**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**





**OR**





**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.
    1ITEM
      2.
    Properties.
    18ITEM
      3.
    Legal
      Proceedings.
    18ITEM
      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.
    19ITEM
      6.
    Selected
      Financial Data.
    21ITEM
      7.
    Management's
      Discussion and Analysis of Results of Operations and Financial
      Condition*.*
    22ITEM
      7A.
    Quantitative
      and Qualitative Disclosures About Market Risk.
    51ITEM
      8.
    Financial
      Statements and Supplementary Data.
    53ITEM
      9.
    Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure.
    53ITEM
      9A.
    Controls
      and Procedures.
    54ITEM
      9B.
    Other
      Information.
    55**PART
      III**ITEM
      10.
    Directors
      and Executive Officers of the Registrant.
    55ITEM
      11.
    Executive
      Compensation.
    55ITEM
      12.
    Security
      Ownership of Certain Beneficial Owners and Management.
    55ITEM
      13.
    Certain
      Relationships and Related Transactions.
    55ITEM
      14.
    Principal
      Accountants Fee and Services.
    55**PART
      IV**ITEM
      15.
    Exhibits,
      Financial Statement Schedules, and Reports on Form 8-K.
    56Signatures.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
    
    1,200,000Carrizo
      Springs Pipeline (c)
    
    December
      2001
    
    1,000,000
    
    561,000South
      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.


(c)  Asset was
a 43-mile pipeline operated by Southern Transmission Company.


(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
    
    
    428,215Commercial
    
    
    
    
    
    61,273
    
    
    61,957
    
    
    60,774
    
    
    58,749Industrial
      and irrigation
    
    
    
    
    
    98
    
    
    95
    
    
    99
    
    
    95Total
      average customers served
    
    
    
    
    
    490,663
    
    
    494,089
    
    
    491,734
    
    
    487,059Transportation
      customers
    
    
    
    
    
    879
    
    
    786
    
    
    461
    
    
    378Total
      average gas sales and transportation customers
    
    
    
    
    
    491,542
    
    
    494,875
    
    
    492,195
    
    
    487,437Gas
      sales in MMcf:Residential
    
    
    
    
    
    10,837
    
    
    36,880
    
    
    39,821
    
    
    35,039Commercial
    
    
    
    
    
    5,082
    
    
    16,026
    
    
    17,399
    
    
    15,686Industrial
      and irrigation
    
    
    
    
    
    152
    
    
    338
    
    
    391
    
    
    417Gas
      sales billed
    
    
    
    
    
    16,071
    
    
    53,244
    
    
    57,611
    
    
    51,142Net
      change in unbilled gas sales
    
    
    
    
    
    3,503
    
    
    112
    
    
    61
    
    
    (16
    )Total
      gas sales
    
    
    
    
    
    19,574
    
    
    53,356
    
    
    57,672
    
    
    51,126Gas
      transported
    
    
    
    
    
    11,721
    
    
    25,761
    
    
    26,893
    
    
    27,324Total
      gas sales and gas transported
    
    
    
    
    
    31,295
    
    
    79,117
    
    
    84,565
    
    
    78,450Gas
      sales revenues (thousands of dollars):Residential
    
    
    
    
    $
    139,086
    
    $
    395,350
    
    $
    337,293
    
    $
    293,544Commercial
    
    
    
    
    
    58,054
    
    
    163,826
    
    
    138,676
    
    
    122,619Industrial
      and irrigation
    
    
    
    
    
    1,923
    
    
    3,943
    
    
    3,930
    
    
    3,841Gas
      revenues billed
    
    
    
    
    
    199,063
    
    
    563,119
    
    
    479,899
    
    
    420,004Net
      change in unbilled gas sales revenues
    
    
    
    
    
    38,124
    
    
    2,024
    
    
    3,434
    
    
    (2,278
    )Total
      gas sales revenues
    
    
    
    
    
    237,187
    
    
    565,143
    
    
    483,333
    
    
    417,726Gas
      transportation revenues
    
    
    
    
    
    4,095
    
    
    8,702
    
    
    8,439
    
    
    8,202Other
      revenues
    
    
    
    
    
    4,261
    
    
    7,013
    
    
    5,017
    
    
    3,199Total
      operating revenues
    
    
    
    
    $
    245,543
    
    $
    580,858
    
    $
    496,789
    
    $
    429,127Weather:Degree
      days (a)
    
    
    
    
    
    1,669
    
    
    4,770
    
    
    5,105
    
    
    4,419Percent
      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
    
    
    141,223Commercial
    
    
    
    
    
    14,469
    
    
    14,384
    
    
    14,141
    
    
    13,707Industrial
      and irrigation
    
    
    
    
    
    115
    
    
    116
    
    
    120
    
    
    104Public
      authorities and other
    
    
    
    
    
    345
    
    
    340
    
    
    337
    
    
    212Total
      average customers served
    
    
    
    
    
    157,081
    
    
    157,262
    
    
    156,367
    
    
    155,246Transportation
      customers
    
    
    
    
    
    586
    
    
    602
    
    
    613
    
    
    624Total
      average gas sales and transportation customers
    
    
    
    
    
    157,667
    
    
    157,864
    
    
    156,980
    
    
    155,870Gas
      sales in MMcf:Residential
    
    
    
    
    
    4,649
    
    
    17,133
    
    
    18,372
    
    
    15,053Commercial
    
    
    
    
    
    2,130
    
    
    6,505
    
    
    6,732
    
    
    5,325Industrial
      and irrigation
    
    
    
    
    
    150
    
    
    379
    
    
    376
    
    
    277Public
      authorities and other
    
    
    
    
    
    99
    
    
    290
    
    
    334
    
    
    145Gas
      sales billed
    
    
    
    
    
    7,028
    
    
    24,307
    
    
    25,814
    
    
    20,800Net
      change in unbilled gas sales
    
    
    
    
    
    1,955
    
    
    34
    
    
    4
    
    
    (22
    )Total
      gas sales
    
    
    
    
    
    8,983
    
    
    24,341
    
    
    25,818
    
    
    20,778Gas
      transported
    
    
    
    
    
    11,679
    
    
    26,007
    
    
    28,366
    
    
    26,976Total
      gas sales and gas transported
    
    
    
    
    
    20,662
    
    
    50,348
    
    
    54,184
    
    
    47,754Gas
      sales revenues (thousands of dollars):Residential
    
    
    
    
    $
    60,119
    
    $
    183,941
    
    $
    175,337
    
    $
    148,860Commercial
    
    
    
    
    
    23,699
    
    
    62,407
    
    
    56,730
    
    
    46,307Industrial
      and irrigation
    
    
    
    
    
    1,512
    
    
    3,376
    
    
    2,895
    
    
    2,509Public
      authorities and other
    
    
    
    
    
    1,057
    
    
    2,676
    
    
    2,667
    
    
    1,233Gas
      revenues billed
    
    
    
    
    
    86,387
    
    
    252,400
    
    
    237,629
    
    
    198,909Net
      change in unbilled gas sales revenues
    
    
    
    
    
    20,310
    
    
    929
    
    
    135
    
    
    (276
    )Total
      gas sales revenues
    
    
    
    
    
    106,697
    
    
    253,329
    
    
    237,764
    
    
    198,633Gas
      transportation revenues
    
    
    
    
    
    5,968
    
    
    13,872
    
    
    15,389
    
    
    14,445Other
      revenues
    
    
    
    
    
    523
    
    
    1,713
    
    
    1,515
    
    
    4,779Total
      operating revenues
    
    
    
    
    $
    113,188
    
    $
    268,914
    
    $
    254,668
    
    $
    217,857Weather:Degree
      days
    
    
    
    
    
    2,301
    
    
    6,240
    
    
    6,654
    
    
    5,373Percent
      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
    
    
    265,206Commercial
    
    
    
    
    
    25,358
    
    
    25,798
    
    
    25,442
    
    
    21,696Industrial
      and irrigation
    
    
    
    
    
    207
    
    
    226
    
    
    225
    
    
    3,472Public
      authorities and other
    
    
    
    
    
    50
    
    
    47
    
    
    41
    
    
    43Total
      average customers served
    
    
    
    
    
    295,666
    
    
    295,997
    
    
    294,020
    
    
    290,417Transportation
      customers
    
    
    
    
    
    1,248
    
    
    1,242
    
    
    1,462
    
    
    1,505Total
      average gas sales and transportation
      customers
    
    
    
    
    
    296,914
    
    
    297,239
    
    
    295,482
    
    
    291,922Gas
      sales in MMcf:Residential
    
    
    
    
    
    6,633
    
    
    24,194
    
    
    25,481
    
    
    19,975Commercial
    
    
    
    
    
    2,669
    
    
    9,753
    
    
    9,725
    
    
    6,196Industrial
      and irrigation
    
    
    
    
    
    1,234
    
    
    1,968
    
    
    2,055
    
    
    3,271Public
      authorities and other
    
    
    
    
    
    9
    
    
    25
    
    
    28
    
    
    23Gas
      sales billed
    
    
    
    
    
    10,545
    
    
    35,940
    
    
    37,289
    
    
    29,465Net
      change in unbilled gas sales
    
    
    
    
    
    3,074
    
    
    (1,366
    )
    
    1,336
    
    
    (333
    )Total
      gas sales
    
    
    
    
    
    13,619
    
    
    34,574
    
    
    38,625
    
    
    29,132Gas
      transported
    
    
    
    
    
    3,859
    
    
    9,080
    
    
    10,959
    
    
    11,457Total
      gas sales and gas transported
    
    
    
    
    
    17,478
    
    
    43,654
    
    
    49,584
    
    
    40,589Gas
      sales revenues (thousands of dollars):Residential
    
    
    
    
    $
    97,734
    
    $
    307,534
    
    $
    290,370
    
    $
    236,331Commercial
    
    
    
    
    
    35,509
    
    
    111,712
    
    
    97,091
    
    
    65,316Industrial
      and irrigation
    
    
    
    
    
    11,581
    
    
    16,542
    
    
    15,045
    
    
    20,804Public
      authorities and other
    
    
    
    
    
    193
    
    
    437
    
    
    511
    
    
    275Gas
      revenues billed
    
    
    
    
    
    145,017
    
    
    436,225
    
    
    403,017
    
    
    322,726Net
      change in unbilled gas sales revenues
    
    
    
    
    
    36,914
    
    
    5,231
    
    
    (12,657
    )
    
    (17,788
    )Total
      gas sales revenues
    
    
    
    
    
    181,931
    
    
    441,456
    
    
    390,360
    
    
    304,938Gas
      transportation revenues
    
    
    
    
    
    5,952
    
    
    11,835
    
    
    14,906
    
    
    13,820Other
      revenues
    
    
    
    
    
    2,732
    
    
    1,343
    
    
    2,242
    
    
    3,190Total
      operating revenues
    
    
    
    
    $
    190,615
    
    $
    454,634
    
    $
    407,508
    
    $
    321,948Weather:Degree
      days
    
    
    
    
    
    2,004
    
    
    5,644
    
    
    6,143
    
    
    4,980Percent
      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
    
    VotesDirector
    
    For
    
    WithheldKurt
      A. Gitter
    
    75,225,836
    
    1,150,970Adam
      M. Lindemann
    
    62,061,565
    
    14,315,241George
      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
    
    
    20.50September
      30, 2004
    
    
    20.65
    
    
    18.00(Quarter
      Ended)June
      30, 2004
    
    
    20.33
    
    
    17.98March
      31, 2004
    
    
    18.81
    
    
    16.90December
      31, 2003
    
    
    17.82
    
    
    15.88September
      30, 2003
    
    
    17.00
    
    
    14.10(Quarter
      Ended)June
      30, 2003
    
    
    16.19
    
    
    10.98March
      31, 2003
    
    
    15.62
    
    
    10.96December
      31, 2002
    
    
    15.41
    
    
    9.21September
      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
    ****
      6,620,773Plans
      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
    
    
    $
    566,833Net
      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
    
    
    
    20,096Available
      for common shareholders
    
    
    
    
    6,088
    101,339
    76,189
    19,624
    57,285
    
    
    
    9,845Net
      earnings (loss) per dilutedcommon
      share (h):Continuing
      operations
    
    
    
    
    0.07
    1.30
    0.70
    0.02
    0.64
    
    
    
    (.19
    )Discontinued
      operations
    
    
    
    
    --
    --
    0.52
    0.29
    0.27
    
    
    
    0.37Available
      for common shareholders
    
    
    
    
    0.07
    1.30
    1.22
    0.31
    0.91
    
    
    
    0.18Total
      assets
    
    
    
    
    5,568,289
    4,572,458
    4,590,938
    2,680,064
    2,907,299
    
    
    
    2,021,460Stockholders’
      equity
    
    
    
    
    1,497,557
    1,261,991
    920,418
    685,346
    721,857
    
    
    
    735,455Current
      portion of long-term debt andcapital
      lease obligation
    
    
    
    
    
    
    
    
    89,650
    
    
    
    
    
    99,997
    
    
    
    
    
    734,752
    
    
    
    
    
    108,203
    
    
    
    
    
    5,913
    
    
    
    
    2,193Long-term
      debt and capital leaseobligation,
      excluding current portion
    
    
    
    
    2,070,353
    2,154,615
    1,611,653
    1,082,210
    1,329,631
    
    
    
    733,744Company-obligated
      mandatorilyredeemable
      preferred securitiesof
      subsidiary trust
    
    
    
    
    --
    --
    100,000
    100,000
    100,000
    
    
    
    100,000Average
      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.





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.





***Overview***





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.




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.





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.





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
    
    $
    32,916Transportation
      and storage segment
    
    
    90,121
    
    
    90,430All
      other
    
    
    (1,783
    )
    
    (736
    )Corporate
    
    
    (803
    )
    
    (3,344
    )Total
      operating income
    
    
    106,931
    
    
    119,266Other
      income (expenses):Interest
    
    
    (64,898
    )
    
    (66,600
    )Earnings
      from unconsolidated investments
    
    
    4,745
    
    
    112Other,
      net
    
    
    (18,080
    )
    
    4,299Total
      other expenses, net
    
    
    (78,233
    )
    
    (62,189
    )Earnings
      before income tax
    
    
    28,698
    
    
    57,077Federal
      and state income tax
    
    
    13,927
    
    
    22,362Net
      earnings
    
    
    14,771
    
    
    34,715Preferred
      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
    
    $
    135,502Transportation
      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
    
    
    91,125Other
      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
    
    
    1,420Other, net
    
    
    5,468
    
    
    17,979
    
    
    12,858Total
      other expenses, net
    
    
    (122,199
    )
    
    (74,422
    )
    
    (86,194
    )Federal
      and state income taxes
    
    
    69,103
    
    
    24,273
    
    
    3,411Net
      earnings from continuing operations
    
    
    114,025
    
    
    43,669
    
    
    1,520Discontinued
      operations:Earnings from discontinued operations beforeincome
      taxes
    
    
    --
    
    
    84,773
    
    
    29,801Federal and state income taxes
    
    
    --
    
    
    52,253
    
    
    11,697Net
      earnings from discontinued operations
    
    
    --
    
    
    32,520
    
    
    18,104Net
      earnings
    
    
    114,025
    
    
    76,189
    
    
    19,624Preferred
      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
    
    $
    491,851Cost
      of gas and other energy
    
    
    (360,889
    )
    
    (311,102
    )Revenue-related
      taxes
    
    
    (18,037
    )
    
    (17,461
    )Net
      operating revenues, excluding depreciationand
      amortization
    
    
    170,420
    
    
    163,288Operating
      expenses:Operating,
      maintenance, and general
    
    
    104,295
    
    
    89,489Depreciation
      and amortization
    
    
    32,511
    
    
    29,263Taxes
      other than on income and revenues
    
    
    14,218
    
    
    11,620Total
      operating expenses
    
    
    151,024
    
    
    130,372Operating
      income
    
    $
    19,396
    
    $
    32,916**Operating
      Information**Gas
      sales volumes (MMcf)
    
    
    42,176
    
    
    41,328Gas
      transported volumes (MMcf)
    
    
    27,259
    
    
    28,858Weather:Degree
      Days:Missouri
      Gas Energy service territories
    
    
    1,669
    
    
    1,827PG
      Energy service territories
    
    
    2,301
    
    
    2,268New
      England Gas Company service territories
    
    
    2,004
    
    
    1,878Percent
      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
    
    $
    968,933Cost
      of gas and other energy
    
    
    (863,637
    )
    
    (723,719
    )
    
    (568,447
    )Revenue-related
      taxes
    
    
    (45,395
    )
    
    (40,485
    )
    
    (33,410
    )Net
      operating revenues, excluding depreciationand
      amortization
    
    
    395,373
    
    
    394,760
    
    
    367,076Operating
      expenses:Operating,
      maintenance, and general
    
    
    194,394
    
    
    171,463
    
    
    154,906Depreciation
      and amortization
    
    
    57,601
    
    
    56,396
    
    
    53,937Taxes
      other than on income and revenues
    
    
    24,484
    
    
    24,139
    
    
    22,731Total
      operating expenses
    
    
    276,479
    
    
    251,998
    
    
    231,574Operating
      income
    
    $
    118,894
    
    $
    142,762
    
    $
    135,502**Operating
      Information**Gas
      sales volumes (MMcf)
    
    
    112,271
    
    
    122,115
    
    
    101,036Gas
      transported volumes (MMcf)
    
    
    60,848
    
    
    66,218
    
    
    65,757Weather:Degree
      Days:Missouri
      Gas Energy service territories
    
    
    4,770
    
    
    5,105
    
    
    4,419PG
      Energy service territories
    
    
    6,240
    
    
    6,654
    
    
    5,373New
      England Gas Company service territories
    
    
    5,644
    
    
    6,143
    
    
    4,980Percent
      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
    
    $
    176,268LNG
      terminalling revenue
    
    
    28,694
    
    
    30,265Commodity
      revenue
    
    
    37,623
    
    
    33,503Other
      revenue
    
    
    4,802
    
    
    4,437Total
      operating revenue
    
    
    242,743
    
    
    244,473Operating
      expenses:Operating,
      maintenance, and general
    
    
    109,796
    
    
    107,796Depreciation
      and amortization
    
    
    30,159
    
    
    33,158Taxes
      other than on income and revenues
    
    
    12,667
    
    
    13,089Total
      operating expense
    
    
    152,622
    
    
    154,043Operating
      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
    
    $
      17,117LNG
      terminalling revenue
    
    
    57,988
    
    3,244Commodity
      revenue
    
    
    
    68,412
    
    3,484Other
      revenue
    
    
    
    9,140
    
    677Total
      operating revenues
    
    
    490,883
    
    24,522Operating
      expenses:Operating,
      maintenance, and general
    
    210,105
    
    10,102Depreciation
      and amortization
    
    59,988
    
    3,197Taxes
      other than on income and revenues
    27,288
    
    1,595Total
      operating expense
    
    297,381
    
    14,894Operating
      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
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 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.





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.





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.





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
    
    $
    1,122,526Short-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
    
    
    186,767Missouri
      Gas Energy Safety Program
    
    
    175,350
    
    
    7,720
    
    
    10,524
    
    
    10,630
    
    
    10,736
    
    
    10,843
    
    
    124,897Storage
      contracts (4)
    
    
    147,224
    
    
    27,444
    
    
    23,999
    
    
    17,444
    
    
    16,159
    
    
    14,658
    
    
    47,520LNG
      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
    
    
    6,935Interest
      payments on debt
    
    
    1,860,506
    
    
    134,766
    
    
    129,696
    
    
    112,347
    
    
    104,969
    
    
    94,096
    
    
    1,284,632Benefit
      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
    TitleGEORGE
      L. LINDEMANN*
    Chairman
      of the Board, Chief Executive Officer and Director (Principal Executive
      Officer)JONE
      E. BRENNAN*
    DirectorDAVID
      BRODSKY*
    DirectorFRANK
      W. DENIUS*
    DirectorKURT
      A. GITTER, M.D.*
    DirectorHERBERT
      H. JACOBI*
    DirectorTHOMAS
      F. KARAM
    DirectorThomas
      F. KaramADAM
      M. LINDEMANN*
    DirectorTHOMAS
      N. McCARTER, III*
    DirectorGEORGE
      ROUNTREE, III*
    DirectorRONALD
      W. SIMMS*
    DirectorDAVID
      J. KVAPIL
    Executive
      Vice President and Chief Financial OfficerDavid
      J. Kvapil
    (Principal
      Financial Officer)*ByTHOMAS
      F. KARAMThomas
      F. KaramAttorney-in-fact











Page


Financial
      Statements:Consolidated
      statement of operations - six months ended December 31, 2004
      andyears
      ended June 30, 2004, 2003 and 2002
    F-2Consolidated
      balance sheet - December 31, 2004, June 30, 2004 and June 30,
      2003
    F-3
      to F-4Consolidated
      statement of cash flows - six months ended December 31, 2004
      andyears
      ended June 30, 2004, 2003 and 2002
    F-5Consolidated
      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-7Notes
      to consolidated financial statements
    F-8
      to F-55Report
      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
    
    $
    968,933Gas
      transportation and storage
    
    
    242,743
    
    
    490,883
    
    
    24,522
    
    
    -Other
    
    
    2,249
    
    
    4,486
    
    
    5,014
    
    
    11,681Total
      operating revenues
    
    
    794,338
    
    
    1,799,774
    
    
    1,188,500
    
    
    980,614Cost
      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 depreciationand
      amortization
    
    
    415,045
    
    
    889,941
    
    
    423,404
    
    
    374,128Operating
      expenses:Operating,
      maintenance and general
    
    
    217,967
    
    
    411,811
    
    
    193,745
    
    
    171,147Business
      restructuring charges
    
    
    --
    
    
    --
    
    
    --
    
    
    29,159Depreciation
      and amortization
    
    
    63,376
    
    
    118,755
    
    
    60,642
    
    
    58,989Taxes,
      other than on income and revenues
    
    
    26,771
    
    
    54,048
    
    
    26,653
    
    
    23,708Total
      operating expenses
    
    
    308,114
    
    
    584,614
    
    
    281,040
    
    
    283,003Operating
      income
    
    
    106,931
    
    
    305,327
    
    
    142,364
    
    
    91,125Other
      income (expenses):Interest
    
    
    (64,898
    )
    
    (127,867
    )
    
    (83,343
    )
    
    (90,992
    )Earnings
      from unconsolidated investments
    
    
    4,745
    
    
    200
    
    
    422
    
    
    1,420Dividends
      on preferred securities of subsidiary trust
    
    
    --
    
    
    --
    
    
    (9,480
    )
    
    (9,480
    )Other,
      net
    
    
    (18,080
    )
    
    5,468
    
    
    17,979
    
    
    12,858Total
      other expenses, net
    
    
    (78,233
    )
    
    (122,199
    )
    
    (74,422
    )
    
    (86,194
    )Earnings
      from continuing operations before income taxes
    
    
    28,698
    
    
    183,128
    
    
    67,942
    
    
    4,931Federal
      and state income taxes
    
    
    13,927
    
    
    69,103
    
    
    24,273
    
    
    3,411Net
      earnings from continuing operations
    
    
    14,771
    
    
    114,025
    
    
    43,669
    
    
    1,520Discontinued
      operations:Earnings
      from discontinued operations beforeincome
      taxes
    
    
    --
    
    
    --
    
    
    84,773
    
    
    29,801Federal
      and state income taxes
    
    
    --
    
    
    --
    
    
    52,253
    
    
    11,697Net
      earnings from discontinued operations
    
    
    --
    
    
    --
    
    
    32,520
    
    
    18,104Net
      earnings
    
    
    14,771
    
    
    114,025
    
    
    76,189
    
    
    19,624Preferred
      stock dividends
    
    
    (8,683
    )
    
    (12,686
    )
    
    --
    
    
    --Net
      earnings available for common shareholders
    
    $
    6,088
    
    $
    101,339
    
    $
    76,189
    
    $
    19,624Net
      earnings available for common shareholders fromcontinuing
      operations per share:Basic
    
    $
    0.07
    
    $
    1.34
    
    $
    0.72
    
    $
    0.03Diluted
    
    $
    0.07
    
    $
    1.30
    
    $
    0.70
    
    $
    0.02Net
      earnings available for common shareholders per share:Basic
    
    $
    0.07
    
    $
    1.34
    
    $
    1.26
    
    $
    0.33Diluted
    
    $
    0.07
    
    $
    1.30
    
    $
    1.22
    
    $
    0.31Weighted
      average shares outstanding:Basic
    
    
    81,995,878
    
    
    75,442,238
    
    
    60,584,293
    
    
    59,420,048Diluted
    
    
    85,298,894
    
    
    77,694,607
    
    
    62,523,110
    
    
    62,596,907See
      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
    
    $
    3,710,541Construction
      work in progress
    
    
    237,283
    
    
    169,264
    
    
    75,4844,106,504
    
    
    3,941,880
    
    
    3,786,025Less
      accumulated depreciation and amortization
    
    
    (778,876
    )
    
    (734,367
    )
    
    (641,225
    )Net
      property, plant and equipment
    
    
    3,327,628
    
    
    3,207,513
    
    
    3,144,800Current
      assets:Cash
      and cash equivalents
    
    
    30,053
    
    
    19,971
    
    
    86,997Accounts
      receivable, billed and unbilled, net
    
    
    333,492
    
    
    181,924
    
    
    192,402Inventories
    
    
    267,136
    
    
    200,295
    
    
    173,757Deferred
      gas purchase costs
    
    
    --
    
    
    3,933
    
    
    24,603Gas
      imbalances - receivable
    
    
    36,122
    
    
    22,045
    
    
    34,911Prepayments
      and other
    
    
    45,705
    
    
    27,561
    
    
    18,971Total
      current assets
    
    
    712,508
    
    
    455,729
    
    
    531,641Goodwill
    
    
    640,547
    
    
    640,547
    
    
    642,921Deferred
      charges
    
    
    199,064
    
    
    190,735
    
    
    188,261Unconsolidated
      investments
    
    
    631,893
    
    
    20,856
    
    
    22,682Other
    
    
    56,649
    
    
    57,078
    
    
    60,633Total
      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
    
    $
    73,074Preferred
      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
    
    
    909,191Less
      treasury stock; 404,536, 404,536 and 282,333shares,
      respectively, at cost
    
    
    (12,870
    )
    
    (12,870
    )
    
    (10,467
    )Less
      common stock held in trust: 1,198,034, 1,089,147and
      1,114,738 shares, respectively
    
    
    (17,980
    )
    
    (15,812
    )
    
    (15,617
    )Deferred
      compensation plans
    
    
    14,128
    
    
    11,960
    
    
    9,960Accumulated
      other comprehensive loss
    
    
    (59,118
    )
    
    (50,224
    )
    
    (62,579
    )Retained
      earnings
    
    
    48,044
    
    
    46,692
    
    
    16,856Total
      stockholders' equity
    
    
    1,497,557
    
    
    1,261,991
    
    
    920,418Company-obligated
      mandatorily redeemable preferredsecurities
      of subsidiary trust holdingsolely
      subordinated notes of Southern Union
    
    
    --
    
    
    --
    
    
    100,000Long-term
      debt and capital lease obligation
    
    
    2,070,353
    
    
    2,154,615
    
    
    1,611,653Total
      capitalization
    
    
    3,567,910
    
    
    3,416,606
    
    
    2,632,071Current
      liabilities:Long-term
      debt and capital lease obligationdue
      within one year
    
    
    89,650
    
    
    99,997
    
    
    734,752Notes
      payable
    
    
    699,000
    
    
    21,000
    
    
    251,500Accounts
      payable
    
    
    183,018
    
    
    122,309
    
    
    112,840Federal,
      state and local taxes
    
    
    33,946
    
    
    32,866
    
    
    6,743Accrued
      interest
    
    
    36,934
    
    
    36,891
    
    
    40,871Customer
      deposits
    
    
    13,156
    
    
    12,043
    
    
    12,585Gas
      imbalances - payable
    
    
    102,567
    
    
    72,057
    
    
    64,519Other
    
    
    155,565
    
    
    116,783
    
    
    130,196Total
      current liabilities
    
    
    1,313,836
    
    
    513,946
    
    
    1,354,006Deferred
      credits
    
    
    321,049
    
    
    292,946
    
    
    322,154Accumulated
      deferred income taxes
    
    
    365,494
    
    
    348,960
    
    
    282,707Commitments
      and contingenciesTotal
      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
    
    $
    19,624Adjustments
      to reconcile net earnings to net cash flowsprovided
      by (used in) operating activities:Depreciation
      and amortization
    
    
    63,376
    
    
    118,755
    
    
    60,642
    
    
    58,989Amortization
      of debt premium
    
    
    (1,510
    )
    
    (14,243
    )
    
    (1,307
    )
    
    --Deferred
      income taxes
    
    
    12,082
    
    
    67,455
    
    
    78,747
    
    
    28,397Provision
      for bad debts
    
    
    11,649
    
    
    21,216
    
    
    17,873
    
    
    12,260Provision
      for impairment of other assets
    
    
    16,425
    
    
    1,603
    
    
    --
    
    
    10,380Financial
      derivative trading gains
    
    
    (302
    )
    
    (605
    )
    
    (605
    )
    
    (6,204
    )Amortization
      of debt expense
    
    
    1,064
    
    
    4,143
    
    
    2,919
    
    
    2,936Gain
      on sale of subsidiaries and other assets
    
    
    --
    
    
    --
    
    
    (62,992
    )
    
    (6,414
    )Loss
      on sale of subsidiaries
    
    
    --
    
    
    1,150
    
    
    --
    
    
    1,500Gain
      on settlement of interest rate swaps
    
    
    --
    
    
    --
    
    
    --
    
    
    (17,166
    )Gain
      on extinguishment of debt
    
    
    --
    
    
    (6,354
    )
    
    --
    
    
    --Business
      restructuring charges
    
    
    --
    
    
    --
    
    
    --
    
    
    24,440Net
      cash provided (used by) assets held for sale
    
    
    --
    
    
    --
    
    
    (23,698
    )
    
    48,618Earnings
      from unconsolidated investments
    
    
    (4,745
    )
    
    (200
    )
    
    (422
    )
    
    (1,420
    )Other
    
    
    (895
    )
    
    (470
    )
    
    (707
    )
    
    355Changes
      in operating assets and liabilities, net ofacquisitions:Accounts
      receivable, billed and unbilled
    
    
    (174,716
    )
    
    (6,181
    )
    
    (48,520
    )
    
    71,932Gas
      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
    )
    
    53,436Inventories
    
    
    (66,841
    )
    
    (25,824
    )
    
    (34,583
    )
    
    1,044Deferred
      charges and credits
    
    
    22,743
    
    
    13,773
    
    
    (12,561
    )
    
    16,804Prepaids
      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
    
    
    273,479Cash
      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
    
    
    40,935Proceeds
      from sale of interest rate swaps
    
    
    --
    
    
    --
    
    
    --
    
    
    17,166Net
      cash used in assets held for sale
    
    
    --
    
    
    --
    
    
    (13,410
    )
    
    (23,215
    )Other
    
    
    (1,711
    )
    
    (1,131
    )
    
    (6,154
    )
    
    274Net
      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
    )
    
    137Issuance
      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
    
    
    8,346Other
    
    
    --
    
    
    --
    
    
    1,217
    
    
    2,529Net
      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
    
    
    --
    
    
    1,219Cash
      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)





**Accumulated**


**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**


**(thousands of dollars)** ****


****


Balance
      July 1, 2001
    
    $
    54,553
    
    
    --
    
    $
    676,324
    
    $
    (15,869
    )
    $
    (11,697
    )
    $
    13,443
    
    $
    5,103
    
    $
    721,857Comprehensive
      income (loss):Net
      earnings
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    19,624
    
    
    19,624Unrealized
      loss in investmentsecurities,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (18,249
    )
    
    --
    
    
    (18,249
    )Minimum
      pension liabilityadjustment,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (10,498
    )
    
    --
    
    
    (10,498
    )Unrealized
      gain on hedgingactivities,
      net of tax
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    804
    
    
    --
    
    
    804Comprehensive
      income (loss)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,319
    )Payment
      on note receivable
    
    
    --
    
    
    --
    
    
    202
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    202Purchase
      of treasury stock
    
    
    --
    
    
    --
    
    
    --
    
    
    (41,632
    )
    
    --
    
    
    --
    
    
    --
    
    
    (41,632
    )5%
      stock dividend
    
    
    2,618
    
    
    --
    
    
    22,091
    
    
    --
    
    
    --
    
    
    --
    
    
    (24,727
    )
    
    (18
    )Stock
      compensation plan
    
    
    --
    
    
    --
    
    
    1,248
    
    
    --
    
    
    1,257
    
    
    --
    
    
    --
    
    
    2,505Sale
      of common stock held in trust
    
    
    --
    
    
    --
    
    
    26
    
    
    --
    
    
    1,945
    
    
    --
    
    
    --
    
    
    1,971Exercise
      of stock options
    
    
    884
    
    
    --
    
    
    8,021
    
    
    (172
    )
    
    47
    
    
    --
    
    
    --
    
    
    8,780Balance
      June 30, 2002
    
    
    58,055
    
    
    --
    
    
    707,912
    
    
    (57,673
    )
    
    (8,448
    )
    
    (14,500
    )
    
    --
    
    
    685,346Comprehensive
      income (loss):Net
      earnings
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    76,189
    
    
    76,189Unrealized
      loss in investmentsecurities,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (581
    )
    
    --
    
    
    (581
    )Minimum
      pension liabilityadjustment,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (41,930
    )
    
    --
    
    
    (41,930
    )Unrealized
      loss on hedgingactivities,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (5,568
    )
    
    --
    
    
    (5,568
    )Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    28,110Payment
      on note receivable
    
    
    --
    
    
    --
    
    
    305
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    305Purchase
      of treasury stock
    
    
    --
    
    
    --
    
    
    --
    
    
    (2,181
    )
    
    --
    
    
    --
    
    
    --
    
    
    (2,181
    )5%
      stock dividend
    
    
    3,468
    
    
    --
    
    
    55,832
    
    
    --
    
    
    --
    
    
    --
    
    
    (59,333
    )
    
    (33
    )Stock
      compensation plan
    
    
    --
    
    
    --
    
    
    480
    
    
    --
    
    
    737
    
    
    --
    
    
    --
    
    
    1,217Issuance
      of stock for acquisition
    
    
    --
    
    
    --
    
    
    --
    
    
    48,900
    
    
    --
    
    
    --
    
    
    --
    
    
    48,900Issuance
      of common stock
    
    
    10,925
    
    
    --
    
    
    157,757
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    168,682Issuance
      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
    
    
    --
    
    
    --
    
    
    2,181Exercise
      of stock options
    
    
    626
    
    
    --
    
    
    2,304
    
    
    487
    
    
    (370
    )
    
    --
    
    
    --
    
    
    3,047Balance
      June 30, 2003
    
    
    73,074
    
    
    --
    
    
    909,191
    
    
    (10,467
    )
    
    (5,657
    )
    
    (62,579
    )
    
    16,856
    
    
    920,418Comprehensive
      income (loss):Net
      earnings
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    114,025
    
    
    114,025Unrealized
      loss in investmentsecurities,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (21
    )
    
    --
    
    
    (21
    )Minimum
      pension liabilityadjustment,
      net of tax
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    10,768
    
    
    --
    
    
    10,768Unrealized
      gain on hedgingactivities,
      net of tax
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    1,608
    
    
    --
    
    
    1,608Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    126,380Preferred
      stock dividends
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (12,686
    )
    
    (12,686
    )Payment
      on note receivable
    
    
    --
    
    
    --
    
    
    347
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    347Purchase
      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
    
    
    --
    
    
    --
    
    
    2,403Issuance
      of preferred stock
    
    
    --
    
    
    230,000
    
    
    (6,590
    )
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    223,410Exercise
      of stock options
    
    
    411
    
    
    --
    
    
    3,711
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    4,122Balance
      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
    
    
    14,771Minimum
      pension liabilityadjustment,
      net of tax benefit
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (8,832)
    
    
    --
    
    
    (8,832)Unrealized
      loss on hedgingactivities,
      net of tax
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (62)
    
    
    --
    
    
    (62)Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,877Preferred
      stock dividends
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (8,683
    )
    
    (8,683
    )5%
      stock dividend
    
    
    242
    
    
    --
    
    
    4,494
    
    
    --
    
    
    --
    
    
    --
    
    
    (4,736
    )
    
    --Payment
      on note receivable
    
    
    --
    
    
    --
    
    
    473
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    473Issuance
      of common stock
    
    
    13,042
    
    
    --
    
    
    215,245
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    228,287Exercise
      of stock options
    
    
    338
    
    
    --
    
    
    9,274
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    9,612Balance
      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
    
    $
    19,624Deduct
      total stock-based employee compensationexpense
      determined under fair value based methodfor
      all awards, net of related taxes
    
    
    
    
    
    496
    
    
    1,699
    
    
    1,373
    
    
    953Pro
      forma net earnings
    
    
    
    
    $
    14,275
    
    $
    112,326
    
    $
    74,816
    
    $
    18,671Net
      earnings available for common shareholders per share:Basic-
      as reported
    
    
    
    
    $
    0.07
    
    $
    1.34
    
    $
    1.26
    
    $
    0.33Basic-
      pro forma
    
    
    
    
    $
    0.07
    
    $
    1.32
    
    $
    1.23
    
    $
    0.31Diluted-
      as reported
    
    
    
    
    $
    0.07
    
    $
    1.30
    
    $
    1.22
    
    $
    0.31Diluted-
      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
    
    $
    19,624Other
      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
    )
    
    406Realized
      gain (loss) on hedging activities in net earnings,net
      of tax (benefit)
    
    (2,216
    )
    
    (5,497
    )
    
    (6
    )
    
    398Minimum
      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
(MM *Btu* ),
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
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 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 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.





**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.





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.





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.




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)
    
    $
    1,904,762Intangibles
    
    
    9,503Current
      assets (a)
    
    
    217,645Other
      non-current assets
    
    
    30,098Total
      assets acquired
    
    
    2,162,008Long-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.


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.





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
    
    2002Operating
      revenues
    $
    1,671,114
    
    $
    1,467,630Net
      earnings from continuing operations
    
    132,458
    
    
    56,073Net
      earnings per share from continuing operationsBasic
    
    1.76
    
    
    0.75Diluted
    
    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 shareholdersfrom
      continuing operations
    
    
    
    
    $
    6,088
    
    $
    101,339
    
    $
    43,669
    
    $
    1,520Net
      earnings from discontinued operations
    
    --
    
    
    --
    
    
    32,520
    
    
    18,104Net
      earnings available for common shareholders
    $
    6,088
    
    $
    101,339
    
    $
    76,189
    
    $
    19,624Weighted
      average shares outstanding -- basic
    
    81,995,878
    
    
    75,442,238
    
    
    60,584,293
    
    
    59,420,048Weighted
      average shares outstanding -- diluted
    
    85,298,894
    
    
    77,694,607
    
    
    62,523,110
    
    
    62,596,907Basic
      earnings per share:Net
      earnings available for common shareholdersfrom
      continuing operations
    
    
    
    
    $
    0.07
    
    $
    1.34
    
    $
    0.72
    
    $
    0.03Net
      earnings from discontinued operations
    
    
    
    
    
    --
    
    
    --
    
    
    0.54
    
    
    0.30Net
      earnings available for common shareholders
    
    
    
    
    $
    0.07
    
    $
    1.34
    
    $
    1.26
    
    $
    0.33Diluted
      earnings per share:Net
      earnings available for common shareholdersfrom continuing operations
    
    
    
    
    $
    0.07
    
    $
    1.30
    
    $
    0.70
    
    $
    0.02Net
      earnings from discontinued operations
    
    
    
    
    
    --
    
    
    --
    
    
    0.52
    
    
    0.29Net
      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
    
    
    60,767,881Less
      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
    
    
    59,420,048Weighted
      average shares outstanding
    
    
    83,153,406
    
    
    76,599,311
    
    
    61,853,526
    
    
    60,767,881Add
      assumed conversion of equity units
    
    
    1,116,968
    
    
    --
    
    
    --
    
    
    --Add
      assumed exercise of stock options
    
    
    1,028,520
    
    
    1,095,296
    
    
    669,584
    
    
    1,829,026Weighted
      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
    
    $
    1,611,098Transmission
      plant
    
    
    1,185,647
    
    
    1,159,825
    
    
    1,238,972General--
      LNG
    
    
    388,703
    
    
    388,459
    
    
    297,694General
      plant-- other
    
    
    143,435
    
    
    141,140
    
    
    165,036Underground
      storage plant
    
    
    274,337
    
    
    287,005
    
    
    236,639Gathering
      plant
    
    
    46,074
    
    
    39,746
    
    
    56,076Other
    
    
    126,308
    
    
    96,308
    
    
    107,444Total
      plant (a)
    
    
    3,871,678
    
    
    3,774,828
    
    
    3,712,959Less
      contributions in aid of construction
    
    
    (2,457
    )
    
    (2,212
    )
    
    (2,418
    )Plant
      in service
    
    
    3,869,221
    
    
    3,772,616
    
    
    3,710,541Construction
      work in progress
    
    
    237,283
    
    
    169,264
    
    
    75,4844,106,504
    
    
    3,941,880
    
    
    3,786,025Less
      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
    
    $
    87,647Less
      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
    
    $
    652,048Impairment
      losses
    
    
    (1,417
    )Sale
      of subsidiaries and other operations
    
    
    (7,710
    )Balance
      as of June 30, 2002
    
    
    642,921Impairment
      losses
    
    
    --Balance
      as of June 30, 2003
    
    
    642,921Impairment
      losses
    
    
    --Reversal
      of income tax reserve
    
    
    (2,374
    )Balance
      as of June 30, 2004
    
    
    640,547Impairment
      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.





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, no impairment had been indicated.




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
      ChargesPensions
    
    $
    54,097
    
    $
    45,625
    
    $
    39,088Unamortized
      debt expense
    
    
    37,869
    
    
    38,596
    
    
    34,209Income
      taxes
    
    
    32,661
    
    
    31,441
    
    
    30,514Retirement
      costs other than pensions
    
    
    24,459
    
    
    26,008
    
    
    29,028Service
      Line Replacement program
    
    
    15,161
    
    
    16,722
    
    
    18,974Environmental
    
    
    16,332
    
    
    12,220
    
    
    14,304Other
    
    
    18,485
    
    
    20,123
    
    
    22,144Total
      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
      CreditsPensions
    
    $
    109,908
    
    $
    97,380
    
    $
    88,016Retirement
      costs other than pensions
    
    
    58,507
    
    
    60,404
    
    
    65,144Costs
      of removal
    
    
    29,337
    
    
    28,519
    
    
    27,286Environmental
    
    
    25,919
    
    
    23,082
    
    
    32,322Derivative
      instrument liability
    
    
    16,232
    
    
    13,704
    
    
    26,151Customer
      advances for construction
    
    
    14,740
    
    
    13,518
    
    
    12,008Provision
      for self-insured claims
    
    
    12,296
    
    
    10,542
    
    
    12,000Investment
      tax credit
    
    
    5,157
    
    
    5,367
    
    
    5,791Other
    
    
    48,953
    
    
    40,430
    
    
    53,436Total
      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
    
    
    13,041Other
      Investments, at Cost
    
    
    3,113
    
    
    8,038
    
    
    9,641Total
      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
    
    $
    1,255Non-current
      assets
    
    
    2,249,386
    
    
    22,847Current
      liabilities
    
    
    65,670
    
    
    833Non-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
    
    $
    1,919Operating
      income
    
    
    7,300
    
    
    394Net
      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.





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.





**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
    
    $
    11.29Granted
    
    
    --
    
    
    --
    
    
    75,249
    
    
    13.83Exercised
    
    
    --
    
    
    --
    
    
    (1,020,546
    )
    
    9.54Canceled
    
    
    --
    
    
    --
    
    
    (188,856
    )
    
    14.45Outstanding
      June 30, 2002
    
    
    --
    
    
    --
    
    
    3,823,513
    
    
    11.65Granted
    
    
    --
    
    
    --
    
    
    --
    
    
    --Exercised
    
    
    --
    
    
    --
    
    
    (662,982
    )
    
    4.65Canceled
    
    
    --
    
    
    --
    
    
    (185,161
    )
    
    14.67Outstanding
      June 30, 2003
    
    
    
    
    
    --
    
    
    2,975,370
    
    
    13.02Granted
    
    
    729,227
    
    
    17.67
    
    
    --
    
    
    --Exercised
    
    
    --
    
    
    --
      -
    
    
    (352,486
    )
    
    9.91Canceled
    
    
    --
    
    
    --
    
    
    (2,190
    )
    
    15.38Outstanding
      June 30, 2004
    
    
    729,227
    
    
    17.67
    
    
    2,620,694
    
    
    13.44Granted
    
    
    
    
    
    
    
    
    --Exercised
    
    
    
    
    
    
    
    
    (340,068
    )
    
    13.32Canceled
    
    
    (51,450
    )
    
    17.67
    
    
    (17,012
    )
    
    15.36Outstanding
      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
    
    $
      6.748.00
      - 11.99
    
    271,058
    
    2.3
      years
    
    10.22
    
    271,058
    
    10.2212.00
      - 13.99
    
    503,785
    
    3.7
      years
    
    13.26
    
    469,484
    
    13.2614.00
      - 17.99
    
    1,367,992
    
    5.4
      years
    
    14.74
    
    1,159,090
    
    14.622,263,614
    
    
    
    
    
    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
    220,635June
      30, 2004
    --
    2,008,066
    443,929
    217,571June
      30, 2003
    --
    1,966,753
    443,929
    214,507June
      30, 2002
    --
    2,145,327
    459,467
    211,442





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





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.




***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.





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.





**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.





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.
The total net proceeds were used to repay debt under the Company’s revolving
credit facilities.







**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
    
    $
    359,7658.25%
      Senior Notes due 2029
    
    
    300,000
    
    
    300,000
    
    
    300,0002.75%
      Senior Notes due 2006
    
    
    125,000
    
    
    125,000
    
    
    125,000Term
      Note due 2005
    
    
    76,087
    
    
    111,087
    
    
    211,0876.50%
      to 10.25% First Mortgage Bonds, due 2008 to 2029
    
    
    112,421
    
    
    113,435
    
    
    115,8847.70%
      debentures, due 2027
    
    
    --
    
    
    --
    
    
    6,756Capital
      lease and other, due 2004 to 2007
    
    
    117
    
    
    277
    
    
    9,179973,390
    
    
    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
    
    
    --
    
    
    --
    
    
    292,5007.875%
      Senior Notes due 2004
    
    
    --
    
    
    52,455
    
    
    100,0006.50%
      Senior Notes due 2009
    
    
    60,623
    
    
    60,623
    
    
    158,9808.25%
      Senior Notes due 2010
    
    
    40,500
    
    
    40,500
    
    
    60,0007.00%
      Senior Notes due 2029
    
    
    66,305
    
    
    66,305
    
    
    135,890Term
      Loan due 2007
    
    
    258,433
    
    
    263,926
    
    
    275,3587.95%
      Debentures due 2023
    
    
    --
    
    
    --
    
    
    76,5007.20%
      Debentures due 2024
    
    
    --
    
    
    --
    
    
    58,000Net
      premiums on long-term debt
    
    
    14,688
    
    
    16,199
    
    
    61,5061,190,549
    
    
    1,250,008
    
    
    1,218,734Total
      consolidated debt and capital lease
    
    
    2,163,939
    
    
    2,259,572
    
    
    2,346,405Less
      current portion
    
    
    89,650
    
    
    99,997
    
    
    734,752Less
      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.




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.




***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
    
    $
    76,596Service
      cost
    
    
    3,689
    
    
    6,533
    
    
    5,655
    
    
    2,091
    
    
    3,993
    
    
    1,177Interest
      Cost
    
    
    11,412
    
    
    22,591
    
    
    22,899
    
    
    4,607
    
    
    8,739
    
    
    5,579Benefits
      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
    
    
    13,357Acquisition
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    42,752
    
    
    --Plan
      amendments
    
    
    446
    
    
    7,703
    
    
    1,095
    
    
    (1,308
    )
    
    5,173
    
    
    311Settlement
      recognition
    
    
    (2,402
    )
    
    (2,341
    )
    
    (2,105
    )
    
    --
    
    
    --
    
    
    --Benefit
      obligation at end of period
    
    $
    398,516
    
    $
    386,493
    
    $
    350,860
    
    $
    168,953
    
    $
    152,425
    
    $
    90,344Change
      in Plan Assets:Fair
      value of plan assets at beginning of period
    
    $
    276,154
    
    $
    237,376
    
    $
    284,911
    
    $
    34,004
    
    $
    21,332
    
    $
    22,408Return
      on plan assets
    
    
    1,980
    
    
    55,725
    
    
    (30,900
    )
    
    160
    
    
    3,211
    
    
    27Employer
      contributions
    
    
    11,320
    
    
    6,043
    
    
    5,516
    
    
    7,144
    
    
    15,724
    
    
    5,572Benefits
      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
    
    $
    21,332Funded
      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
    
    
    20,343Unrecognized
      prior service cost
    
    
    13,439
    
    
    13,737
    
    
    7,179
    
    
    3,409
    
    
    5,038
    
    
    130Prepaid/
      (accrued) at measurement date
    
    
    21,923
    
    
    17,742
    
    
    28,447
    
    
    (86,565
    )
    
    (87,411
    )
    
    (48,539
    )Contributions
      subsequent tomeasurement
      date
    
    
    1,044
    
    
    3,750
    
    
    4,534
    
    
    1,815
    
    
    2,151
    
    
    4,675Net
      asset (liability) recognized atend
      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/AHealth
      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
    
    $
    1,136Interest
      Cost
    
    
    11,412
    
    
    22,591
    
    
    22,899
    
    
    22,570
    
    
    4,607
    
    
    8,739
    
    
    5,579
    
    
    5,362Expected
      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
    
    
    --
    
    
    --
    
    
    --
    
    
    1,200Special
      termination benefits charge
    
    
    --
    
    
    --
    
    
    --
    
    
    8,957
    
    
    --
    
    
    --
    
    
    --
    
    
    1,309Settlement
      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
      accountstax
      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/AHealth
      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
    
    $
    7,1502006
    
    
    21,921
    
    
    7,5172007
    
    
    22,825
    
    
    7,3272008
    
    
    22,966
    
    
    7,7872009
    
    
    24,180
    
    
    8,416Years
      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.





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.





***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
    
    
    13,050State
    
    
    1,129
    
    
    7,075
    
    
    7,168
    
    
    60012,082
    
    
    67,455
    
    
    46,094
    
    
    13,650Total
      income tax expense fromcontinuing
      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
    
    $
    6,263Insurance
      accruals
    
    
    2,268
    
    
    1,601
    
    
    2,028Bad
      debt reserves
    
    
    4,866
    
    
    5,721
    
    
    4,096Post-retirement
      benefits
    
    
    17,326
    
    
    1,346
    
    
    1,078Minimum
      pension liability
    
    
    39,909
    
    
    33,511
    
    
    35,159NOL
      carry-forward
    
    
    12,434
    
    
    --
    
    
    --Unconsolidated
      investments
    
    
    11,942
    
    
    --
    
    
    --Other
    
    
    58,419
    
    
    8,442
    
    
    10,313Total
      deferred income tax assets
    
    
    171,516
    
    
    74,675
    
    
    58,937Valuation
      allowance
    
    
    (11,942
    )
    
    --
    
    
    --Net
      deferred income tax assets
    
    $
    159,574
    
    $
    74,675
    
    $
    58,937Deferred
      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
    
    
    4,096Accumulated
      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 continuingoperations
      at 35%
    
    $
    10,044
    
    $
    64,095
    
    $
    23,780
    
    $
    1,726Changes
      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
    
    
    695Amortization/write-down
      of goodwill
    
    
    --
    
    
    --
    
    
    --
    
    
    3,113Internal
      Revenue Service audit settlement
    
    
    --
    
    
    --
    
    
    --
    
    
    (1,570
    )Investment
      Tax Credit amortization
    
    
    (210
    )
    
    (424
    )
    
    (421
    )
    
    (608
    )Other
    
    
    1,163
    
    
    735
    
    
    588
    
    
    55Actual
      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.





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.




***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.





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.




**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.





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. These sites are as follows:





***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.***





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.





***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.***





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.





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.





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.


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.





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.





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
    
    $
    309,936Net
      operating revenues, excluding depreciation and amortization
      (a)
    
    $
    51,480
    
    $
    105,730Net
      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
    $
      794,338Net
      operating revenues, excluding depreciation and
amortization
    164,649
    250,396
    415,045Net
      earnings (loss) from continuing operations
    (7,140)
    21,911
    14,771Net
      earnings (loss) available for common shareholders
    (11,481
    17,569
    6,088Diluted
      net earnings (loss) per share available for common
      shareholders:(1)Continuing
      operations
    (.15)
    .20
    .07Available
      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
    
    $
    1,799,774Net
      operating revenues, excluding depreciation and
amortization
    
    
    169,266
    
    
    240,050
    
    
    297,864
    
    
    182,761
    
    
    889,941Net
      earnings (loss) from continuing operations
    
    
    (3,707
    )
    
    38,422
    
    
    75,367
    
    
    3,943
    
    
    114,025Net
      earnings (loss) available for common shareholders
    
    
    (3,707
    )
    
    34,418
    
    
    71,026
    
    
    (398
    )
    
    101,339Diluted
      net earnings (loss) per share available for common
      shareholders:(1)Continuing
      operations
    
    
    (.05
    )
    
    .45
    
    
    .91
    
    
    (.01
    )
    
    1.30Available
      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
    
    $
    1,188,500Net
      operating revenues, excluding depreciation and
amortization
    
    
    54,464
    
    
    118,031
    
    
    161,400
    
    
    89,509
    
    
    423,404Net
      earnings (loss) from continuing operations
    
    
    (9,186
    )
    
    18,519
    
    
    46,234
    
    
    (11,898
    )
    
    43,669Net
      earnings (loss) from discontinued operations
    
    
    2,691
    
    
    10,900
    
    
    17,665
    
    
    1,264
    
    
    32,520Net
      earnings (loss) available for common shareholders
    
    
    (6,495
    )
    
    29,419
    
    
    63,899
    
    
    (10,634
    )
    
    76,189Diluted
      net earnings (loss) per share available for common
      shareholders:(1)Continuing
      operations
    
    
    (.16
    )
    
    .30
    
    
    .75
    
    
    (.19
    )
    
    .70Discontinued
      operations
    
    
    .05
    
    
    .18
    
    
    .29
    
    
    .02
    
    
    .52Available
      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
    
    $
    968,933Transportation
      and Storage
    
    
    242,743
    
    
    490,883
    
    
    24,522
    
    
    --Total
      segment operating revenues
    
    
    792,089
    
    
    1,795,288
    
    
    1,183,486
    
    
    968,933All
      Other
    
    
    2,249
    
    
    4,486
    
    
    5,014
    
    
    11,681Total
      consolidated operating revenues
    
    $
    794,338
    
    $
    1,799,774
    
    $
    1,188,500
    
    $
    980,614Depreciation
      and amortization:Distribution
    
    $
    32,511
    
    $
    57,601
    
    $
    56,396
    
    $
    53,937Transportation
      and Storage
    
    
    30,159
    
    
    59,988
    
    
    3,197
    
    
    --Total
      segment depreciation andamortization
    
    
    62,670
    
    
    117,589
    
    
    59,593
    
    
    53,937All
      Other
    
    
    306
    
    
    572
    
    
    590
    
    
    2,387Corporate
    
    
    400
    
    
    594
    
    
    459
    
    
    2,665Total
      consolidated depreciation andamortization
    
    $
    63,376
    
    $
    118,755
    
    $
    60,642
    
    $
    58,989





Operating
      income:Distribution
    
    $
    19,396
    
    $
    118,894
    
    $
    142,762
    
    $
    135,502Transportation
      and Storage
    
    
    90,121
    
    
    193,502
    
    
    9,628
    
    
    --Total
      segment operating income
    
    
    109,517
    
    
    312,396
    
    
    152,390
    
    
    135,502All
      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
    
    $
    2,156,106Transportation
      and Storage
    
    
    2,348,354
    
    
    2,197,289
    
    
    2,212,467
    
    
    --Total
      segment assets
    
    
    4,797,104
    
    
    4,429,259
    
    
    4,455,724
    
    
    2,156,106All
      Other
    
    
    40,320
    
    
    42,133
    
    
    50,073
    
    
    53,339Corporate
    
    
    730,865
    
    
    101,066
    
    
    85,141
    
    
    75,173Sale
      of assets - Texas operations
    
    
    --
    
    
    --
    
    
    --
    
    
    395,446Total
      consolidated assets
    
    $
    5,568,289
    
    $
    4,572,458
    
    $
    4,590,938
    
    $
    2,680,064Expenditures
      for long-lived assets:Distribution
    
    $
    56,442
    
    $
    78,791
    
    $
    67,327
    
    $
    68,042Transportation
      and storage
    
    
    111,886
    
    
    131,378
    
    
    5,128
    
    
    --Total
      segment expenditures forlong-lived
      assets
    
    
    168,328
    
    
    210,169
    
    
    72,455
    
    
    68,042All
      other
    
    
    133
    
    
    856
    
    
    1,653
    
    
    1,365Corporate
    
    
    9,976
    
    
    15,028
    
    
    5,622
    
    
    1,291Total
      consolidated expenditures for
      Assetslong-lived
      assets
    
    $
    178,437
    
    $
    226,053
    
    $
    79,730
    
    $
    70,698Reconciliation
      of operating income to earningsfrom
      continuing operations before income taxes:Operating
      income
    
    $
    106,931
    
    $
    305,327
    
    $
    142,364
    
    $
    91,125Interest
    
    
    (64,898
    )
    
    (127,867
    )
    
    (83,343
    )
    
    (90,992
    )Earnings
      from unconsolidatedinvestments
    
    
    4,745
    
    
    200
    
    
    422
    
    
    1,420Dividends
      on preferred securities ofsubsidiary
      trust
    
    
    --
    
    
    --
    
    
    (9,480
    )
    
    (9,480
    )Other
      income, net
    
    
    (18,080
    )
    
    5,468
    
    
    17,979
    
    
    12,858Earnings
      from continuing operationsbefore
      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
    
    
    738,417Operating
      income
    
    
    106,931
    
    
    119,266Earnings
      before income taxes
    
    
    28,698
    
    
    57,077Federal
      and state income taxes
    
    
    (13,927
    )
    
    (22,362
    )Net
      earnings
    
    
    14,771
    
    
    34,715Preferred
      stock dividends
    
    
    (8,683
    )
    
    (4,004
    )Net
      earnings available for common shareholders
    
    
    6,088
    
    
    30,711Net
      earnings available for common shareholders per share:Basic
    
    $
    .07
    
    $
    .41Diluted
    
    $
    .07
    
    $
    .40Weighted
      average shares outstanding:Basic
    
    
    81,995,878
    
    
    75,337,197Diluted
    
    
    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