 30, 2003 increased by $75,008,000 as a result of the decrease in the discount rate in 2003, decreases in the fair value of plan assets due to volatility in the stock markets and increases in liabilities due to early retirement programs.

The weighted-average assumptions used to determine benefit obligations for the six months ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002 were:

	Pension Benefits													Post-retirement Benefits
Six Months													Six Months
Ended													Ended
December 31,				Year Ended June 30,									December 31,				Years Ended June 30,
	2004			2004			2003			2002				2004			2004			2003			2002
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	%
Rate of compensation increase (average)		3.40	%		3.60	%		4.00	%		5.00	%			N/A			N/A			N/A			N/A
Health care cost trend rate		N/A			N/A			N/A			N/A				13.00	%		13.00	%		13.00	%		12.00	%

The assumed health care cost trend rate used in measuring the accumulated post-retirement benefit obligation was 13% during the six months ended December 31, 2004 and the year ended June 30, 2004. This rate was assumed to decrease gradually each year to a rate of 4.75% in 2012 and remain at that level thereafter. The assumed health care cost trend rate used in measuring the accumulated post-retirement benefit obligation was 13% during the year ended June 30, 2003. This rate was assumed to decrease gradually each year to a rate of 5% in 2011 and remain at that level thereafter.

Net periodic benefit cost for the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 and 2002 includes the following components:

	Pension Benefits												Post-retirement Benefits
	Six Months												Six Months
	Ended												Ended
	December 31,			Year Ended June 30,									December31,			Year Ended June 30,
	2004			2004			2003			2002			2004			2004			2003			2002

Service Cost	$	3,689		$	6,533		$	5,655		$	5,707		$	2,091		$	3,993		$	1,177		$	1,136
Interest Cost		11,412			22,591			22,899			22,570			4,607			8,739			5,579			5,362
Expected return on plan assets		(12,302	)		(21,477	)		(24,749	)		(25,868	)		(1,100	)		(1,640	)		(1,734	)		(1,701	)
Amortization of prior service cost		744			1,145			790			984			321			266			(65	)		(100	)
Recognized actuarial (gain) loss		3,982			8,402			2,433			194			379			485			(234	)		(737	)
Curtailment recognition		--			--			--			8,905			--			--			--			1,200
Special termination benefits charge		--			--			--			8,957			--			--			--			1,309
Settlement recognition		(386	)		(445	)		(558	)		(457	)		--			--			--			--
Net periodic benefit cost	$	7,139		$	16,749		$	6,470		$	20,992		$	6,298		$	11,843		$	4,723		$	6,469

Curtailment and special termination benefit charges were recognized during the year ended June 30, 2002 in connection with the Company’s corporate reorganization and restructuring initiatives. The Company has deferred, as a regulatory asset, certain of these charges that have historically been recoverable in rates.

Amortization of unrecognized actuarial gains and losses for Missouri Gas Energy plans were recognized using a rolling five-year average gain or loss position with a five-year amortization period pursuant to a stipulation agreement with the Missouri Public Service Commission (MPSC). The Company has deferred, as a regulatory asset, the difference in amortization of unrecognized actuarial losses recognized under such method and that amount determined and reported as net periodic pension cost in accordance with the applicable FASB Standards.

The weighted-average assumptions used to determine net periodic benefit cost for the six months ended December 31, 2004 and the years ended June 30, 2004, 2003 and 2002 were:

	Pension Benefits													Post-retirement Benefits
Six Months													Six Months
Ended													Ended
December 31,				Year ended June 30,									December 31,				Year ended June 30,
	2004			2004			2003			2002				2004			2004			2003			2002
Discount rate:
Beginning of year		6.50	%		7.50	%		7.50	%		8.00	%			6.50	%		7.50	%		7.50	%		7.50	%
End of year		6.00	%		6.50	%		7.50	%		7.50	%			6.00	%		6.50	%		7.50	%		7.50	%
Expected return on assets - exempt accounts
tax exempt accounts		9.00	%		9.00	%		9.00	%		9.00	%			7.00	%		7.00	%		9.00	%		9.00	%
Expected return on assets -
taxable accounts		N/A			N/A			N/A			N/A				5.00	%		5.00	%		5.50	%		5.40	%
Rate of compensation increase (average)		3.60	%		4.00	%		5.00	%		5.00	%			N/A			N/A			N/A			N/A
Health care cost trend rate		N/A			N/A			N/A			N/A				13.00	%		13.00	%		12.00	%		12.00	%

The Company 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 assumed health care cost trend rate used in determining the net periodic benefit cost for the six months ended December 31, 2004 was 13%. This rate was assumed to decrease gradually each year to a rate of 4.75% in 2012 and remain at that level thereafter. The assumed health care cost trend rate used in determining the net periodic benefit cost for the year ended June 30, 2004 was 13%. This rate was assumed to decrease gradually each year to a rate of 5% in 2011 and remain at that level thereafter. The assumed health care cost trend rate used in determining the net periodic benefit cost for the year ended June 30, 2003 was 12%. This rate was assumed to decrease gradually each year to a rate of 6% in 2006 and remain at that level thereafter. The assumed health care cost trend rate used in determining the net periodic benefit cost for the year ended June 30, 2002 was 10%. This rate was assumed to decrease gradually each year to a rate of 6% in 2006 and remain at that level thereafter.

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

	One Percentage Point Increase in Health Care Trend Rate	One Percentage Point Decrease in Health Care Trend Rate
Effect on total service and interest cost components	$ 1,858	$ (1,489)
Effect on post-retirement benefit obligation	$ 18,111	$ (14,622)

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

The broad goal and objective of the Plan assets is to ensure that future growth of the Plan 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 Plan to meet the Plan’s 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.

Post-retirement Health and Life Plans’ Asset Information. The Post-retirement Health and Life Plans’ assets shall be 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 Plan. 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.

The Company’s weighted average asset allocation at December 31, 2004, June 30, 2004, and June 30, 2003, by asset category is as follows:

	Pension									Post-Retirement
	December 31,			June 30,						December 31,			June 30,
	2004			2004			2003			2004			2004			2003
Asset Category

Equity securities		66	%		68	%		51	%		18	%		21	%		26	%
Debt securities		28	%		26	%		45	%		47	%		50	%		64	%
Other- cash equivalents		6	%		6	%		4	%		35	%		29	%		10	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Equity securities include Company common stock in the amounts of $19,846,000, $16,615,000 and $12,716,000 at December 31, 2004, June 30, 2004, and June 30, 2003, respectively.

Based on the Pension Plan objectives, asset allocations are maintained as follows: equity of 50% to 80%, fixed income of 20% to 50%, and cash and cash equivalents of 0% to 10%.

Based on the Post-Retirement Benefit Plan objectives, asset allocations are maintained as follows: equity of 25% to 35%, fixed income of 65% to 75%, and cash and cash equivalents of 0% to 10%.

The Company expects to contribute between the estimated amounts of $12,000,000 and $17,000,000 to its pension plans and the estimated amount of $14,000,000 to its other post-retirement benefit plans in 2005.

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

	Pension Benefits		Post-Retirement Benefits
2005	$	24,426	$	7,150
2006		21,921		7,517
2007		22,825		7,327
2008		22,966		7,787
2009		24,180		8,416
Years 2010- 2014		129,777		54,817

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 the Pennsylvania Operations; (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. On December 31, 1998, the Plan covering (i) above, exclusive of Missouri Gas Energy’s union employees, was converted from the traditional defined benefit Plan with benefits based on years of service and final average compensation to a cash balance defined benefit plan in which an account is maintained for each employee.

The initial value of the account was determined as the actuarial present value (as defined in the Plan) of the benefit accrued at transition (December 31, 1998) under the pre-existing traditional defined benefit plan. Future contribution credits to the accounts are based on a percentage of future compensation, which varies by individual. Interest credits to the accounts are based on 30-year Treasury Securities rates.

Recently Enacted Legislation. The Medicare Prescription Drug Improvement and Modernization Act of 2003 (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 to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

In accordance with Financial Staff Position (FSP) FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which supersedes FSP FAS 106-1, the measures of the benefit obligation and net periodic post-retirement cost in this Transition Report on Form 10-K do not reflect any amounts associated with potential tax subsidies under the Medicare Prescription Drug Act because the Company has not yet concluded whether benefits provided by the plan are actuarially equivalent to Medicare Part D under the Medicare Prescription Drug Act.

The method of determining whether a sponsor’s plan will qualify for actuarial equivalency was published January 21, 2005 by the Center for Medicare and Medical Services. Once the determination of actuarial equivalence for current and future years is complete, if eligible, the Company will account for the subsidy as an actuarial gain, pursuant to the guidelines of FSP 106-2.

Defined Contribution Plan. The Company provides a Savings Plan available to all employees. For Missouri Gas Energy non-union and corporate employees, the Company contributes 50% and 75% of the first 5% and second 5%, respectively, of the participant’s compensation paid into the Savings Plan. For Missouri Gas Energy union employees, the Company contributes 50% of the first 7% of the participant’s compensation paid into the Savings Plan. In Pennsylvania, the Company contributes 55% of the first 4% of the participant's compensation paid into the Savings Plan. For New England Gas Company’s Fall River operations, the Company contributes 100% of the first 4% of non-union employee compensation paid into the Savings Plan and 100% of the first 3% of union employee compensation paid into the Savings Plan. For New England Gas Company’s Providence operations, the Company contributes 50% of the first 10% 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% of the first 4% of the participant's compensation paid into the Savings Plan. Company con-tributions are 100% 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% vested after six years of continuous service. Company contribu-tions to the plan during the six months ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002 were $2,400,000, $4,058,000, $2,251,000 and $2,722,000, respectively.

Effective January 1, 1999, the Company amended its defined contribution plan to provide contributions for certain employees who were employed as of December 31, 1998. These contributions were designed to replace certain bene-fits previously provided under defined benefit plans. Employer contributions to these separate accounts, re-ferred 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% to 8.5%. Company contributions to Retirement Power Accounts during the six months ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002 were $2,904,000, $5,149,000, $1,469,000 and $826,000 respectively.

Panhandle Energy. Following the 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 4% to 6% of the participating employee’s salary based on the participating employee’s age and years of service. The adoption of the OPEB plan resulted in the recording of a $42,752,000 liability as of June 12, 2003 and Panhandle Energy continues to fund the plan at approximately $7,800,000 per year. Since Panhandle Energy 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.

Corporate Restructuring. Business reorganization and restructuring initiatives were commenced in August 2001 as part of a previously announced cash flow improvement plan. Actions taken included (i) the offering of voluntary Early Retirement Programs (ERPs) in certain of its operating divisions and (ii) a limited reduction in force (RIF) within its corporate offices. ERPs, providing for increased benefits for those electing retirement, were offered to approxi-mately 325 eligible employees across the Company's operating divisions, with approximately 59% of such eligible employees accepting. The RIF was limited solely to certain corporate employees in the Company's Austin and Kansas City offices where forty-eight employees were offered severance packages. In connection with the corporate reorganization and restructuring efforts, the Company recorded a charge of $30,553,000 during the quarter ended September 30, 2001. This charge was reduced by $1,394,000 during the quarter ended June 30, 2002, as a result of the Company’s ability to negotiate more favorable terms on certain of its restructuring liabilities. The charge included: $16,400,000 of voluntary and accepted ERP's, primarily through enhanced benefit plan obligations, and other employee benefit plan obligations; $6,800,000 of RIF within the corporate offices and related employee separation benefits; and $6,000,000 connected with various business realignment and restructuring initiatives. All restructuring actions were completed as of June 30, 2002.

Common Stock Held in Trust. From time to time, the Company purchases outstanding shares of common stock of Southern Union to fund certain Company employee stock-based compensation plans. At December 31, 2004, June 30, 2004 and June 30, 2003, 1,198,034, 1,089,147 and 1,114,738 shares, respectively, of common stock were held by various rabbi trusts for certain of those Company’s benefit plans. At December 31, 2004, 110,996 shares were held in a rabbi trust for certain employees who deferred receipt of Company shares for stock options exercised.

XV Taxes on Income

	Six Months
	Ended
	December 31,		Year Ended June 30,
	2004		2004		2003			2002

Income Tax Expense:
Current:
Federal	$	1,761	$	1,497	$	(15,258	)	$	(8,848	)
State		84		151		(6,563	)		(1,391	)
		1,845		1,648		(21,821	)		(10,239	)
Deferred:
Federal		10,953		60,380		38,926			13,050
State		1,129		7,075		7,168			600
		12,082		67,455		46,094			13,650
Total income tax expense from
continuing operations	$	13,927	$	69,103	$	24,273		$	3,411

Deferred credits in the accompanying Consolidated Balance Sheet include $5,157,000, $5,367,000 and $5,791,000 of unamortized deferred investment tax credit as of December 31, 2004, June 30, 2004 and June 30, 2003, respectively.

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,			June 30,
	2004			2004			2003
Deferred income tax assets:
Alternative minimum tax credit	$	24,352		$	24,054		$	6,263
Insurance accruals		2,268			1,601			2,028
Bad debt reserves		4,866			5,721			4,096
Post-retirement benefits		17,326			1,346			1,078
Minimum pension liability		39,909			33,511			35,159
NOL carry-forward		12,434			--			--
Unconsolidated investments		11,942			--			--
Other		58,419			8,442			10,313
Total deferred income tax assets		171,516			74,675			58,937
Valuation allowance		(11,942	)		--			--
Net deferred income tax assets	$	159,574		$	74,675		$	58,937

Deferred income tax liabilities:
Property, plant and equipment	$	(427,380	)	$	(313,387	)	$	(261,100	)
Unamortized debt expense		(5,991	)		(21,607	)		(5,455	)
Regulatory liability		(15,358	)		(13,151	)		(14,483	)
Other		(48,341	)		(55,831	)		(56,510	)
Total deferred income tax liabilities		(497,070	)		(403,976	)		(337,548	)
Net deferred income tax liability		(337,496	)		(329,301	)		(278,611	)
Less current income tax assets		27,998			19,659			4,096
Accumulated deferred income taxes	$	(365,494	)	$	(348,960	)	$	(282,707	)

The Company has a Federal Net Operating Loss (NOL) carryforward for the short tax year ended December 31, 2004. The NOL of $35,247,000 can be carried forward to offset future taxable income for twenty years.

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 $11,942,000 at December 31, 2004. The Company has also recorded an offsetting valuation allowance of $11,942,000.

	Six Months
	Ended
	December 31,			Year Ended June 30,
	2004			2004			2003			2002

Computed statutory income tax expense from continuing
operations at 35%	$	10,044		$	64,095		$	23,780		$	1,726
Changes in income taxes resulting from:
Valuation allowance		11,942			--			--			--
Dividend received deduction		(9,800	)		--			--			--
State income taxes, net of federal income tax benefit		788			4,697			326			695
Amortization/write-down of goodwill		--			--			--			3,113
Internal Revenue Service audit settlement		--			--			--			(1,570	)
Investment Tax Credit amortization		(210	)		(424	)		(421	)		(608	)
Other		1,163			735			588			55
Actual income tax expense from continuing operations	$	13,927		$	69,103		$	24,273		$	3,411

Southern Union is in the process of completing an income tax project previously initiated to assess the timing and amount of temporary differences that may have accumulated over the years. The Company believes that this study will be completed in the second quarter of 2005. The analysis required in completing this project may identify deferred income tax assets or liabilities that should be reversed to decrease or increase income tax expense, respectively. Management does not believe that the effect of such reversals will have a material effect on the Company’s results of operations.

XVI Regulation and Rates

Missouri Gas Energy. On September 21, 2004, the Missouri Public Service Commission issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22,370,000, effective October 2, 2004. The rate order, based on a 10.5% return on equity, also produced an improved rate design that should help stabilize revenue streams and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between customers and the Company.

New England Gas Company. On May 22, 2003, the 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 $5,277,000. 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 twelve-month period starting July 1, 2003.

Panhandle Energy. In December 2002, FERC approved a Trunkline LNG certificate application to expand the Lake Charles facility to approximately 1.2 Bcf per day of sustainable send out capacity versus the current sustainable send out capacity of .63 Bcf per day and 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 totaling $137,000,000, plus capitalized interest, by the end of 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 $77,000,000, plus capitalized interest, and would increase the LNG terminal 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 this facility. Approximately $127,000,000 of costs are included in the line item Construction Work In Progress for the expansion projects through December 31, 2004.

XVII 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: 2005—$18,872,000; 2006—$18,397,000; 2007—$13,754,000; 2008—$8,340,000 2009--$4,196,000 and thereafter $6,935,000. Rental expense was $9,456,000, $17,821,000, $4,342,000, and $5,759,000 for the six month ended December 31, 2004, and the years ended June 30, 2004, 2003 and 2002, respectively.

XVIII Commitments and Contingencies

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 and assure compliance with regulatory policies and procedures.

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

In certain of the Company’s jurisdictions the Company is allowed to recover environmental remediation expenditures through rates. 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.

Local Distribution Company Environmental Matters.

The Company is investigating the possibility that the Company or predecessor companies may have been associated with Manufactured Gas Plant (MGP) sites in its former gas distribution service territories, principally in Texas, Arizona and New Mexico, and present gas distribution service territories in Missouri, Pennsylvania, Massachusetts and Rhode Island. At the present time, the Company is aware of certain MGP sites in these areas and is investigating those and certain other locations. To the extent that potential costs associated with former MGPs are quantified, the Company expects to provide any appropriate accruals and seek recovery for such remediation costs through all appropriate means, including in rates charged to gas distribution customers, insurance and regulatory relief. At the time of the closing of the acquisition of the Company's Missouri service territories, the Company entered into an Environmental Liability Agreement that provides that Western Resources retains financial responsibility for certain liabilities under environmental laws that may exist or arise with respect to Missouri Gas Energy. In addition, the New England Division has reached agreement with its Rhode Island rate regulators on a regulatory plan that creates a mechanism for the recovery of environmental costs over a ten-year period. This plan, effective July 1, 2002, establishes an environmental fund for the recovery of evaluation, remedial and clean-up costs arising out of the Company's MGPs and sites associated with the operation and disposal activities from MGPs. Similarly, environmental costs associated with Massachusetts’ facilities are recoverable in rates over a seven-year period.

Missouri Gas Energy (MGE).

Kansas City, Missouri Site - In a letter dated May 10, 1999, the Missouri Department of Natural Resources (MDNR) sent notice of a planned Site Inspection/Removal Site Evaluation of the Kansas City Coal Gas former MGP site. This site (comprised of two adjacent MGP operations previously owned by two separate companies and hereafter referred to as Station A and Station B) is located at East 1^st Street and Campbell in Kansas City, Missouri and is owned by MGE. During July 1999, the Company entered the two sites into MDNR’s Voluntary Cleanup Program (VCP) and, subsequently, performed environmental assessments of the sites. Following the submission of these assessments to MDNR, MGE was required by MDNR to initiate remediation of Station A. Following the selection of a qualified contractor in a competitive bidding process, the Company began remediation of Station A in the first calendar quarter of 2003. The project was completed in July 2003, at an approximate cost of $4,000,000. MDNR issued a conditional No Further Action letter for Station A-South on July 22, 2004. However, MDNR may require additional investigation and possible remediation on Station A-North and on the railroad right-of-way adjacent to Station A. MDNR has also stated that some remedial actions may be necessary on Station B to remove tar material found during the 1999 site investigation.

St. Joseph, Missouri Site - Following a failed tank tightness test, MGE removed an underground storage tank (UST) system in December 2002 from a former MGP site in St. Joseph, Missouri. An UST closure report was filed with MDNR on August 12, 2003. In a letter dated September 26, 2003, MDNR indicated that its review of the analytical data submitted for this site indicated that contamination existed at the site above the action levels specified in Missouri guidance documents. In a letter dated January 28, 2004, MDNR indicated that the MDNR would provide MGE a final version of the Missouri Risk-Based Corrective Action (MRBCA) process. On April 28, 2004, MDNR provided MGE with information regarding the MRBCA process, and requested a work plan on the St. Joseph site within 60 days of MGE’s receipt of this information. MGE submitted a UST Site Characterization Work Plan that was approved by MDNR on August 20, 2004. The Site Characterization fieldwork was completed in December 2004 and a report is due to MDNR in March 2005. Part of the cost of the investigation should be recoverable by the Petroleum Storage Tank Insurance Fund.

New England Gas Company (NEGC).

642 Allens Avenue, Providence, Rhode Island Site - - Prior to its acquisition by the Company, Providence Gas performed environmental studies and initiated an environmental remediation project at Providence Gas’ primary gas distribution facility located at 642 Allens Avenue in Providence, Rhode Island. Providence Gas spent more than $13,000,000 on environmental assessment and remediation at this MGP site under the supervision of the Rhode Island Department of Environmental Management (RIDEM). Following the acquisition, environmental remediation at the site was temporarily suspended. During this suspension, the Company requested certain modifications to the 1999 Remedial Action Work Plan from RIDEM. After receiving approval to some of the requested modifications to the 1999 Remedial Action Work Plan, environmental work was reinitiated in April 2002, by a qualified contractor selected in a competitive bidding process. Remediation was completed in October 2002, and a Closure Report was filed with RIDEM in December 2002. The cost of environmental work conducted after remediation resumed was $4,000,000. Remediation of the remaining 37.5 acres of the site (known as the “Phase 2” remediation project) is not scheduled at this time. Until NEGC receives a closure letter from RIDEM, it is unclear what, if any, additional investigation or remediation will be necessary.

170 Allens Avenue, Providence, Rhode Island Site - - In November 1998, Providence Gas received a letter of responsibility from RIDEM relating to possible contamination at a site that operated as a MGP in the early 1900s in Providence, Rhode Island. Subsequent to its use as a MGP, this site was operated for over eighty years as a bulk fuel oil storage yard by a succession of companies including Cargill, Inc. (Cargill). Cargill has also received a letter of responsibility from RIDEM for the site. An investigation has begun to determine the extent of contamination, as well as the extent of the Company’s responsibility. Providence Gas entered into a cost-sharing agreement with Cargill, under which Providence Gas is responsible for approximately twenty percent (20%) of the costs related to the investigation. To date, approximately $300,000 has been spent on environmental assessment work at this site. Until RIDEM provides its final response to the investigation, and the Company knows its ultimate responsibility respective to other potentially responsible parties with respect to the site, the Company cannot offer any conclusions as to its ultimate financial responsibility with respect to the site.

Cory’s Lane, Tiverton, Rhode Island Site - - Fall River Gas Company (acquired in September 2000 by the Company) was a defendant in a civil action seeking to recover anticipated remediation costs associated with contamination found at property owned by the plaintiffs (Cory’s Lane Site) in Tiverton, Rhode Island. This claim was based on alleged dumping of material by Fall River Gas Company trucks at the site in the 1930s and 1940s. In a settlement agreement effective December 3, 2001, the Company agreed to perform all assessment, remediation and monitoring activities at the Cory’s Lane Site sufficient to obtain a final letter of compliance from the RIDEM. Following the performance of a site investigation, NEGC submitted a Site Investigation Report in December 2003 to RIDEM. On April 15, 2004, NEGC obtained verbal approval from RIDEM to conduct additional investigation activity at the site. The results of the investigation are pending completion of the report.

Bay Street, Tiverton, Rhode Island Site - - In a letter dated March 17, 2003, RIDEM sent NEGC 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 NEGC prepare a Site Investigation Work Plan (Work Plan) for submittal to RIDEM by April 10, 2003, and subsequently perform a Site Investigation of the Bay Street Area. Without admitting responsibility or accepting liability, NEGC responded to RIDEM in a letter dated March 19, 2003, and agreed to perform the activities requested by the State within the period specified by RIDEM. After receiving approval from RIDEM on a Work Plan, NEGC began assessment work in June 2003. A Site Inspection Report and a Human Health Risk Assessment were filed with RIDEM in October 2003, and RIDEM provided NEGC’s comments to the inspection report in a letter dated January 27, 2004. The January 27, 2004, RIDEM letter included the comment that additional assessment work was necessary in the Bay Street Area. In July 2004, NEGC submitted a Supplemental Site Investigation Work Plan and Phase 2 Site Investigation Work Plan for the further assessment of the Bay Street Area. In a letter dated August 18, 2004, RIDEM communicated its conditional concurrence of NEGC’s Work Plan. NEGC initiated assessment field work in August 2004. A report detailing the finding of the field work is anticipated to be completed in the spring of 2005. Once the report has been submitted to RIDEM and the neighborhood, all interested stakeholders are expected to provide comments.

In connection with the investigation of the Bay Street Area, two former residents of the area filed a tort action on August 20, 2003, against NEGC alleging personal injury to the plaintiffs. This litigation has not been served on the Company. The Company has also received a demand letter dated July 1, 2004, sent by lawyers on behalf of the owners of a property in the Bay Street Area. This demand in the amount of $4,000,000 alleges property damage and personal injury. Parts of the Bay Street Area appear to have been built on fill placed at various times and include one or more historic dump sites. Research is therefore underway to identify other potentially responsible parties associated with the fill materials and the dumping.

Mt. Hope Street, North Attleboro, Massachusetts Site - In 2003, NEGC conducted a Phase I environmental site assessment at a former MGP site in North Attleboro, Massachusetts (the Mt. Hope Street Site) to determine if the property could be redeveloped as a service center. During the site walk, coal tar was found in the adjacent creek bed, and notice to the Massachusetts Department of Environmental Protection (MADEP) was made. On September 18, 2003, a Phase I Initial Site Investigation Report and Tier Classification were submitted to MADEP. On November 25, 2003, MADEP issued a Notice of Responsibility letter to NEGC. Based upon the Phase I filing, NEGC is required to file a Phase II report with MADEP by September 18, 2005, to complete the site characterization.

66 Fifth Street, Fall River, Massachusetts Site - In a letter dated March 11, 2003, MADEP provided NEGC a Notice of Responsibility for 66 Fifth Street in Fall River, Massachusetts. This Notice of Responsibility requested that site assessment activities be conducted at the former MGP at 66 Fifth Street to determine whether or not there was a release of cyanide into the groundwater at this site that impacted downgradient properties at 60 and 82 Hartwell Street. NEGC submitted an Immediate Response Action (IRA) Work Plan in May 2003. The IRA Report was submitted to MADEP in July 2003. Investigation work performed to date indicates that cyanide concentrations at the down gradient properties are unrelated to the NEGC property at 66 Fifth Street. As required by MADEP, NEGC will submit a Phase II Risk Assessment and Site Closure Report. It is likely that no further action will be necessary on this site.

State Avenue, Fall River, Massachusetts Site - - The Company received a Notice of Responsibility, Request for Information and Request for Immediate Response Action Plan dated July 1, 2004, for an area in Fall River, Massachusetts along State Avenue (State Avenue Area) that is contiguous to the Bay Street Area of Rhode Island. In response to this Notice from the MADEP, the Company submitted an Immediate Response Action Plan (IRAP) to the MADEP on July 26, 2004. The Company’s IRAP proposes an investigation to determine whether or not coal gasification related material was historically dumped in the State Avenue Area.

Valley Resources Sites in Rhode Island and Massachusetts - Valley Gas Company (acquired in September 2000 by the Company), is a party to an action in which Blackstone Valley Electric Company (Blackstone) brought suit for contribution to its expenses of cleanup of a site on Mendon Road in Attleboro, Massachusetts, to which coal gas manufacturing waste was transported from a former MGP site in Pawtucket, Rhode Island (Blackstone Litigation). Blackstone Valley Electric Company v. Stone & Webster, Inc., Stone & Webster Engineering Corporation, Stone & Webster Management Consultants, Inc. and Valley Gas Company, C. A. No. 94-10178JLT, United States District Court, District of Massachusetts. Valley Gas Company takes the position in that litigation that it is indemnified for any cleanup expenses by Blackstone pursuant to a 1961 agreement signed at the time of Valley Gas Company’s creation. This suit was stayed in 1995 pending the issuance of rulemaking at the United States Environmental Protection Agency (EPA) (Commonwealth of Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). The requested rulemaking concerned the question of whether or not ferric ferrocyanide (FFC) is among the “cyanides” listed as toxic substances under the Clean Water Act and, therefore, is a “hazardous substance” under the Comprehensive Environmental Response, Compensation and Liability Act. On October 6, 2003, the EPA issued a Final Administrative Determination declaring that FFC is one of the “cyanides” under the environmental statutes. While the Blackstone Litigation was stayed, Valley Gas Company and Blackstone (merged in May 2000 with Narragansett Electric Company, a subsidiary of National Grid) have received letters of responsibility from the RIDEM with respect to releases from two MGP sites in Rhode Island. RIDEM issued letters of responsibility to Valley Gas Company and Blackstone in September 1995 for the Tidewater MGP in Pawtucket, Rhode Island, and in February 1997 for the Hamlet Avenue MGP in Woonsocket, Rhode Island. Valley Gas Company entered into an agreement with Blackstone (now Narragansett) in which Valley Gas Company and Blackstone agreed to share equally the expenses for the costs associated with the Tidewater site subject to reallocation upon final determination of the legal issues that exist between the companies with respect to responsibility for expenses for the Tidewater site and otherwise. No such agreement has been reached with respect to the Hamlet site.

While the Blackstone Litigation has been stayed, National Grid and the Company have jointly pursued claims against the bankrupt Stone & Webster entities (Stone & Webster) based upon Stone & Webster’s historic management of MGP facilities on behalf of the alleged predecessors of both companies. On January 9, 2004, the U.S. Bankruptcy Court for the District of Delaware issued an order approving a settlement between National Grid, the Company and Stone & Webster that provided for the payment of $5,000,000 out of the bankruptcy estates. This settlement resulted in a payment of $1,250,000 to the Company for payment of environmental costs associated with the former Fall River Gas Company, and a $3,750,000 payment to the Company and National Grid jointly for future environmental costs at the Tidewater and Hamlet sites. The settlement further provides an admission of liability by Stone & Webster that gives National Grid and the Company additional rights against historic Stone & Webster insurers.

In August and September of 2003, representatives of National Grid, parent company of Narragansett Electric Company, and representatives of the Company conducted meetings to discuss the possibility of a negotiated settlement between the two companies. Settlement discussions are ongoing.

Mercury Release - The Company has completed an investigation of a recent incident involving the release of mercury stored in a NEGC facility in Pawtucket, Rhode Island. On October 19, 2004, New England Gas Company discovered that a NEGC facility had been broken into and that mercury had been spilled both inside a building and in the immediate vicinity. Mercury had also been removed from the Pawtucket facility and a quantity had been spilled in a parking lot in the neighborhood. Mercury from the parking lot spill was apparently tracked into some nearby apartment units, as well as some other buildings. Spill cleanup has been completed at the NEGC property and nearby apartment units. Investigation of some other neighborhood properties has been undertaken, with cleanup necessitated 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, they are conducting inquiries regarding NEGC's compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and hazard communication requirements. NEGC has received a subpoena requesting documents relating to this matter. 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.

PG Energy.

Pennsylvania Sites - - During 2002, PG Energy received inquiries from the Pennsylvania Department of Environmental Protection (PADEP) pertaining to three Pennsylvania former MGP sites located in Scranton, Bloomsburg and Carbondale. At the request of PADEP, PG Energy is currently performing environmental assessment work at the Scranton MGP site. In March 2004, PG Energy filed an Initial Site Assessment Characterization report on the Scranton site and is preparing to submit a Comprehensive Site Assessment Characterization Work Plan for further assessment of this site.

PG Energy has participated financially in PPL Electric Utilities Corporation’s (PPL) environmental and health assessment of an additional MGP site located in Sunbury, Pennsylvania. In May 2003, PPL commenced a remediation project at the Sunbury site that was completed in August 2003. PG Energy has contributed to PPL’s remediation project by making cash payments and by removing and relocating gas utility lines located in the path of the remediation. In a letter dated January 12, 2004, PADEP notified PPL of its approval of the Remedy Certification Report submitted by PPL for the Sunbury MGP cleanup project.

On March 31, 2004, PG Energy entered into a Voluntary Consent Order and Agreement (Multi-Site Agreement) with the PADEP. This Multi-Site Agreement is for the purpose of developing and implementing an environmental assessment and remediation program for five MGP sites (including the Scranton, Bloomsburg, Wilkes-Barre, Nanticoke and Carbondale sites) and six MGP holder sites owned by PG Energy in the State of Pennsylvania. Under the Multi-Site Agreement, PG Energy is to perform environmental assessments of these sites within two years of the effective date of the Multi-Site Agreement. Thereafter, PG Energy is required to perform additional assessment and remediation activity as is deemed to be necessary based upon the results of the initial assessments.

Panhandle Energy Environmental Matters.

Panhandle Energy has previously identified environmental impacts at certain sites on its gas transmission systems and has undertaken cleanup programs at those sites. These impacts resulted from (i) the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in compressed air systems; (ii) the past use of paints containing PCBs; (iii) the prior use of wastewater collection facilities; and (iv) other on-site disposal areas. Panhandle Energy communicated with EPA and appropriate state regulatory agencies on these matters, and has developed and implemented a program to remediate such contamination in accordance with federal, state and local regulations.

As part of the cleanup program resulting from contamination due to the use of lubricants containing PCBs in compressed air systems, Panhandle Eastern Pipe Line and Trunkline have identified PCB levels above acceptable levels inside the auxiliary buildings that house the air compressor equipment at thirty-three compressor station sites. Panhandle Energy has developed and is implementing an EPA-approved process to remediate this PCB contamination in accordance with federal, state and local regulations. Sixteen sites have been decontaminated per the EPA approved process as prescribed in the EPA regulations.

At some locations, PCBs have been identified in paint that was applied many years ago. In accordance with EPA regulations, Panhandle Energy has implemented a program to remediate sites where such issues are identified during painting activities. If PCBs are identified above acceptable levels, the paint is removed and disposed of in an EPA approved manner.

The Illinois Environmental Protection Agency (Illinois EPA) notified Panhandle Eastern Pipe Line and Trunkline, together with other non-affiliated parties, of contamination at three former waste oil disposal sites in Illinois. Panhandle Eastern Pipe Line’s and Trunkline’s estimated share for the costs of assessment and remediation of the sites, based on the volume of waste sent to the facilities, is approximately 17 percent. Panhandle Energy and 21 other non-affiliated parties conducted an initial voluntary investigation of the Pierce Oil Springfield site, one of the three sites. In addition, Illinois EPA has informally indicated that it has referred the Pierce Oil Springfield site to the EPA so that environmental contamination present at the site can be addressed through the federal Superfund program. No formal notice has yet been received from either agency concerning the referral. However, the EPA is expected to issue special notice letters and has begun the process of listing the site on the National Priority List. Panhandle Energy and three of the other non-affiliated parties associated with the Pierce Oil Springfield site met with the EPA and Illinois EPA regarding this issue. Panhandle Energy was given no indication as to when the listing process was to be completed. Panhandle Energy has also received a Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) 104e data request from the US EPA Region V regarding the second Pierce Waste Oil site known as the Dunavan site, located in Oakwood Illinois. Panhandle Energy is working on the response that will show that waste oil generated at Panhandle Energy facilities was shipped to the Dunavan Oil site in Oakwood Illinois, resulting in Panhandle Energy becoming a potentially responsible party at such site.

Based on information available at this time, the Company believes the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.

Air Quality Control.

In 1998, the EPA issued a final rule on regional ozone control that requires Panhandle Energy to place controls on certain large internal combustion engines in five midwestern states. The part of the rule that affects Panhandle Energy was challenged in court by various states, industry and other interests, including Interstate Natural Gas Association of America (INGAA), an industry group to which Panhandle Energy belongs. In March 2000, the court upheld most aspects of the EPA’s rule, but agreed with INGAA’s position and remanded to the EPA the sections of the rule that affected Panhandle Energy. The final rule was promulgated by the EPA in April 2004. The five midwestern states have one year to promulgate state laws and regulations to address the requirements of this rule. Based on an EPA guidance document negotiated with gas industry representatives in 2002, it is believed that Panhandle Energy will be required under state rules to reduce nitrogen oxide (NOx) emissions by 82% on the identified large internal combustion engines and will be able to trade off engines within the company and within each of the five Midwestern states affected by the rule in an effort to create a cost effective NOx reduction solution. The final implementation date is May 2007. The rule impacts 20 large internal combustion engines on the Panhandle Energy system in Illinois and Indiana at an approximate cost of $17,000,000 for capital improvements through 2007, based on current projections.

In 2002, the Texas Commission on Environmental Quality enacted the Houston/Galveston State Implementation Plan (SIP) regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and may require 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 five additional facilities. These two rules affect six Company facilities in Texas at an estimated cost of approximately $12,000,000 for capital improvements through March 2007, based on current projections.

The EPA promulgated various Maximum Achievable Control Technology (MACT) 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 of 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% 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 22 internal combustion engines subject to the rules. It is expected that compliance with these regulations will cost an estimated $5,000,000 for capital improvements, based on current projections.

Regulatory.

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 Southern Union. The trial of Southern Union’s claims against the sole-remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to Southern Union of nearly $400,000 in actual damages and $60,000,000 in punitive damages against former Commissioner Irvin. The District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages. Former Commissioner Irvin has appealed to the Ninth Circuit Court of Appeals. A decision on the appeal by the Ninth Circuit is expected in 2005. The Company intends to vigorously pursue collection of the award. With the exception of ongoing legal fees associated with the collection of damages from former Commissioner Irvin, the Company believes that the results of the above-noted Southwest litigation and any related appeals will not have a material adverse effect on the Company's financial condition, results of operations or cash flows.

Other.

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. Panhandle believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which is filed with and approved by FERC. As a result, Panhandle Energy believes that it has meritorious defenses to the complaint (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 suit vigorously.

Southern Union and its subsidiaries are parties to other legal proceedings that management considers to be normal actions to which an enterprise of its size and nature might be subject, Management does not consider these actions to be material to Southern Union's overall business or financial condition, results of operations or cash flows.

Commitments. At December 31, 2004, 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 $1,527,032,000. 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.

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 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.

Of the Company’s employees represented by unions, Missouri Gas Energy employs 36%, New England Gas Company employs 32%, Panhandle Energy employs 18% and PG Energy employs 14%.

The Company had standby letters of credit outstanding of $8,582,000, $58,566,000 and $7,761,000 at December 31, 2004, June 30, 2004 and June 30, 2003, respectively, which guarantee payment of insurance claims and other various commitments.

The Company has guaranteed a $4,000,000 line of credit between Advent Networks, Inc. (in which Southern Union has an equity interest) and a bank.

XIX Discontinued Operations

Effective January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets to ONEOK for approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance with accounting principles generally accepted in the United States, 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 respective periods.

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		2002
Operating revenues	$	144,490	$	309,936
Net operating revenues, excluding depreciation and amortization (a)	$	51,480	$	105,730
Net earnings from discontinued operations (b)	$	32,520	$	18,104

_________________________________

(a)	Net operating revenues consist of operating revenues less gas purchase costs and revenue-related taxes.

(b)

Net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs, in accordance with generally accepted accounting principles. All outstanding debt of Southern Union Company and subsidiaries is maintained at the corporate level, and no debt was assumed by ONEOK, Inc. in the sale of the Texas Operations.

XX Quarterly Operations (Unaudited)

Six Months Ended	Quarter Ended
December 31, 2004	September 30	December 31	Total
Operating revenues	$ 234,576	$ 559,762	$ 794,338
Net operating revenues, excluding depreciation and amortization	164,649	250,396	415,045
Net earnings (loss) from continuing operations	(7,140)	21,911	14,771
Net earnings (loss) available for common shareholders	(11,481	17,569	6,088
Diluted net earnings (loss) per share available for common shareholders:⁽¹⁾
Continuing operations	(.15)	.20	.07
Available for common shareholders	(.15)	.20	.07

Year Ended	Quarter Ended
June 30, 2004	September 30			December 31		March 31		June 30			Total
Operating revenues	$	231,351		$	507,066	$	774,551	$	286,806		$	1,799,774
Net operating revenues, excluding depreciation and amortization		169,266			240,050		297,864		182,761			889,941
Net earnings (loss) from continuing operations		(3,707	)		38,422		75,367		3,943			114,025
Net earnings (loss) available for common shareholders		(3,707	)		34,418		71,026		(398	)		101,339
Diluted net earnings (loss) per share available for common shareholders:⁽¹⁾
Continuing operations		(.05	)		.45		.91		(.01	)		1.30
Available for common shareholders		(.05	)		.45		.91		(.01	)		1.30

Year Ended	Quarter Ended
June 30, 2003	September 30			December 31		March 31		June 30			Total
Operating revenues	$	99,710		$	346,104	$	535,663	$	207,023		$	1,188,500
Net operating revenues, excluding depreciation and amortization		54,464			118,031		161,400		89,509			423,404
Net earnings (loss) from continuing operations		(9,186	)		18,519		46,234		(11,898	)		43,669
Net earnings (loss) from discontinued operations		2,691			10,900		17,665		1,264			32,520
Net earnings (loss) available for common shareholders		(6,495	)		29,419		63,899		(10,634	)		76,189
Diluted net earnings (loss) per share available for common shareholders:⁽¹⁾
Continuing operations		(.16	)		.30		.75		(.19	)		.70
Discontinued operations		.05			.18		.29		.02			.52
Available for common shareholders		(.11	)		.48		1.04		(.17	)		1.22

(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.

XXI 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 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 Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy.

Revenue included in the All Other category is attributable to several operating subsidiaries of the Company: PEI Power Corporation generates and sells electricity; PG Energy Services Inc. offers appliance service contracts; ProvEnergy Power Company LLC (ProvEnergy Power), which was sold effective October 31, 2003, provided outsourced energy management services and owned 50% 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 provided energy consulting services. None of these businesses have ever met the quantitative thresholds for determining reportable segments individually or in the aggregate. The Company also has corporate operations that do not generate any revenues.

The Company evaluates segment performance based on several factors, of which the primary financial measure is operating income. 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 six months ended December 31, 2004, and the years ended June 30, 2004, 2003 or 2002.

Prior to the acquisition of Panhandle Energy, 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, management assessed the manner in which financial information is reviewed in making operating decisions and assessing performance, and concluded that Panhandle Energy’s operations (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 Southern Union Gas natural gas operating division as discontinued operations. Accordingly, the Distribution segment results exclude the results of the Texas operations for all periods presented.

The following table sets forth certain selected financial information for the Company’s segments for the six months ended December 31, 2004, and for the years ended June 30, 2004, 2003 and 2002. Financial information for the Transportation and Storage segment reflects the operations of Panhandle Energy beginning on its acquisition date of June 11, 2003.

	Six Months
	Ended
	December 31,		Year Ended June 30,
	2004		2004		2003		2002
Revenues from external customers:
Distribution	$	549,346	$	1,304,405	$	1,158,964	$	968,933
Transportation and Storage		242,743		490,883		24,522		--
Total segment operating revenues		792,089		1,795,288		1,183,486		968,933
All Other		2,249		4,486		5,014		11,681
Total consolidated operating revenues	$	794,338	$	1,799,774	$	1,188,500	$	980,614

Depreciation and amortization:
Distribution	$	32,511	$	57,601	$	56,396	$	53,937
Transportation and Storage		30,159		59,988		3,197		--
Total segment depreciation and
amortization		62,670		117,589		59,593		53,937
All Other		306		572		590		2,387
Corporate		400		594		459		2,665
Total consolidated depreciation and
amortization	$	63,376	$	118,755	$	60,642	$	58,989

Operating income:
Distribution	$	19,396		$	118,894		$	142,762		$	135,502
Transportation and Storage		90,121			193,502			9,628			--
Total segment operating income		109,517			312,396			152,390			135,502
All Other		(1,783	)		(3,514	)		13			--
Corporate		(803	)		(3,555	)		(10,039	)		(15,218	)
Business restructuring charges		--			--			--			(29,159	)
Total consolidated operating income	$	106,931		$	305,327		$	142,364		$	91,125

Total assets:
Distribution	$	2,448,750		$	2,231,970		$	2,243,257		$	2,156,106
Transportation and Storage		2,348,354			2,197,289			2,212,467			--
Total segment assets		4,797,104			4,429,259			4,455,724			2,156,106
All Other		40,320			42,133			50,073			53,339
Corporate		730,865			101,066			85,141			75,173
Sale of assets - Texas operations		--			--			--			395,446
Total consolidated assets	$	5,568,289		$	4,572,458		$	4,590,938		$	2,680,064

Expenditures for long-lived assets:
Distribution	$	56,442		$	78,791		$	67,327		$	68,042
Transportation and storage		111,886			131,378			5,128			--
Total segment expenditures for
long-lived assets		168,328			210,169			72,455			68,042
All other		133			856			1,653			1,365
Corporate		9,976			15,028			5,622			1,291
Total consolidated expenditures for Assets
long-lived assets	$	178,437		$	226,053		$	79,730		$	70,698

Reconciliation of operating income to earnings
from continuing operations before income taxes:
Operating income	$	106,931		$	305,327		$	142,364		$	91,125
Interest		(64,898	)		(127,867	)		(83,343	)		(90,992	)
Earnings from unconsolidated
investments		4,745			200			422			1,420
Dividends on preferred securities of
subsidiary trust		--			--			(9,480	)		(9,480	)
Other income, net		(18,080	)		5,468			17,979			12,858
Earnings from continuing operations
before income taxes	$	28,698		$	183,128		$	67,942		$	4,931

XXII Transition Period Comparative Data

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

	December 31,
	2004			2003
	(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 shareholders		6,088			30,711

Net earnings available for common shareholders per share:
Basic	$	.07		$	.41
Diluted	$	.07		$	.40

Weighted average shares outstanding:
Basic		81,995,878			75,337,197
Diluted		85,298,894			77,496,541

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

of Southern Union Company

We were engaged to perform an integrated audit of Southern Union Company’s December 31, 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 in accordance with the standards of the Public Company Accounting Oversight Board (United States). We have audited the Company’s December 31, 2004 and June 30, 2004, 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinion on the consolidated financial statements, based on our audits of those consolidated financial statements, is presented below. However, as explained more fully below, the scope of our work was not sufficient to enable us to express, and we do not express, an opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2004.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of stockholders’ equity and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries at December 31, 2004, June, 30, 2004 and June 30, 2003, and the results of their operations and their cash flows for the six month period ended December 31, 2004 and for each of the three 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 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

The Company has not reported on its assessment of the effectiveness of internal control over financial reporting. Accordingly, the scope of our work was not sufficient to enable us to express, and we do not express, an opinion on the effectiveness of the Company's internal control over financial reporting.

PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2005