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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D. C. 20549

                                    FORM 10-K


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

                     For the Fiscal Year Ended June 30, 2004

                                       OR

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

                           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                        (I.R.S.Employer
incorporation or organization)                         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           New York Stock Exchange
  $1 per share
7.55% Depositary Shares           New York Stock Exchange
5.75% Equity 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 contained  herein,  and will not be contained,  to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ___

Indicate  by check mark  whether  the  registrant  is an  Accelerated  Filer (as
defined in Exchange Act Rule 12D-2). Yes X  No
                                        ----  ----
The  aggregate  market value of the Common Stock held by  non-affiliates  of the
Registrant  as of  December  31, 2003 was  $1,002,204,375  (based on the closing
sales  price of Common  Stock on the New York Stock  Exchange  on  December  31,
2003). 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 August 16,
2004 was 81,886,254.

                       DOCUMENTS INCORPORATED BY REFERENCE

Portions  of  the  registrant's  proxy  statement  for  its  annual  meeting  of
stockholders to be held on October 28, 2004, are  incorporated by reference into
Part III.

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<PAGE>



                                     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 is primarily engaged in the transportation,  storage and distribution of
natural  gas  in  the  United  States.  The  Company's  interstate  natural  gas
transportation  and storage  operations are conducted  through Panhandle Eastern
Pipe Line Company, LP and its subsidiaries  (hereafter  collectively referred to
as  Panhandle  Energy),  which  operate  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 regions.  Panhandle Energy also 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 based on current send out
capacity. The Company's local natural gas distribution  operations are conducted
through its three regulated  utility  divisions,  Missouri Gas Energy, PG Energy
and New England Gas Company,  which collectively serve over 960,000 residential,
commercial and industrial customers in Missouri,  Pennsylvania, Rhode Island and
Massachusetts.

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 for
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 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.

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  Federal  Energy
Regulatory  Commission  (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 (Sea Robin),  a Louisiana joint venture and 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
billion  cubic  feet  (Bcf)  per day  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.


<PAGE>

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,   Inc.   (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 Norteno  Pipeline  Company
(Norteno) (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 provided  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
intrastate pipeline that served commercial,  industrial and utility customers in
central,  southern  and coastal  Texas.  SUEI and  Investments  participated  in
energy-related projects  internationally.  Energia 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.  Norteno owned
and operated interstate pipelines that served the gas distribution properties of
Southern  Union Gas and the Public Service  Company of New Mexico.  Norteno 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 million by the end of fiscal year 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 subsequent  strategic  initiatives,  the Company sold certain  non-core
subsidiaries and assets described below during the three-year  period ended June
30, 2004.
<TABLE>
<CAPTION>
                   Subsidiary or Asset Sold               Date Sold       Proceeds         Pre-tax  Gain(Loss)
-----------------------------------------------------    --------------   -------------    --------------------


<S>                                                       <C>              <C>              <C>
ProvEnergy Power Company LLC (a)                          October 2003     $ 2,175,000      $(1,150,000)
PG Energy Services' propane operations (b)                April 2002         2,300,000        1,200,000
Carrizo Springs Pipeline (c)                              December 2001      1,000,000          561,000
South Florida Natural Gas and Atlantic Gas
    Corporation (d)                                       December 2001     10,000,000       (1,500,000)
Morris Merchants, Inc. (e)                                October 2001       1,586,000               --
Valley Propane, Inc. (f)                                  September 2001     5,301,000               --
ProvEnergy Oil Enterprises (g)                            August 2001       15,776,000               --
PG Energy Services' commercial and
    industrial gas marketing contracts                    July 2001          4,972,000        4,653,000
</TABLE>

----------------------------------------------------
(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.


<PAGE>
                                Business Segments

The Company's operations include two reportable segments:

o    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;

o    The  Distribution  segment,   which  is  primarily  engaged  in  the  local
     distribution  of natural gas in  Missouri,  Pennsylvania,  Rhode Island and
     Massachusetts.  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  (which the  Company  formerly  referred to as net  operating  revenues),
assets and other financial  information relating to the All Other category,  see
Note XXI - Reportable Segments).

o    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,  in 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.

o    Fall River Gas Appliance  Company,  Inc. rents water heaters and conversion
     burners (primarily for residential use) to over 16,400 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.

o    Valley  Appliance  and  Merchandising  Company  (VAMCO)  rents  natural gas
     burning  appliances  and offers  appliance  service  contract  programs  to
     residential   customers.   In  fiscal  2002,  VAMCO  provided  construction
     management  services for natural  gas-related  projects to  commercial  and
     industrial customers.

o    PG  Energy  Services,   Inc.  (Energy   Services)  offers  the  inspection,
     maintenance  and servicing of residential  and small  commercial  gas-fired
     equipment to 16,100  residential and commercial  users primarily in central
     and northeastern Pennsylvania.

o    Alternate Energy Corporation is an energy consulting firm that also retains
     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,
Legal, Payroll, Purchasing, Risk Management, Tax and Treasury.


<PAGE>


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

o    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 fiscal 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.

o    Advent Networks,  Inc.  (Advent) -- Southern Union has a $5,433,000  equity
     interest in Advent and holds  $11,500,000 of convertible  notes  receivable
     from Advent.  Additionally, a wholly owned subsidiary of Southern Union has
     guaranteed a $4,000,000 line of credit between Advent and a bank.  Advent's
     UltraBand(TM)  technology is expected to deliver digital broadband services
     40 times faster than digital  subscriber  lines (DSL) or cable modems,  and
     1,000 times faster than dial-up modems, over the "last mile". UltraBand(TM)
     should provide cable network overbuilders a competitive  advantage with its
     capability  to  deliver  content  at a  quality  and speed  that  cannot be
     provided over cable modem.  All of the  convertible  notes bear interest at
     10% per annum and convert into equity at a ratio  determined  upon the next
     equity  financing  of Advent or upon a change of  control  of  Advent.  The
     convertible  notes are due on  demand at the  request  of  Southern  Union.
     Advent is a closely  held,  privately  owned  company and, as such,  has no
     published  market  value.   Certain  Southern  Union  executive   officers,
     directors  and  employees  have  invested  an  aggregate  of  approximately
     $2,600,000 in Advent and  beneficially  own in the aggregate  approximately
     three  percent  equity  ownership   interest  in  Advent  either  directly,
     indirectly  or through a  partnership  unrelated to Southern  Union through
     which such persons vote their beneficial  interest at their own discretion.
     As a result of an early round of  financings,  the Company has the right to
     name one of seven directors to the Advent Board. However,  currently Thomas
     F. Karam and John E. Brennan,  officers and directors of the Company, serve
     as the Company's representatives on the Advent 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.
In fiscal  2004,  this segment  represented  27 percent of the  Company's  total
operating revenues.

Panhandle  Energy  owns  and  operates  a large  natural  gas  pipeline  network
consisting  of more  than  10,000  miles  of  pipeline.  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.

Panhandle Energy has  approximately 87 Bcf of total storage available for use in
connection with its gas transmission systems. Panhandle Energy owns and operates
47 compressor  stations,  and has five gas storage  fields  located in Illinois,
Kansas,  Louisiana,  Michigan and Oklahoma and with a combined  maximum  working
storage  capacity  of 72 Bcf.  Panhandle  Energy also has  contracts  with third
parties that provide for approximately 15 Bcf of storage.

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 sustainable  send out capacity of  approximately  .63
Bcf per  day.  Trunkline  LNG is  currently  in the  process  of  expanding  the
terminal, which will increase sustainable send out capacity to approximately 1.2
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  with an estimated
cost totaling $137 million,  plus capitalized  interest,  by the end of the 2005
calendar year. In February 2004,  Trunkline LNG filed a further  incremental LNG
expansion  project  (Phase II) with FERC and is  awaiting  commission  approval.
Phase II is  estimated  to cost  approximately  $77  million,  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-calendar 2006.
BG LNG Services has contracted for all the proposed additional capacity, subject
to Trunkline LNG achieving certain construction milestones at this facility.

In February 2004,  Trunkline filed an application  with FERC to request approval
of a 30-inch diameter,  23-mile natural gas pipeline loop from the LNG terminal.
The estimated cost of this pipeline expansion is approximately $41 million, plus
capitalized  interest.  The pipeline creates  additional  transport  capacity in
association  with the Trunkline LNG expansion and also includes new and expanded
delivery points with major interstate pipelines.

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.  In fiscal  2004 and 2003 (from  June 12 to June 30,  2003),
Panhandle Energy's combined  throughput was 1,321 trillion British thermal units
(TBtu) and 69 TBtu, respectively.

In fiscal 2004,  Panhandle Energy's  operating  revenues were  $491,083,000,  of
which 86 percent was generated  from  transportation  and storage  services,  12
percent  from LNG  terminalling  services,  and 2 percent  from other  services.
Aggregate sales to Panhandle Energy's top ten customers accounted for 70 percent
of the  segment's  operating  revenues in fiscal 2004 (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 in
fiscal 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.


<PAGE>

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
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,  Rhode  Island and  Massachusetts.  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 960,000 residential,  commercial
and industrial customers through local distribution systems consisting of 14,243
miles of mains, 9,605 miles of service lines and 76 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.  In fiscal 2004, this segment  represented 72 percent of the
Company's total operating revenues.

In fiscal 2004, 2003 and 2002, the  Distribution  segment's  operating  revenues
were  $1,304,000,000,  $1,159,000,000  and $968,900,000,  respectively;  average
customers served totaled  949,978,  944,657 and 935,229,  respectively;  and gas
volumes sold or transported  totaled 173,119 million cubic feet (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 in fiscal 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 503,000 customers in central and western Missouri
(including  Kansas  City,  St.  Joseph,  Joplin  and  Monett)  through  a  local
distribution  system that consists of approximately  8,074 miles of mains, 5,022
miles  of  service  lines  and 47  miles  of  transmission  lines.  Its  service
territories have a total population of approximately  1.5 million.  Missouri Gas
Energy's  natural  gas  rates  are  regulated  by the  Missouri  Public  Service
Commission (MPSC) (see Item 1. Business - Regulation and Rates).

<PAGE>
The Missouri Gas Energy  customers  served,  gas volumes sold or transported and
weather-related information for the past three fiscal years are as follows:
<TABLE>
<CAPTION>
                                                                                     Year  Ended June 30,
                                                                                   -------------------------
                                                                                   2004       2003      2002
                                                                                   ----       ----      ----
<S>                                                                              <C>        <C>        <C>
Average number of customers:
     Residential ............................................................... 432,037    430,861    428,215
     Commercial ................................................................  61,957     60,774     58,749
     Industrial ................................................................      95         99         95
                                                                                --------   --------   --------
         Total average gas sales customers ..................................... 494,089    491,734    487,059
     Transportation customers ..................................................     786        461        378
                                                                                --------   --------   --------
         Total average gas sales and transportation customers .................. 494,875    492,195    487,437
                                                                                ========   ========   ========


Gas sales in millions of cubic feet (MMcf):
     Residential ...............................................................  36,880     39,821     35,039
     Commercial ................................................................  16,026     17,399     15,686
     Industrial ................................................................     338        391        417
                                                                                --------   --------    --------
         Gas sales billed ......................................................  53,244     57,611     51,142
     Net change in unbilled gas sales ..........................................     112         61        (16)
                                                                                --------   --------   --------
         Total gas sales .......................................................  53,356     57,672     51,126
     Gas transported ...........................................................  25,761     26,893     27,324
                                                                                --------   --------   --------
         Total gas sales and gas transported ...................................  79,117     84,565     78,450
                                                                                ========   ========   ========
Weather:
     Degree days (a)............................................................   4,770      5,105      4,419
     Percent of 10-year measure (b).............................................     92%         98%        85%
     Percent of 30-year measure (b).............................................     92%         98%        85%
--------------------------------------------------------------------------------
</TABLE>
(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
approximately   159,000  customers  in  northeastern  and  central  Pennsylvania
(including Wilkes-Barre, Scranton and Williamsport) through a local distribution
system that  consists  of  approximately  2,514  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 past three fiscal years are as follows:
<TABLE>
<CAPTION>
                                                                                        Year Ended June 30,
                                                                                        -------------------
                                                                                     2004      2003      2002
                                                                                     ----      ----      ----
<S>                                                                                <C>        <C>       <C>
Average number of customers:
     Residential ...............................................................   142,422    141,769   141,223
     Commercial ................................................................    14,384     14,141    13,707
     Industrial ................................................................       116        120       104
     Public authorities and other ..............................................       340        337       212
                                                                                  --------   --------  --------
         Total average customers served ........................................   157,262    156,367   155,246
     Transportation customers ..................................................       602        613       624
                                                                                  --------   --------  --------
         Total average gas sales and transportation customers ..................   157,864    156,980   155,870
                                                                                  ========   ========  ========

Gas sales in MMcf:
     Residential ...............................................................    17,133     18,372    15,053
     Commercial ................................................................     6,505      6,732     5,325
     Industrial ................................................................       379        376       277
     Public authorities and other ..............................................       290        334       145
                                                                                  --------   --------  --------
         Gas sales billed ......................................................    24,307     25,814    20,800
     Net change in unbilled gas sales ..........................................        34          4       (22)
                                                                                  --------  ---------  --------

         Total gas sales .......................................................    24,341     25,818    20,778
     Gas transported ...........................................................    26,007     28,366    26,976
                                                                                  --------   --------  --------
         Total gas sales and gas transported ...................................    50,348     54,184    47,754
                                                                                  ========   ========  ========
Weather:
     Degree days................................................................     6,240      6,654     5,373
     Percent of 10-year measure.................................................       100%       109%       89%
     Percent of 30-year measure.................................................       103%       106%       86%
</TABLE>

New England Gas Company - New England Gas Company,  headquartered in Providence,
Rhode  Island,  serves  approximately  301,000  customers  in Rhode  Island  and
Massachusetts  (including Providence,  Newport and Cumberland,  Rhode Island and
Fall  River,  North  Attleboro  and  Somerset,  Massachusetts)  through  a local
distribution  system  that  consists of  approximately  3,655 miles of mains and
3,068 miles of service lines. Its service territories have a total population of
approximately 1.2 million.  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 past three fiscal years are as follows:
<TABLE>
<CAPTION>
                                                                                           Year Ended June 30,
                                                                                           -------------------
                                                                                      2004        2003        2002
                                                                                      ----        ----        ----
<S>                                                                                 <C>          <C>         <C>
Average number of customers:
     Residential ...............................................................    269,926      268,312     265,206
     Commercial ................................................................     25,798       25,442      21,696
     Industrial and irrigation .................................................        226          225       3,472
     Public authorities and other ..............................................         47           41          43
                                                                                   --------     --------    --------
         Total average customers served ........................................    295,997      294,020     290,417
     Transportation customers ..................................................      1,242        1,462       1,505
                                                                                   --------     --------    --------
         Total average gas sales and transportation customers ..................    297,239      295,482     291,922
                                                                                   ========     ========    ========
Gas sales in MMcf:
     Residential ...............................................................     24,194       25,481      19,975
     Commercial ................................................................      9,753        9,725       6,196
     Industrial and irrigation .................................................      1,968        2,055       3,271
     Public authorities and other ..............................................         25           28          23
                                                                                   --------     --------    --------
         Gas sales billed ......................................................     35,940       37,289      29,465
     Net change in unbilled gas sales ..........................................     (1,366)       1,336        (333)
                                                                                   --------     --------    --------
         Total gas sales .......................................................     34,574       38,625      29,132
     Gas transported ...........................................................      9,080       10,959      11,457
                                                                                   --------     --------    --------
         Total gas sales and gas transported ...................................     43,654       49,584      40,589
                                                                                   ========     ========    ========
Weather:
     Degree days................................................................      5,644        6,143       4,980

     Percent of 10-year measure.................................................         98%         111%        88%

     Percent of 30-year measure ................................................        102%         107%        85%

</TABLE>
<PAGE>


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 transportation  contracts.
The Company has been  directly  acquiring  its gas supplies  since the mid-1980s
when  interstate  pipeline  systems  opened  their  systems  for  transportation
service. The Company has the organization,  personnel and equipment necessary to
dispatch and monitor 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  pipeline
companies  beginning in 1992. As a result,  gas  purchasing  and  transportation
decisions and associated risks have been shifted from the pipeline  companies to
the gas  distributors.  The increased  demands on  distributors  to  effectively
manage their gas supply in an  environment  of volatile  gas prices  provides an
advantage to distribution companies such as Southern Union who have demonstrated
a history of contracting  favorable and efficient gas supply  arrangements in an
open market system.

The majority of 2004 gas requirements for the utility operations of Missouri Gas
Energy and PG Energy were  delivered  under short- and long-term  transportation
contracts  through  four major  pipeline  companies.  The  majority  of 2004 gas
requirements  for  the  utility  operations  of New  England  Gas  Company  were
delivered under long-term  transportation  contracts through four major pipeline
companies.  These contracts have various  expiration dates ranging from calendar
year 2005  through  2018.  Missouri  Gas Energy and New England Gas Company have
firm supply commitments for all areas that are supplied with gas purchased under
short- and long-term arrangements. PG Energy has firm supply commitments for all
areas  that are  supplied  with gas  purchased  under  short-term  arrangements.
Missouri Gas Energy,  PG Energy and New England Gas Company hold contract rights
to over 17 Bcf, 11 Bcf and 7 Bcf of storage capacity, respectively, to assist in
meeting peak demands.  Storage capacity in 2004  approximated 31% of the utility
operations' annual gas distribution volumes.

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,  curtailments  of deliveries  to customers  with firm
contracts may be made in accordance with  guidelines  established by appropriate
federal  and  state  regulatory  agencies.  There  have  been no  supply-related
curtailments of deliveries to Missouri Gas Energy, PG Energy, or New England Gas
Company utility sales customers during the last ten years.

Competition

As energy providers, Missouri Gas Energy, PG Energy, and New England Gas Company
have  historically  competed  with  alternative  energy  sources,   particularly
electricity,  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 commercial  customers in the Company's  regulated
utility service areas generally is higher than the effective cost of natural gas
service. There can be no assurance, however, that future fluctuations in gas and
electric costs will not reduce the cost advantage of natural gas service.

Competition between the use of fuel oils, natural gas and propane,  particularly
by industrial and electric generation  customers has 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  arrangement  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 Pennsylvania and New
England than in the Company's Missouri service area;  however,  this competition
affects  the  nationwide  market for  natural  gas.  Additionally,  the  general
economic conditions in the Company's regulated utility service areas continue to
affect  certain  customers and market areas,  thus  impacting the results of the
Company's operations.

The Company's  regulated  utility  operations  are not currently in  significant
direct competition with any other distributors of natural gas to residential and
small commercial customers within their service areas. 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 as well.  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
have 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.

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

Gas service rates are established by regulatory  authorities to permit utilities
the opportunity to recover  operating,  administrative  and financing costs, and
the opportunity to earn a reasonable  return on equity.  Gas costs are billed to
customers  through  purchase  gas  adjustment  (PGA)  clauses,  which permit the
Company to adjust its sales price as the cost of purchased gas changes.  This is
important because the cost of natural gas accounts for a significant  portion of
the Company's total expenses.  The appropriate regulatory authority must receive
notice of such adjustments prior to billing implementation.

Other than in Pennsylvania, the Company supports any service rate changes to its
regulators  using an historic test year of operating  results adjusted to normal
conditions and for any known and measurable revenue or expense changes.  Because
the  regulatory  process has certain  inherent time delays,  rate orders 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, therefore,
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.

Missouri -- On November 4, 2003,  Missouri  Gas Energy  filed a request with the
MPSC to increase base rates by $44,800,000 and to implement a weather mitigation
rate  design  that would  significantly  reduce  the  impact of  weather-related
fluctuations on customer  bills. On January 30, 2004,  Missouri Gas Energy filed
an updated  claim which raised the amount of the base rate  increase  request to
$54,200,000.  As of July 19, 2004,  upon the close of the record and  reflecting
settlement  of  a  number  of  issues,  MGE's  request  stood  at  approximately
$39,000,000  and  the  MPSC  Staff's   recommendation   stood  at  approximately
$13,000,000.  Statutes require that the MPSC reach a decision in the case within
an  eleven-month  period from the  original  filing  date.  It is not  presently
possible to determine what action the MPSC will  ultimately take with respect to
this rate increase request.

Rhode Island -- 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 addition to the regulation of its utility businesses, the Company is affected
by other  regulations,  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.

<PAGE>

                                  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 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.  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  distribution  service territories certain MGP sites are currently the
subject of governmental actions.

The Company's  interstate natural gas  transportation  operations are subject to
federal,  state and local  regulations  regarding  water quality,  hazardous and
solid waste disposal and other environmental matters. The Company 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. The Company communicated with the United States Environmental  Protection
Agency (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.  Some remediation is being
performed by former  Panhandle  Energy  affiliates in accordance  with indemnity
agreements that also indemnify against certain future  environmental  litigation
and claims. The Company is also subject to various federal, state and local laws
and regulations relating to air quality control. These regulations include rules
relating to regional  ozone control and hazardous air  pollutants.  The regional
ozone  control  rules  are  known as State  Implementation  Plans  (SIP) and are
designed to control the release of  nitrogen  oxide (NOx)  compounds.  The rules
related to hazardous  air  pollutants  are known as Maximum  Achievable  Control
Technology  (MACT) rules and 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 - Commitments
and Contingencies.

                                   Real Estate

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

                                    Employees

As of July 31, 2004, the Company had 3,006 employees,  of whom 2,139 are paid on
an hourly  basis and 867 are paid on a salary  basis.  Of the 2,139  hourly paid
employees,  unions  represent  61%. 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--1,862 persons;
Transportation  and  Storage   segment--1,060   persons;  All  Other  subsidiary
operations--20  persons.  In addition,  the corporate  office of Southern  Union
employed a total of 64 persons.

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 fiscal 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 fiscal 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  May  2002;  and  a  four-year   contract  with  one  bargaining  unit
representing  employees  of New England  Gas  Company's  Fall River  operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.

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  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  approximately  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 fiscal 2004 and 2003. During
fiscal  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 fiscal 2002, was settled in May 2002 when
the Company and the bargaining unit agreed to a new five-year contract.

                              Available Information

The Company files annual,  quarterly and special  reports,  proxy statements and
other  information  with the  Securities  and  Exchange  Commission  (SEC).  Any
document  the  Company  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. The
Company's   SEC   filings   are  also   available   at  the  SEC's   website  at
http://www.sec.gov      and     through     the     Company's     website     at
http://www.southernunionco.com.  The information on Southern  Union's website is
not incorporated by reference into and is not made a part of this report.

<PAGE>

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  fiscal  2001,  Power Corp.  constructed  an  additional
45-megawatt,  natural  gas-fired  plant in 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  proceedings.  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.

There were no matters  submitted to a vote of security holders of Southern Union
during the quarter ended June 30, 2004.

                                     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:

                                                                    $/Share
                                                                ---------------
                                                                 High       Low
                                                                ------     -----
July 1 to August 16, 2004...................................$   20.48     $18.00

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

(Quarter Ended)
    June 30, 2003...........................................    16.19      10.98
    March 31, 2003..........................................    15.62      10.95
    December 31, 2002.......................................    15.41       9.21
    September 30, 2002......................................    15.48       9.25

<PAGE>

                                     Holders

As of August 16, 2004,  there were 6,876  holders of record of Southern  Union's
common stock and 81,886,254 shares of Southern Union's common stock outstanding.
The holders of record do not include  persons whose shares are held of record by
a bank,  brokerage  house or clearing  agency,  but does  include any such bank,
brokerage house or clearing agency that is a holder of record.  The shares as of
August 16, 2004 reflect the 5% stock dividend distributed on August 31, 2004, as
further discussed below.

On August 16, 2004, 62,294,648 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 dividends on capital stock.  Under
the most restrictive provisions in effect, Southern Union may not declare or pay
any cash or asset  dividends  on its  common  stock or  acquire or retire any of
Southern Union's common stock, unless no event of default exists and the Company
meets certain  financial ratio  requirements,  which presently are met. Southern
Union's  ability to pay cash  dividends may be limited by debt  restrictions  at
Panhandle  Energy  that  could  limit  Southern  Union's  access  to funds  from
Panhandle Energy for debt service or dividends.

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 the 2003 Stock and
Incentive Plan, and the 1992 Long-Term Stock Incentive Plan (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
generally  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  which were both  assumed  by  Southern  Union  upon the  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 June 30, 2004:

<TABLE>
<CAPTION>
                                                                                   Number of Securities
                                                                                  Remaining Available for
                              Number of Securities                                 Future Issuance Under
                               to be issued Upon           Weighted-Average         Equity Compensation
                                   Exercise of              Exercise Price of    Plans (excluding securities
 Plan Category                 Outstanding Options        Outstanding Options    reflected in first column)
 -------------                 -------------------        -------------------    --------------------------
<S>                                   <C>                        <C>                        <C>
Plans approved by shareholders        3,349,921                  $ 14.36                    6,620,773
Plans not approved by shareholders      664,564                  $  9.70                           --
</TABLE>

<PAGE>


ITEM 6.  Selected Financial Data.
<TABLE>
<CAPTION>
                                                                        As of and for the year ended June 30,
                                                                        -------------------------------------
                                                         2004(a)         2003(a)        2002(b)          2001(c)        2000(d)
                                                         -------         -------        -------          -------        -------
                                                                   (dollars in thousands, except per share amounts)

<S>                                                 <C>              <C>            <C>            <C>              <C>
Total operating revenues.......................     $  1,799,974     $ 1,188,507    $   980,614    $   1,461,811    $   566,833
Net earnings (loss):
     Continuing operations (e).................          101,339          43,669          1,520           40,159        (10,251)
     Discontinued operations (f)...............               --          32,520         18,104           16,524         20,096
     Available for common shareholders.........          101,339          76,189         19,624           57,285          9,845
Net  earnings (loss) per diluted common
share (g):
     Continuing operations ....................             1.30             .70            .02              .64           (.19)
     Discontinued operations...................               --             .52            .29              .27            .37
     Available for common shareholders.........             1.30            1.22            .31              .91            .18

Total assets...................................        4,572,458       4,590,938      2,680,064        2,907,299       2,021,460
Stockholders' equity...........................        1,261,991         920,418        685,346          721,857         735,455
Short-term debt and capital lease
     obligation................................           99,997         734,752        108,203            5,913           2,193
Long-term debt and capital lease
     obligation, excluding current portion.....        2,154,615       1,611,653      1,082,210        1,329,631         733,774
Company-obligated mandatorily
     redeemable preferred securities of
     subsidiary trust..........................               --         100,000        100,000          100,000         100,000

Average customers served (h)...................          948,831         945,705        942,849          970,927         605,000

</TABLE>

(a)  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 are not comparable
     to the same periods in prior years.
(b)  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 fiscal year 2002,
     the Company recorded an after-tax  restructuring charge of $8,990,000.  See
     Note VII - Goodwill and Intangibles and Note XIV - Employee Benefits.
(c)  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 are not comparable to the same periods in prior years.
(d)  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 are not comparable to the same periods in prior years.
(e)  Net earnings  from  continuing  operations is net of dividends on preferred
     stock.
(f)  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.
(g)  Earnings per share for all periods  presented  were  computed  based on the
     weighted  average  number  of  shares of  common  stock  and  common  stock
     equivalents outstanding during the year adjusted for the 5% stock dividends
     distributed on August 31, 2004,  July 31, 2003,  July 15, 2002,  August 30,
     2001 and June 30, 2000.
(h)  Includes average customers served by continuing operations.

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

Management's  Discussion  and Analysis of Results of  Operations  and  Financial
Condition is provided as a supplement to the accompanying consolidated financial
statements and footnotes to help provide an  understanding  of Southern  Union's
financial  condition,  changes in financial condition and results of operations.
The following  section includes an overview of Southern Union's business as well
as recent  developments that the Company believes are important in understanding
its results of operations,  and to anticipate future trends in those operations.
Subsequent   sections  include  an  analysis  of  Southern  Union's  results  of
operations on a  consolidated  basis and on a segment basis for each  reportable
segment,  and  information  relating to Southern  Union's  liquidity and capital
resources,  quantitative and qualitative disclosures about market risk and other
matters.

                                    Overview

Southern Union Company (Southern Union and together with its  subsidiaries,  the
Company) is primarily engaged in the transportation, storage and distribution of
natural  gas  in  the  United  States.  The  Company's  interstate  natural  gas
transportation  and storage  operations are conducted  through Panhandle Energy,
which  operates 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 regions.
The Company's local natural gas  distribution  operations are conducted  through
its three regulated  utility  divisions,  Missouri Gas Energy, PG Energy and New
England  Gas  Company,  which  collectively  serve  over  960,000  customers  in
Missouri, Pennsylvania, Rhode Island and Massachusetts.

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 for 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 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.

Panhandle  Energy is  primarily  engaged in the  interstate  transportation  and
storage  of  natural  gas  and  also  provides   liquefied   natural  gas  (LNG)
terminalling  and  regasification  services  and is  subject  to the  rules  and
regulations of the Federal Energy Regulatory  Commission  (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 (Sea
Robin),  a Louisiana  joint venture and 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 billion cubic feet (Bcf) per day 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.


<PAGE>
Upon  acquiring  Panhandle  Energy it was  determined  that  Panhandle  Energy's
operations  could not be integrated  efficiently into Southern Union, but that a
new operating platform would have to be established.  By doing this at Panhandle
Energy, the Company obviated the need for any corporate  information  technology
allocation and,  established a more efficient platform from which to operate all
of the Company's  businesses.  Direct  integration  savings of $15,000,000  were
expected from this process of which,  substantially,  the entire amount has been
achieved to date.

Effective  January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (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.

                              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

The following  table  provides  selected  financial data regarding the Company's
consolidated results of operations for fiscal 2004, 2003 and 2002:
<TABLE>
<CAPTION>

                                                                                     Years Ended June 30,
                                                                       ------------------------------------------------
                                                                           2004              2003             2002
                                                                       -------------    -------------     -------------
                                                                                    (thousands of dollars)
<S>                                                                    <C>              <C>               <C>
Operating income:
    Distribution segment..........................................     $     118,894    $     142,762     $     135,502
    Transportation and storage segment............................           193,702            9,635                --
    All other.....................................................            (3,514)              13                --
Business restructuring charges....................................                --               --           (29,159)
    Corporate.....................................................            (3,555)         (10,039)          (15,218)
                                                                       -------------    -------------     -------------
       Total operating income.....................................           305,527          142,371            91,125
Other income (expenses):
    Interest......................................................          (127,867)         (83,343)          (90,992)
    Dividends on preferred securities of subsidiary trust.........                --           (9,480)           (9,480)
    Other, net....................................................             5,468           18,394            14,278
                                                                       -------------    -------------     -------------
       Total other expenses, net..................................          (122,399)         (74,429)          (86,194)
                                                                       -------------    -------------     -------------
Federal and state income taxes....................................            69,103           24,273             3,411
                                                                       -------------    -------------     -------------
Net earnings from continuing operations...........................           114,025           43,669             1,520
                                                                       -------------    -------------     -------------
Discontinued operations:
    Earnings from discontinued operations before income taxes.....                --           84,773            29,801
    Federal and state income taxes................................                --           52,253            11,697
                                                                       -------------    -------------     -------------
Net earnings from discontinued operations.........................                --           32,520            18,104
                                                                       -------------    -------------     -------------
Net earnings .....................................................           114,025           76,189            19,624

Preferred stock dividends.........................................           (12,686)              --                --
                                                                       -------------    -------------     -------------
Net earnings available for common shareholders....................     $     101,339    $      76,189     $      19,624
                                                                       =============    =============     =============
</TABLE>

<PAGE>

Net Earnings - 2004 Compared to 2003. Southern Union Company's 2004 (fiscal year
ended June 30) net earnings available for common  shareholders were $101,339,000
($1.30 per diluted  share,  hereafter  referred to as per share),  compared with
$76,189,000  ($1.22  per share) 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) in
2004  compared  with  $43,669,000  ($.70 per share) in 2003.  The  increase  was
primarily due to the following:

o a  $184,067,000  increase  in  operating  income from the  Transportation  and
  Storage  segment (see Business Segment Results -  Transportation  and  Storage
  Segment);

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

o 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:

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

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

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

o a $12,926,000 decrease in other income (see Other Income (Expense), Net);

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

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

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

Net Earnings - 2003 Compared to 2002. Southern Union Company's 2003 net earnings
available for common  shareholders were $76,189,000 ($1.22 per share),  compared
with $19,624,000  ($.31 per share) 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) in
2003  compared  with  $1,520,000  ($.02 per  share) in 2002.  The  increase  was
primarily due to the following:

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

o a $9,635,000  increase in operating income from the Transportation and Storage
  segment (see Business Segment Results - Transportation and Storage Segment);

o a total of  $29,159,000  in business  restructuring  charges,  recorded in the
  first quarter of the fiscal 2002 with no  comparable  charge in fiscal  2003
  (see Business Restructuring Charges);

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

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

o a $4,116,000 increase in other income (see Other Income (Expense), Net).

The above items were  partially  offset by 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) in
2003  compared  with  $18,104,000  ($.29  per  share) 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 in 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: $16.4 million of
voluntary  and  accepted  ERP's,   primarily   through   enhanced  benefit  plan
obligations,  and other employee benefit plan  obligations;  $6.8 million of RIF
within the corporate offices and related employee separation benefits;  and $6.0
million   connected  with  various   business   realignment  and   restructuring
initiatives. All restructuring actions were completed as of June 30, 2002.

Corporate.  Operating  loss  from  Corporate  operations  in 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 in 2003 due to the timing of the Panhandle Energy acquisition.

Operating  loss from Corporate  operations in 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 in 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  bank note (the 2002 Term Note) entered into by the Company
on July 15, 2002 to  refinance a portion of the  $485,000,000  Term Note entered
into by the Company on August 28, 2000 to (i) fund the cash  consideration  paid
to  stockholders  of Fall  River Gas,  ProvEnergy  and  Valley  Resources,  (ii)
refinance  and repay  long-  and  short-term  debt  assumed  in the New  England
Operations,  and (iii)  acquisition  costs of the New England  Operations.  This
decrease in the 2002 Term Note  interest  was due to  reductions  in LIBOR rates
during fiscal 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.

<PAGE>

Interest  expense on short-term  debt in 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 in 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 in 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 in 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 Income (Expense),  Net. Other income, net in 2004 was $5,468,000  compared
with  $18,394,000 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 Gas Corporation (Southwest) litigation.

Other income, net, in 2003 of $18,394,000  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,  in 2002  of  $14,278,000  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, $1,004,000 of realized gains on the sale of investment securities, and
power generation and sales income of $971,000. 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 in 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 in 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 ITEM 7.  Management's  Discussion  and  Analysis  -  Financial
Condition.

Discontinued Operations. Net earnings from discontinued operations in 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.

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 fiscal 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 fiscal 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  May  2002;  and  a  four-year   contract  with  one  bargaining  unit
representing  employees  of New England  Gas  Company's  Fall River  operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.

<PAGE>


Business Segment Results

Distribution Segment -- The Company's  Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and  Massachusetts.  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 960,000  residential,
commercial  and  industrial   customers  through  local   distribution   systems
consisting  of 14,243 miles of mains,  9,605 miles of service lines and 76 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.  In fiscal 2004, this segment
represented 72 percent of the Company's total operating revenues.

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) manage capital  spending and operating  costs
without  sacrificing  customer safety or quality of service;  and (iii) 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 continually  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.

The following table provides summary data regarding the  Distribution  segment's
results of operations for fiscal 2004, 2003 and 2002:
<TABLE>
<CAPTION>

                                                                                     Years Ended June 30,
                                                                       ------------------------------------------------
                                                                           2004              2003             2002
                                                                       -------------    -------------     -------------
                                                                                    (thousands of dollars)
<S>                                                                    <C>              <C>               <C>
Financial Results
Operating revenues................................................     $   1,304,405    $   1,158,964     $     968,933
Cost of gas and other energy......................................          (863,637)        (723,719)         (568,447)
Revenue-related taxes.............................................           (45,395)         (40,485)          (33,410)
                                                                       -------------    -------------     -------------
    Net operating revenues, excluding depreciation and
       amortization...............................................           395,373          394,760           367,076
Operating expenses:
    Operating, maintenance, and general...........................           194,394          171,463           154,906
    Depreciation and amortization.................................            57,601           56,396            53,937
    Taxes other than on income and revenues.......................            24,484           24,139            22,731
                                                                       -------------    -------------     -------------
       Total operating expense....................................           276,479          251,998           231,574
                                                                       -------------    -------------     -------------
       Operating income...........................................     $     118,894    $     142,762     $     135,502
                                                                       =============    =============     =============
Operating Information
Gas sales volumes (MMcf)..........................................           112,271          122,115           101,036
Gas transported volumes (MMcf)....................................            60,848           66,218            65,757
Weather:
    Degree Days:
       Missouri Gas Energy service territories....................             4,770            5,105             4,419
       PG Energy service territories..............................             6,240            6,654             5,373
       New England Gas Company service territories................             5,644            6,143             4,980
    Percent of 30-year measure:
       Missouri Gas Energy service territories....................                92%              98%               85%
       PG Energy service territories..............................               103%             106%               86%
       New England Gas Company service territories................               102%             107%               85%
</TABLE>

<PAGE>

Operating  Revenues.  Operating  revenues in 2004 compared  with 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 thousand cubic feet (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  million cubic feet (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 purchase costs  generally do not directly  affect earnings since these costs
are passed on to customers  pursuant to purchase gas  adjustment  (PGA) 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 5,370 MMcf, or 8%, to 60,848 MMcf
at an average  transportation rate per Mcf of $.58 in 2003 and $.57 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.

Operating revenues in 2003 compared with 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  $7,076,000  increase in gross  receipt  taxes
primarily due to an increase in gas purchase and other energy costs.

Gas  transportation  volumes  in 2003  increased  461 MMcf to 66,218  MMcf at an
average transportation rate per Mcf of $.56 in 2002 and $.58 in 2003.

Net Operating  Revenues.  Net  operating  revenues  (which the Company  formerly
referred to as operating margin) in 2004 increased by $613,000, compared with an
increase of  $27,684,000  in 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 temperatures 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 2004,  2003 and 2002 was
948,300, 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.


<PAGE>
Operating  Expenses.  Operating,   maintenance  and  general  expenses  in  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  in  2004  increased   $1,205,000  to
$57,601,000. The increase was primarily due to normal growth in plant.

Operating,  maintenance and general expenses in 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  in  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 in 2003,
primarily due to an increase in state franchise taxes.

<PAGE>

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. In fiscal 2004, this segment  represented 27
percent of the Company's total operating revenues.

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.

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 fiscal 2004 and 2003 (from June 12 to June 30, 2003).
<TABLE>
<CAPTION>

                                                                                                June 12, 2003
                                                                           Year Ended                to
                                                                          June 30, 2004         June 30, 2003
                                                                          -------------         -------------
                                                                                (thousands of dollars)
<S>                                                                    <C>                   <C>
Financial Results
Natural gas transportation and storage revenues...................     $         423,755     $          20,601
LNG terminalling revenues.........................................                57,988                 3,244
Other revenues  ..................................................                 9,340                   684
                                                                       -----------------     -----------------
    Total operating revenues......................................               491,083                24,529
Operating expenses:
    Operating, maintenance, and general...........................               210,105                10,102
    Depreciation and amortization.................................                59,988                 3,197
    Taxes other than on income and revenues.......................                27,288                 1,595
                                                                       -----------------     -----------------
       Total operating expense....................................               297,381                14,894
                                                                       -----------------     -----------------
       Operating income...........................................     $         193,702     $           9,635
                                                                       =================     =================

Operating Information
Volumes transported (TBtu)........................................                 1,321                     69
</TABLE>

As  a  result  of  the  acquisition,  Panhandle  Energy's  assets  acquired  and
liabilities  assumed were recorded at estimated fair value as of the acquisition
date based on the results of outside appraisals.  The most significant impact of
recording the assets and liabilities at fair value going forward, as compared to
pre-acquisition  operations,  are expected to be higher depreciation expense due
to the step-up of  depreciable  assets,  assignment of purchase price to certain
amortizable  intangible  assets,  and  lower  interest  costs  (though  not cash
payments) for the remaining life of debt due to its revaluation and related debt
premium amortization.


<PAGE>
                         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  payments.
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 Company 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
consummating  business  acquisitions.  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 provided by operating  activities were  $341,050,000 in 2004 compared
with cash flows  provided by operating  activities  of  $55,696,000  in 2003 and
$273,616,000  for 2002.  Cash flows  provided  by  operating  activities  before
changes in operating assets and liabilities for 2004 were $306,675,000  compared
with $147,061,000 and $177,715,000 for 2003 and 2002,  respectively.  Changes in
operating assets and liabilities  provided cash of $34,375,000 in 2004.  Changes
in  operating  assets  and  liabilities  used  cash of  $91,365,000  in 2003 and
provided cash of $95,901,000  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 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.
The Long-Term  Facility  replaced the Company's  $150,000,000  and  $225,000,000
credit facilities that expired on April 1, 2004 and May 29, 2004,  respectively.
The  Company  has  additional  availability  under  uncommitted  line of  credit
facilities  (Uncommitted  Facilities)  with various banks.  Borrowings under the
Long-Term Facility are available for Southern Union's working capital, letter of
credit requirements and other general corporate purposes. The Long-Term Facility
is  subject to a  commitment  fee based on the  rating of the  Company's  senior
unsecured  notes (the Senior Notes).  As of June 30, 2004,  the commitment  fees
were an annualized  0.15%. The Long-Term  Facility  requires the Company to meet
certain  covenants  in order for the  Company  to be able to borrow  under  that
agreement.  A balance of $21,000,000 and $251,500,000 was outstanding  under the
Company's  credit  facilities  at June 30,  2004 and 2003,  respectively.  As of
August  16,  2004,  there was a balance  of  $79,500,000  outstanding  under the
Long-Term Facility.

<PAGE>

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  June  30 are as  follows:
2005--$17,777,000;   2006--$14,708,000;   2007--$13,970,000;  2008--$10,018,000;
2009--$6,549,000 and thereafter $8,102,000.  The Company is also committed under
various  agreements to purchase certain quantities of gas in the future. At June
30,  2004,  the  Company's  Distribution  segment 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 $1,099,972,000.  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  flow  used  in  investing  activities  increased
$35,649,000 to $227,009,000  in 2004. Cash flow used in investing  activities in
2003 increased  $152,134,000 to $191,360,000.  Investing  activity cash flow was
primarily  affected by additions to property,  plant and equipment,  acquisition
and sales of operations, and the settlement of interest rate swaps.

During 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  in  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 30-inch  diameter,  23-mile natural gas pipeline loop from the LNG
terminal in 2004 and 2003, respectively.  The remaining capital expenditures for
the  last  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.  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.

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 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 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  30-inch  diameter,  23-mile  natural gas
pipeline  loop from the LNG  terminal,  excluding  capitalized  interest,  to be
$172,947,000  over the next 3 fiscal years.  These  estimates were developed for
budget planning purposes and are subject to revision.

<PAGE>
On June 24, 2004,  CCE  Holdings,  LLC (CCE  Holdings),  a joint  venture of the
Company and its equity partner, GE Commercial Finance Energy Financial Services,
entered  into a  Purchase  Agreement  to  acquire  for cash  100% of the  equity
interests of CrossCountry  Energy, LLC  (CrossCountry)  from Enron Corp. and its
affiliates  for a  total  transaction  value  of  approximately  $2,350,000,000,
including  assumed debt.  The Purchase  Agreement was granted  "Stalking  Horse"
status by the United States  Bankruptcy  Court for the Southern  District of New
York by an Order  entered  June 24,  2004,  which  Order set forth  certain  bid
procedures by which third-parties may submit higher and/or better offers through
a court mandated auction process. Third-party bids had to be submitted by August
23,  2004 in order to be  eligible  to  participate  in the  September  1,  2004
auction.  If  CCE  Holdings  is  the  successful  bidder,  the  closing  of  the
acquisition will then be subject to approval by certain state regulatory bodies,
in  addition  to  satisfaction  of  additional  closing  conditions.  Closing is
anticipated to occur no later than December 17, 2004. If CCE Holdings is not the
successful  bidder,   approximately  $3,890,000  of  acquisition-related   costs
incurred by the Company in fiscal 2004 and included in the Consolidated  Balance
Sheet at June 30, 2004, would be expensed in fiscal 2005.

CrossCountry  holds  interests in and  operates  Transwestern  Pipeline  Company
(Transwestern),  Citrus Corp.  (Citrus) and Northern  Plains Natural Gas Company
(Northern  Plains).  The pipeline  system owned or operated by  CrossCountry  is
comprised of approximately 9,700 miles of pipeline and approximately 8.5 Bcf per
day of natural gas  capacity.  Transwestern  owns and operates an  approximately
2,400-mile  pipeline that transports natural gas from the San Juan, Anadarko and
Permian Basins to markets in the Mid-Continent,  Texas,  Arizona, New Mexico and
California.  Its bi-directional  flow capabilities  provide flexibility to adapt
rapidly to regional demand. Its customers include local distribution  companies,
producers, marketers, electric power generators and industrial end-users. Citrus
owns Florida Gas Transmission  (FGT) - an approximately  5,000-mile  natural gas
pipeline  extending from south Texas to south Florida with mainline  capacity of
2.1 Bcf per day. FGT has access to diverse natural gas supplies from the Gulf of
Mexico,  Texas  and  Louisiana.  With  over 240  delivery  points  and  delivery
connections to more than 50 natural gas fired electric  generation  plants,  FGT
serves the rapidly growing Florida  peninsula.  Its customers  include  electric
utilities,  independent  power producers,  co-generation  facilities,  municipal
generators and local  distribution  companies.  Northern  Plains holds ownership
interests in Northern  Border  Pipeline  Company,  Midwestern  Gas  Transmission
Company, Viking Gas Transmission Company and Guardian Pipeline, LLC.

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 $10,400,000 in 2005 related to this program
and  approximately  $157,300,000  over the  remaining  life of the program of 15
years.

Financing Activities. Cash flow used in financing activities was $181,067,000 in
2004 compared to cash flow provided by financing  activities of  $222,661,000 in
2003 and  cash  flow  used in  financing  activities  of  $235,609,000  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 current  debt
structure  is  5.45%  (which  includes  interest  and the  amortization  of debt
issuance costs and redemption premiums on refinanced debt).

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, pending
the repayment of the $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 in fiscal 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.  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.

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 June 30, 2004, a balance of $111,087,000 was outstanding on this 2002 Term
Note at an  effective  interest  rate of  2.42%.  The 2002  Term  Note  requires
semi-annual  principal repayments on February 15th and August 15th of each year,
with  payments of  $35,000,000  each being due  February 15, 2005 and August 15,
2005. The remaining  principal  amount of $41,087,000 is due August 26, 2005. 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.

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 has
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.  The  Company  will only  receive  additional
proceeds  from the sale of the 7,850,000  shares of the  Company's  common stock
that were sold through the forward sale  agreements if it settles its obligation
under such agreements  through the physical delivery of shares, in which case it
will  receive  additional  net  proceeds  of  $142,000,000.   The  forward  sale
agreements  are  required  to be settled  within 12 months  from the date of the
offering.  The Company expects that it will only settle its obligation under the
forward  sale  agreements  through  the  physical  delivery  of  shares if it is
successful  in its  attempt to  acquire  CrossCountry  Energy,  LLC (see Item 7.
Management's   Discussion  and  Analysis  -  Liquidity  and  Capital   Resources
(Investing Activities)).

The Company  has an  effective  shelf  registration  statement  on file with the
Securities   and  Exchange   Commission   for  a  total   principal   amount  of
$1,000,000,000  in securities of which  $762,812,500  in securities is available
for  issuance as of August 16,  2004,  which may be issued by the Company in the
form of debt securities, common stock, preferred stock, guarantees,  warrants to
purchase  common stock,  preferred  stock and debt  securities,  stock  purchase
contracts,  stock  purchase  units and  depositary  shares in the event that the
Company elects to offer fractional  interests in preferred stock, and also trust
preferred  securities to be issued by Southern  Union  Financing II and Southern
Union Financing III.  Southern Union may sell such securities up to such amounts
from time to time, at prices determined at the time of any such offering.

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 $58,566,000 at June 30,
2004 and  $7,761,000  at June 30,  2003,  which  guarantee  payment of insurance
claims and other various commitments.

<PAGE>
                                  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  Consolidated  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 70% of  segment
operating  revenues and 19% of total  operating  revenues in fiscal  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 CMS Energy  Corporation,  Panhandle
Energy's former parent,  which accounted for 11% of 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  ten  percent  or more  of the  Company's  total
operating revenues in 2004.

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations. As of June
30, 2004,  the Company had guarantees  related to PEI Power and Advent  Network,
Inc.  (in which  Southern  Union  has an  equity  interest)  of  $8,710,000  and
$4,000,000,  respectively,  letters of credit  related to  insurance  claims and
other  commitments of $58,566,000  and surety bonds related to  construction  or
repair  projects of  approximately  $2,300,000.  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 June 30, 2004:
<TABLE>
<CAPTION>

                                                               Contractual Obligations (thousands of dollars)
                                               --------------------------------------------------------------------------------
                                                                                                                     2010 and
                                                  Total       2005        2006       2007        2008       2009    thereafter
                                               -----------  ----------  --------   ---------  ---------   --------  -----------
<S>                                            <C>          <C>         <C>        <C>        <C>         <C>       <C>
Long-term debt,
   including capital leases (1) (2).........   $ 2,243,374  $   99,997  $ 90,475   $ 565,718  $   1,648   $301,646  $1,183,890
Short-term borrowing,
   including credit facilities (1)..........        21,000      21,000        --          --         --         --          --
Gas purchases (3) ..........................     1,099,972     266,023   196,081     158,678    141,508    127,461     210,221
Missouri Gas Energy Safety Program..........       167,733      10,420    10,524      10,630     10,736     10,843     114,580
Storage contracts (4).......................       447,389      79,790    68,538      63,316     53,075     49,015     133,655
LNG facilities and pipeline expansion.......       172,947     144,789    26,821       1,337         --         --          --
Operating lease payments....................        71,124      17,777    14,708      13,970     10,018      6,549       8,102
Interest payments on debt...................     1,718,510     125,391   122,380     111,114    102,288     89,035   1,168,302
Benefit plan contributions..................        25,657      25,657        --          --         --         --          --
Non-trading derivative liabilities..........        19,405       6,461     6,838       6,106         --         --          --
                                               -----------  ----------  --------   ---------  ---------   --------  ----------
   Total contractual cash obligations.......   $ 5,987,111  $  797,305  $536,365   $ 930,869  $ 319,273  $ 584,549  $2,818,750
                                               ===========  ==========  ========   =========  =========  =========  ==========
</TABLE>
---------------------------------
(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 $16,199,000 of unamortized debt
     premium as of June 30,  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.

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.  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  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 - Commitments 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 disposal and other environmental matters. The Company 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. The Company communicated with the United States Environmental  Protection
Agency (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.  Some remediation is being
performed by former  Panhandle  Energy  affiliates in accordance  with indemnity
agreements that also indemnify against certain future  environmental  litigation
and claims. The Company is also subject to various federal, state and local laws
and regulations relating to air quality control. These regulations include rules
relating to regional  ozone control and hazardous air  pollutants.  The regional
ozone  control  rules  are  known as State  Implementation  Plans  (SIP) and are
designed to control the release of NOx compounds. The rules related to hazardous
air pollutants are known as Maximum  Achievable  Control Technology (MACT) rules
and 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 -
Commitments and Contingencies.

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 by the first  calendar  quarter of 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.

On May 31, 2002, the staff of the MPSC recommended that the Commission  disallow
approximately  $15 million in gas costs incurred  during the period July 1, 2000
through June 30, 2001.  Missouri Gas Energy filed its response in  opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's  assertions.  Missouri Gas Energy intends to vigorously defend itself in
this  proceeding.  This matter  went into  recess  following a hearing in May of
2003.  Following the May hearing,  the Commission staff reduced its disallowance
recommendation to approximately $9.3 million.  The hearing concluded in November
2003 and the matter was fully  submitted to the  Commission in February 2004 and
is awaiting decision by the Commission.

On November 27, 2001,  August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended  that the  Commission  disallow  approximately  $5.9  million,  $5.9
million and $4.3 million,  respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1,  1997  through  June 30,  1998,  respectively.  The  basis of these  proposed
disallowances  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. MGE intends to vigorously defend itself in these proceedings.  On
November 4, 2002, the  Commission  adopted a procedural  schedule  calling for a
hearing in this  matter some time after May 2003.  No date for this  hearing 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.  Panhandle  Energy's  pipelines,  with respect to certain
producer contract settlements, may be contractually required to reimburse or, in
some  instances,  to  indemnify  producers  against  such  royalty  claims.  The
potential  liability of the producers to the  government and of the pipelines to
the producers  involves  complex issues of law and fact which are likely to take
substantial  time  to  resolve.  If  required  to  reimburse  or  indemnify  the
producers,  Panhandle 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.

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,  and not to be  material  to the  Company's  overall
business or financial condition,  results of operations or cash flows. (See Note
XVIII - Commitments and Contingencies.)

Inflation.  The Company  believes that inflation has caused and will continue to
cause increases in certain operating expenses and has required and will continue
to require  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 Company's financial condition and results of
operations  have been and will  continue  to be  dependent  upon the  receipt of
adequate and timely adjustments in rates.

On  November  4,  2003,  Missouri  Gas Energy  filed a request  with the MPSC to
increase base rates by $44,800,000  and to implement a weather  mitigation  rate
design   that  would   significantly   reduce  the  impact  of   weather-related
fluctuations on customer  bills. On January 30, 2004,  Missouri Gas Energy filed
an updated  claim which raised the amount of the base rate  increase  request to
$54,200,000.  As of July 19, 2004,  upon the close of the record and  reflecting
settlement  of  a  number  of  issues,  MGE's  request  stood  at  approximately
$39,000,000  and  the  MPSC  Staff's   recommendation   stood  at  approximately
$13,000,000.  Statutes require that the MPSC reach a decision in the case within
an  eleven-month  period from the  original  filing  date.  It is not  presently
possible to determine what action the MPSC will  ultimately take with respect to
this rate increase request.

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.  Construction on the Trunkline LNG expansion project (Phase I) commenced in
September  2003 and is expected to be completed by the end of the 2005  calendar
year. In February 2004,  Trunkline LNG filed a further incremental LNG expansion
project (Phase II) with FERC and is awaiting commission approval. Phase II 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-calendar 2006.

In February 2004,  Trunkline filed an application  with FERC to request approval
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.

The Company  continues to pursue  certain  changes to rates and rate  structures
that are intended to reduce the  sensitivity  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.

<PAGE>
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  $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,  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 -- As of June 30, 2004,  all  securities  owned by the
Company are accounted  for under the cost method.  These  securities  consist of
common and preferred  stock in non-public  companies  whose value is not readily
determinable.  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 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 June
30, 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  accounts for pension
costs  and  other  postretirement  benefit  costs  in  accordance  with the FASB
Standards  Employers'  Accounting  for Pensions and  Employers'  Accounting  for
Postretirement  Benefits Other Than  Pensions,  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   utilizes   derivative
instruments on a limited basis to manage certain  business risks.  Interest rate
swaps and  treasury  rate  locks are used to reduce  interest  rate risks and to
manage interest expense. Commodity swaps have been utilized to manage price risk
associated  with  certain  energy  contracts.   The  Company  accounts  for  its
derivatives  in accordance  with the FASB  Standard,  Accounting  for Derivative
Instruments  and Hedging  Activities,  as  amended.  Under this  Statement,  all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either:  (i) a hedge of the fair value of a recognized  asset or liability or of
an  unrecognized  firm  commitment  (a fair  value  hedge);  (ii) a  hedge  of a
forecasted  transaction  or of the  variability  of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge),  or
(iii) an instrument that is held for trading or non-hedging  purposes (a trading
or  non-hedging  instrument).  Changes  in the fair value of a  derivative  that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is  attributable to the hedged risk, are recorded in earnings.
Changes in the fair value of a derivative  that qualifies as a cash-flow  hedge,
to the extent that the hedge is effective,  are recorded in other  comprehensive
income,  until  earnings  are affected by the  variability  of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings).  Hedge  ineffectiveness is recorded through
earnings  immediately.  Lastly,  changes in the fair value of derivative trading
and non-hedging instruments 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 has been
accounted for using the purchase  method of  accounting  in accordance  with the
FASB Standard,  Business Combinations.  Under this Statement, the purchase price
paid by the Company,  including  transaction  costs,  was 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.
Determining the fair value of certain assets acquired and liabilities assumed is
judgmental  in nature and often  involves the use of  significant  estimates and
assumptions.  The  accounting  rules  provide a one-year  period  following  the
consummation of an acquisition to finalize the fair value estimates.

Accounting Pronouncements

In  April  2003,  the FASB  issued  Amendment  of  Statement  133 on  Derivative
Instruments  and Hedging  Activities.  The  Statement is effective for contracts
entered  into or  modified  after June 30,  2003 and for  hedging  relationships
designated  after  June  30,  2003.  The  Statement  (i)  clarifies  under  what
circumstances a contract with an initial net investment meets the characteristic
of  a  derivative,  (ii)  clarifies  when  a  derivative  contains  a  financing
component,  (iii)  amends  the  definition  of an  underlying  to  conform it to
language  used in FASB  Interpretation  Guarantor's  Accounting  and  Disclosure
Requirement for  Guarantees,  Including  Indirect  Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement did
not materially change the methods the Company uses to account for and report its
derivatives and hedging activities.

Effective  July 1, 2003, the Company  adopted the FASB standard,  Accounting for
Certain  Financial  Instruments  with  Characteristics  of both  Liabilities and
Equity.  The Statement  establishes  guidelines on how an issuer  classifies and
measures certain financial  instruments with characteristics of both liabilities
and equity. The Statement further defines and requires that certain  instruments
within its scope be classified as liabilities on the financial  statements.  The
adoption  of the  Statement  did not have a  material  impact  on its  financial
position, results of operations or cash flows for the periods presented.

Effective  January 1, 2004 the  Company  adopted the FASB  standard,  Employers'
Disclosures about Pensions and Other  Postretirement  Benefits - an amendment of
FASB  Statements  No.  87,  88,  and  106.  The  Statement  revises   employers'
disclosures  about  pension plans and other  postretirement  benefit  plans.  It
retains  the  disclosure  requirements  contained  in FASB  Statement  No.  132,
Employers' Disclosures about Pensions and Other Postretirement  Benefits,  which
it replaces,  and requires additional disclosure about the assets,  obligations,
cash flows and net periodic  benefit cost of defined  benefit  pension plans and
other defined benefit  postretirement  plans.  The Statement does not change the
measurement or  recognition  of those plans required by FASB  Statements No. 87,
Employers'   Accounting  for  Pensions,   No.  88,  Employers'   Accounting  for
Settlements   and   Curtailments  of  Defined  Benefit  Pension  Plans  and  for
Termination  Benefits,  and No. 106,  Employers'  Accounting for  Postretirement
Benefits Other Than Pensions.

In December 2003, the FASB issued  Consolidation of Variable Interest  Entities.
The  Interpretation  introduced  a new  consolidation  model,  which  determines
control and consolidation based on potential  variability in gains and losses of
the entity being  evaluated for  consolidation.  The  Interpretation  requires a
company to consolidate a variable  interest entity if the company is allocated a
majority of the entity's gains and/or losses, including fees paid by the entity.
The  Interpretation is effective for companies that have an interest in variable
interest  entities or potential  variable interest entities commonly referred to
as  special-purpose  entities  for  periods  ending  after  December  15,  2003.
Application  by  companies  for all  other  types of  entities  is  required  in
financial  statements  for periods  ending after March 15, 2004. The Company has
not identified any material  variable interest entities or interests in variable
interest entities for which the provisions of this Interpretation  would require
a change in the Company's current accounting for such interests.

In March 2004, the Emerging  Issues Task Force (EITF) reached final  consensuses
on Issue 03-6, Participating Securities and the Two-Class Method under FASB 128,
Earnings per Share. The Issue addresses the computation of earnings per share by
companies that have issued securities other than common stock that contractually
entitle the holder to participate in dividends and earnings of the company when,
and if, it declares  dividends on its common  stock.  The Issue is effective for
interim periods  beginning after March 31, 2004. Based on the Company's  capital
structure  at June 30,  2004,  this Issue did not change the method  used by the
Company to calculate its earnings per share for the period ended June 30, 2004.

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  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 Act on the  Company's
post-retirement  healthcare  plan  because  the  employer  is unable to conclude
whether  benefits  provided by the plan are  actuarially  equivalent to Medicare
Part D under the Act. The method of  determining  whether a sponsor's  plan will
qualify for actuarial  equivalency  is pending until the US Department of Health
and Human Services (HHS) completes its interpretative  work on the Act. Once the
interpretative  guidance  is  released by HHS,  if  eligible,  the Company  will
account for the subsidy as an actuarial  gain pursuant to the guidelines of this
standard.

See  the  Notes  to  Consolidated  Financial  Statements  for  other  accounting
pronouncements followed by the Company.

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, the
following:  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  the  Company's   service
territories;  the  achievement of operating  efficiencies  and the purchases and
implementation  of new technologies for attaining such  efficiencies;  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  our  gas  distribution   business;   new
legislation and government  regulations  and proceedings  affecting or involving
the Company;  unanticipated environmental liabilities;  the Company's ability to
comply  with  or  to  challenge   successfully  existing  or  new  environmental
regulations;  changes in  business  strategy  and the  success  of new  business
ventures;  the risk that the  businesses  acquired and any other  businesses  or
investments  that  Southern  Union  has  acquired  or  may  acquire  may  not be
successfully  integrated  with the  businesses  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;  our or  any  of our  subsidiaries  debt  securities  ratings;  the
economic  climate  and  growth  in our  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.  These are
representative   of  the   factors   that  could   affect  the  outcome  of  the
forward-looking  statements.  In addition,  such statements could be affected by
general  industry  and  market  conditions,  and  general  economic  conditions,
including  interest  rate  fluctuations,  federal,  state  and  local  laws  and
regulations  affecting the retail gas industry or the energy industry generally,
and other factors.

<PAGE>


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 June 30, 2004, the Company had issued  fixed-rate  long-term debt aggregating
$1,866,308,000  in principal amount  (excluding  premiums on Panhandle  Energy's
debt  of  $16,199,000)  and  having  a  fair  value  of  $1,959,225,000.   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  $84,263,000  if
interest  rates were to decline by 10% from their  levels at June 30,  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 $398,066,000 at June 30, 2004
and  primarily  consisted  of 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 the
2002 Term Note and the  Long-Term  Facility  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 June 30, 2004 levels,
the  Company's  consolidated  interest  expense  would  increase  by a total  of
approximately $68,000 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, 2003 to June 30, 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 June 30, 2004, the interest rate on the
TIF Debt was 3.25% and estimated  incremental tax revenues are expected to cover
approximately  25% of the fiscal 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 June 30, 2004.  The balance  outstanding on the TIF Debt was $8,710,000 as of
June 30, 2004.

As a result of the  acquisition  of  Panhandle  Energy,  the Company is party to
interest rate swap agreements with an aggregate  notional amount of $197,947,000
as of June 30, 2004 that fix the  interest  rate  applicable  to  floating  rate
long-term debt and which qualify for hedge  accounting.  For the year ended June
30, 2004, the amount of swap ineffectiveness was not significant. As of June 30,
2004,  floating rate  LIBOR-based  interest  payments are exchanged for weighted
fixed rate interest payments of 5.88%,  which does not include the spread on the
underlying variable debt rate of 1.625%.  Interest rate swaps are carried on the
Consolidated  Balance  Sheet  at fair  value  with the  unrealized  gain or loss
adjusted through  accumulated other  comprehensive  income. 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 June 30, 2004 and 2003,
the fair value liability  position of the swaps was $14,445,000 and $26,058,000,
respectively.  As of June 30, 2004 and since the acquisition date, an unrealized
gain of $1,776,000,  net of tax, was included in accumulated other comprehensive
income related to these swaps, of which approximately $1,068,000, net of tax, 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 June 30, 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 an interest rate swap 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 agreement 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 June 30, 2004, the fair value liability  position of the swap was $4,960,000,
which reduced the carrying value of the underlying debt.

During fiscal 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 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 a liability and a matching adjustment to deferred cost of gas of $1,337,000.

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 fiscal years 2004,  2003 and 2002, the Company
recorded $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 $507,000 at June 30, 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 June  30,  2004 and  have  communicated  that
determination to the Audit Committee of our Board of Directors.

Changes in Internal Controls

There have been no significant changes in our internal controls or other factors
that have  materially  affected or are  reasonably  likely to materially  affect
internal controls subsequent to June 30, 2004.

ITEM 9B.  Other Information.

None.

<PAGE>
                                    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 2004 Annual Meeting
of  Stockholders  under  the  captions  Board of  Directors  --  Board  Size and
Composition,   Report  of  the  Audit  Committee,  and  Executive  Officers  and
Compensation -- Executive  Officers Who Are Not Directors and Executive Officers
and Compensation -- Section 16(a) Beneficial Owner Reporting Compliance.

We have adopted a Code of Ethics for Senior Financial Officers, 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 report on
Form 8-K.

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 2004 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 2004 Annual Meeting
of Stockholders  under the captions Executive Officers and Compensation - 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 2004 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 2004 Annual Meeting
of Stockholders under the caption Independent Auditors.

<PAGE>
                                     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
-----------                        -----------

      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  on October  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)    Southern Union Company Bylaws, as amended.  (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.)

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

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

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

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

      4(e)    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(f)    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(g)    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(h)    Form of Amended  and  Restated  Declaration  of Trust of  Southern
              Union  Financing  I.  (Filed as Exhibit  4-D to  Southern  Union's
              Registration Statement on Form S-3 (No. 33-58297) and incorporated
              herein by reference.)

      4(i)    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.)
<PAGE>

Exhibit No.                             Description
-----------                             -----------

      4(j)    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(k)    Form of Southern Union Financing I Preferred Security (included in
              4(g)   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(l)    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(m)    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(n)    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(o)    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(p)    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(q)    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(r)    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(s)    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(t)    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(u)    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(v)    Southern Union is a party to other debt instruments, none of which
              authorizes  the  issuance of debt  securities  in an amount  which
              exceeds 10% of the total assets of Southern Union.  Southern Union
              hereby agrees to furnish a copy of any of these instruments to the
              Commission upon request.

      10(a)   Third  Amended and Restated  Revolving  Credit  Agreement  between
              Southern  Union  Company and the Banks named therein dated May 28,
              2004.
<PAGE>

Exhibit No.                            Description
-----------                            -----------

      10(b)   Amended and Restated Term Loan Credit  Agreement  between Southern
              Union  Company  and the Banks named  therein  dated April 3, 2003.
              (Filed as Exhibit 10(c) to Southern  Union's Annual Report on Form
              10-K for the year ended June 30, 2003 and  incorporated  herein by
              reference.)

      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.)(*)

      14      Code of Ethics.

      21      Subsidiaries of the Company.

      23      Consent of Independent Registered Public Accounting Firm.

Exhibit No.                          Description
-----------                          -----------

      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 June 30, 2004.

Date
Filed                             Description of Filing
-----             --------------------------------------------------------------

04/30/04          Announcement  of  operating  performance  for the quarter- and
                  nine-months  ended March 31,  2004 and 2003 and filing,  under
                  Item 12,  summary  statements  of  income  of  Southern  Union
                  Company  for  the  quarter  ended  March  31,  2004  and  2003
                  (unaudited) and notes thereto.

06/23/04          Announcement  that  CCE  Holdings,  LLC,  a joint  venture  of
                  Southern  Union  and  its 50%  equity  partner  GE  Commercial
                  Finance  Energy  Financial  Services,  submitted  an  offer to
                  acquire 100% of the equity  interests of CrossCountry  Energy,
                  LLC from Enron Corp. and its affiliates.

06/25/04          Announcement  that CCE  Holdings,  LLC entered into a Purchase
                  Agreement  to  acquire   100%  of  the  equity   interests  of
                  CrossCountry  Energy, LLC from Enron Corp. and its affiliates;
                  announcement  that the U.S.  Bankruptcy Court for the Southern
                  District  of  New  York  issued  an  Order   establishing  CCE
                  Holding's  Agreement as the  "Stalking  Horse" bid; and filing
                  under Item 7, the Purchase Agreement among CCE Holdings,  LLC,
                  Enron  Transportation  Services,  LLC, EOC Preferred,  LLC and
                  Enron Corp., dated as of June 24, 2004.

---------------------
(*) Indicates Management Compensation Plan.


<PAGE>


                                   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 August 31, 2004.


                                                   SOUTHERN UNION COMPANY


                                                    By     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 August 31, 2004.

       Signature/Name                                  Title
       --------------                                  -----

     GEORGE L. LINDEMANN*         Chairman of the Board, Chief Executive Officer
                                  and Director

     JOHN E. BRENNAN*             Director

     DAVID BRODSKY*               Director

     FRANK W. DENIUS*             Director

     KURT A. GITTER, M.D.*        Director

     THOMAS F. KARAM              Director
     ---------------------
     Thomas F. Karam

     ADAM M. LINDEMANN*           Director

     GEORGE ROUNTREE, III*        Director

     RONALD W. SIMMS*             Director

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


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


<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




                                                                      Page

Financial Statements:
 Consolidated statement of operations -- years ended
   June 30, 2004, 2003 and 2002..................................     F-2
 Consolidated balance sheet -- June 30, 2004 and 2003............  F-3 to F-4
 Consolidated statement of cash flows -- years ended June 30,
   2004, 2003 and 2002...........................................     F-5
 Consolidated statement of common stockholders' equity -- years
   ended June 30, 2004, 2003 and 2002............................     F-6
 Notes to consolidated financial statements......................  F-7 to F-44
 Report of independent registered public accounting firm.........     F-45


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



<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
                                                                                              Year Ended June 30,
                                                                                 -------------------------------------------
                                                                                       2004          2003          2002
                                                                                 -------------  ------------  --------------
                                                                                 (thousands  of  dollars, except shares and
                                                                                                per share amounts)
<S>                                                                              <C>            <C>           <C>
Operating revenues:
     Gas distribution......................................................      $   1,304,405  $  1,158,964  $     968,933
     Gas transportation and storage........................................            491,083        24,529             --
     Other.................................................................              4,486         5,014         11,681
                                                                                 -------------  ------------  -------------
         Total operating revenues..........................................          1,799,974     1,188,507        980,614

Cost of gas and other energy...............................................           (864,438)     (724,611)      (573,077)
Revenue-related taxes......................................................            (45,395)      (40,485)       (33,409)
                                                                                 -------------  ------------  -------------
         Net operating revenues, excluding depreciation and amortization...            890,141       423,411        374,128

Operating expenses:
     Operating, maintenance and general....................................            411,811       193,745        171,147
     Business restructuring charges........................................                 --            --         29,159
     Depreciation and amortization.........................................            118,755        60,642         58,989
     Taxes, other than on income and revenues..............................             54,048        26,653         23,708
                                                                                 -------------  ------------  -------------
         Total operating expenses..........................................            584,614       281,040        283,003
                                                                                 -------------  ------------  -------------
         Operating income..................................................            305,527       142,371         91,125
                                                                                 -------------  ------------  -------------
Other income (expenses):
     Interest .............................................................           (127,867)      (83,343)       (90,992)
     Dividends on preferred securities of subsidiary trust.................                 --        (9,480)        (9,480)
     Other, net............................................................              5,468        18,394         14,278
                                                                                 -------------  ------------  -------------
         Total other expenses, net.........................................           (122,399)      (74,429)       (86,194)
                                                                                 -------------  ------------  -------------
Earnings from continuing operations before income taxes....................            183,128        67,942          4,931
Federal and state income taxes ............................................             69,103        24,273          3,411
                                                                                 -------------  ------------  -------------
Net earnings from continuing operations....................................            114,025        43,669          1,520
                                                                                 -------------  ------------  -------------
Discontinued operations:
     Earnings from discontinued operations before income taxes.............                 --        84,773         29,801
     Federal and state income taxes........................................                 --        52,253         11,697
                                                                                 -------------  ------------  -------------
Net earnings from discontinued operations..................................                 --        32,520         18,104
                                                                                 -------------  ------------  -------------
Net earnings  .............................................................            114,025        76,189         19,624
Preferred stock dividends..................................................            (12,686)           --             --
                                                                                 -------------- ------------  -------------
Net earnings available for common shareholders.............................      $     101,339  $     76,189  $      19,624

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

Net earnings available for common shareholders per share:
     Basic.................................................................      $        1.34  $       1.26  $        0.33
                                                                                 =============  ============= =============
     Diluted...............................................................      $        1.30  $       1.22  $        0.31
                                                                                 =============  ============= =============
Weighted average shares outstanding:
     Basic.................................................................         75,442,238     60,584,293    59,420,048
                                                                                 =============  ============= =============

     Diluted...............................................................         77,694,532     62,523,107    62,596,874
                                                                                 =============  ============= =============
</TABLE>

                             See accompanying notes.

<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEET



                                     ASSETS


<TABLE>
<CAPTION>

                                                                                                          June 30,
                                                                                            ---------------------------------
                                                                                                   2004             2003
                                                                                            ---------------------------------

                                                                                                  (thousands of dollars)
<S>                                                                                         <C>              <C>
Property, plant and equipment:
     Plant in service.................................................................      $    3,772,616   $    3,710,541
     Construction work in progress....................................................             169,264           75,484
                                                                                            --------------   --------------
                                                                                                 3,941,880        3,786,025
         Less accumulated depreciation and amortization...............................            (734,367)        (641,225)
                                                                                            --------------   --------------

         Net property, plant and equipment............................................           3,207,513        3,144,800

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

Goodwill, net of accumulated amortization of $27,510..................................             640,547          642,921

Deferred charges......................................................................             190,735          188,261

Investment securities, at cost........................................................               8,038            9,641

Other.................................................................................              69,896           73,674












                                                                                            --------------   --------------
         Total assets.................................................................      $    4,572,458   $    4,590,938
                                                                                            ==============   ==============
</TABLE>

                             See accompanying notes.

<PAGE>

                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                     CONSOLIDATED BALANCE SHEET (Continued)



                      STOCKHOLDERS' EQUITY AND LIABILITIES
<TABLE>
<CAPTION>

                                                                                                         June 30,
                                                                                             ------------------------------
                                                                                                    2004            2003
                                                                                             ------------------------------
                                                                                                 (thousands of dollars)
<S>                                                                                          <C>              <C>
Stockholders' equity:
     Common stock, $1 par value; authorized 200,000,000 shares;
         issued 77,140,087 shares at June 30, 2004.....................................      $      77,141    $      73,074
     Preferred stock, no par value; authorized 6,000,000 shares;
         issued 920,000 shares at June 30, 2004........................................            230,000               --
     Premium on capital stock..........................................................            975,104          909,191
     Less treasury stock: 404,536 and 282,333 shares, respectively,
         at cost.......................................................................            (12,870)         (10,467)
     Less common stock held in trust: 1,089,147 and 1,061,656 shares,
         respectively..................................................................            (15,812)         (15,617)
     Deferred compensation plans.......................................................             11,960            9,960
     Accumulated other comprehensive income (loss).....................................            (50,224)         (62,579)
     Retained earnings.................................................................             46,692           16,856
                                                                                             -------------    -------------
     Total stockholders' equity........................................................          1,261,991          920,418

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

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

         Total capitalization..........................................................          3,416,606        2,632,071

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

         Total current liabilities.....................................................            513,946        1,354,006

Deferred credits.......................................................................            292,946          322,154

Accumulated deferred income taxes......................................................            348,960          282,707

Commitments and contingencies..........................................................
                                                                                             -------------    -------------
         Total stockholders' equity and liabilities....................................      $   4,572,458    $   4,590,938
                                                                                             =============    =============
</TABLE>


                             See accompanying notes.

<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>

                                                                                              Year Ended June 30,
                                                                                 -------------------------------------------
                                                                                        2004         2003           2002
                                                                                 -------------------------------------------
                                                                                             (thousands of dollars)
<S>                                                                              <C>               <C>           <C>
Cash flows from (used in) operating activities:
     Net earnings ........................................................       $   114,025      $ 76,189      $  19,624
     Adjustments to reconcile  net earnings to net cash flows  provided by
        (used in) operating activities:
         Depreciation and amortization....................................           118,755         60,642         58,989
Amortization of debt premium..............................................           (14,243)        (1,307)            --
         Deferred income taxes............................................            67,455         78,747         28,397
Provision for bad debts...................................................            21,216         17,873         12,260
Provision for impairment of other assets..................................             1,603             --         10,380
         Financial derivative trading gains...............................              (605)          (605)        (6,204)
Amortization of debt expense..............................................             4,143          2,919          2,936
Gain on sale of subsidiaries and other assets.............................                --        (62,992)        (6,414)
         Loss on sale of subsidiaries.....................................             1,150             --          1,500
         Gain on settlement of interest rate swaps........................                --             --        (17,166)
         Gain on extinguishment of debt...................................            (6,354)            --             --
         Business restructuring charges...................................                --             --         24,440
         Net cash provided (used by) assets held for sale.................                --        (23,698)        48,618
         Other ...........................................................              (470)          (707)           355
         Changes in operating assets and liabilities, net of
            acquisitions:
              Accounts receivable, billed and unbilled....................            (6,181)       (48,520)        71,932
              Gas imbalance receivable....................................            20,341          6,330             --
              Accounts payable............................................             9,469         22,728        (11,965)
              Gas imbalance payable.......................................            (1,278)         4,851             --
              Customer deposits...........................................              (542)         5,013            (53)
              Deferred gas purchase costs.................................            20,670        (21,006)        53,436
              Inventories.................................................           (25,824)       (34,583)         1,044
              Deferred charges and credits................................            13,773        (12,561)        16,804
              Prepaids and other current assets...........................             8,978         2,541         (3,735)
              Taxes and other current liabilities.........................            (5,031)       (16,158)       (31,562)
                                                                                ------------    -----------    -----------
         Net cash flows provided by operating activities..................           341,050         55,696        273,616
                                                                                ------------    -----------    -----------
Cash flows (used in) provided by investing activities:
     Additions to property, plant and equipment...........................          (226,053)       (79,730)       (70,698)
Acquisition of operations, net of cash received...........................                --       (522,316)            --
     Notes receivable.....................................................            (2,000)        (6,750)        (2,750)
     Purchase of investment securities....................................                --             --           (938)
Customer advances ........................................................            (3,600)        (9,619)          (403)
     Proceeds from sale of subsidiaries and other assets..................             2,175        437,000         40,935
Proceeds from sale of interest rate swaps.................................                --             --         17,166
     Net cash used in assets held for sale................................                --        (13,410)       (23,215)
     Other................................................................             2,469          3,465            677
                                                                                ------------   ------------   ------------
         Net cash flows used in investing activities......................          (227,009)      (191,360)       (39,226)
                                                                                ------------   ------------   ------------
Cash flows (used in) provided by financing activities:
     Issuance of long-term debt...........................................           750,000        311,087             --
Issuance costs of debt....................................................            (8,530)          (313)          (921)
     Issuance of preferred stock..........................................           230,000             --             --
     Issuance costs of preferred stock....................................            (6,590)            --             --
     Issuance of common stock.............................................                --        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....................................            (8,393)            --             --
     Repayment of debt and capital lease obligation.......................          (908,773)      (500,135)      (145,131)
Net (payments) borrowings under revolving credit facilities...............          (230,500)       119,700        (58,800)
Proceeds from exercise of stock options...................................             4,122          3,047          8,346
     Other................................................................                --          1,217          2,529
                                                                                ------------   ------------   ------------
Net cash flows (used in) provided by financing activities.................          (181,067)       222,661       (235,609)
                                                                                -------------  ------------   ------------
Change in cash and cash equivalents.......................................           (67,026)        86,997         (1,219)
Cash and cash equivalents at beginning of year............................            86,997             --          1,219
                                                                                ------------   ------------   ------------
Cash and cash equivalents at end of year..................................      $     19,971   $     86,997   $         --
                                                                                ============   ============   ============
</TABLE>
Cash paid for interest,  net of amounts capitalized,  in 2004, 2003 and 2002 was
$143,715,000,  $90,462,000  and  $99,643,000,  respectively.  Cash  refunded for
income  taxes in 2004 and 2002 was  $10,875,000  and  $4,214,000,  respectively,
while cash paid for income taxes in 2003 was $2,351,000.

                             See accompanying notes.



                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                 CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
                                                                                              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)

<S>          <C>                  <C>        <C>           <C>         <C>         <C>          <C>        <C>           <C>
Balance July 1, 2001              $ 54,553   $       --    $ 676,324   $  (15,869) $ (11,697)   $  13,443  $    5,103    $  721,857
 Comprehensive income:
  Net earnings                           --          --           --           --         --           --      19,624        19,624
  Unrealized loss in investment
   securities, net of tax benefit        --          --           --           --         --      (18,249)         --       (18,249)
  Minimum pension liability
   adjustment, net of tax benefit        --          --           --           --         --      (10,498)         --       (10,498)
  Unrealized gain on hedging
   activities, net of tax                --          --           --           --         --          804          --           804
                                                                                                                          ---------
  Comprehensive income (loss)                                                                                                (8,319)
 Payment on note receivable              --          --          202           --         --           --          --           202
 Purchase of treasury stock              --          --           --      (41,632)        --           --          --       (41,632)
 5% stock dividend                    2,618          --       22,091           --         --           --     (24,727)          (18)
 Stock compensation plan                 --          --        1,248           --      1,257           --          --         2,505
 Sale of common stock held in trust      --          --           26           --      1,945           --          --         1,971
 Exercise of stock options              884          --        8,021         (172)        47           --          --         8,780
                                   --------     -------    ---------    ---------  ---------    ---------   ---------     ---------
Balance June 30, 2002                58,055          --      707,912      (57,673)    (8,448)     (14,500)         --       685,346
 Comprehensive income (loss):
  Net earnings                           --          --          --            --         --           --      76,189        76,189
  Unrealized loss in investment
   securities, net of tax benefit        --          --          --            --         --         (581)         --          (581)
  Minimum pension liability
   adjustment, net of tax benefit        --          --          --            --         --      (41,930)         --       (41,930)
  Unrealized loss on hedging
   activities, net of tax benefit        --          --          --            --         --       (5,568)         --        (5,568)
                                                                                                                          ---------
  Comprehensive income                                                                                                       28,110
                                                                                                                          ---------
 Payment on note receivable              --          --         305            --         --           --          --           305
 Purchase of treasury stock              --          --          --        (2,181)        --           --          --        (2,181)
 5% stock dividend                    3,468          --      55,832            --         --           --     (59,333)          (33)
 Stock compensation plan                 --          --         480            --        737           --          --         1,217
 Issuance of stock for acquisition       --          --          --        48,900         --           --          --        48,900
 Issuance of common stock            10,925          --     157,757            --         --           --          --       168,682
 Issuance costs of equity units          --          --      (3,443)           --         --           --          --        (3,443)
 Contract adjustment payment             --          --     (11,713)           --         --           --          --       (11,713)
 Sale of common stock held in trust      --          --        (243)           --      2,424           --          --         2,181
 Exercise of stock options              626          --       2,304           487       (370)          --          --         3,047
                                   --------    --------    --------      --------   --------     --------    --------     ---------
Balance June 30, 2003                73,074          --     909,191       (10,467)    (5,657)     (62,579)     16,856       920,418

 Comprehensive income (loss):
  Net earnings                           --          --          --            --         --           --     114,025       114,025
  Unrealized loss in investment
   securities, net of tax benefit        --          --          --            --         --          (21)         --           (21)
  Minimum pension liability
   adjustment, net of tax                --          --          --            --         --       10,768          --        10,768
  Unrealized gain on hedging
   activities, net of tax                --          --          --            --         --        1,608          --         1,608
                                                                                                                          ---------
  Comprehensive income                                                                                                      126,380
                                                                                                                          ---------
Preferred stock dividends                --          --          --            --         --          --      (12,686)      (12,686)
Payment on note receivable               --          --         347            --         --          --           --           347
Purchase of treasury stock               --          --          --        (2,403)        --          --           --        (2,403)
5% stock dividend                     3,656          --      67,847            --         --          --      (71,503)           --
Sale of common stock held in trust       --          --         598            --      1,805          --           --         2,403
Issuance of preferred stock              --     230,000      (6,590)           --         --          --           --       223,410
Exercise of stock options               411          --       3,711            --         --          --           --         4,122
                                   --------  ----------   ---------    ----------   --------   -----------  ----------   ----------
Balance June 30, 2004              $ 77,141  $  230,000   $ 975,104    $  (12,870)  $ (3,852)  $   (50,224) $   46,692   $1,261,991
                                   ========  ==========   =========    ==========   ========   ===========  ==========   ==========
</TABLE>
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.

<PAGE>




                     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) is primarily engaged in the transportation,  storage
and distribution of natural gas in the United States.  The Company's  interstate
natural  gas   transportation  and  storage  operations  are  conducted  through
Panhandle Energy,  which operates 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 regions. The Company's local natural gas distribution operations are
conducted through its three regulated utility divisions, Missouri Gas Energy, PG
Energy and New  England  Gas  Company,  which  collectively  serve over  960,000
customers in Missouri, Pennsylvania, Rhode Island and Massachusetts.

Basis of Presentation.  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, other
than variable interest entities,  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 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.

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 the  transportation,  storage and distribution of natural
gas in the United  States and  reports  these  operations  under two  reportable
segments: the Transportation and Storage segment and the Distribution segment.

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.
The Company's  operating revenue and other financial  information by segment for
fiscal 2004, 2003 and 2002 are presented in Note XXI -- Reportable Segments.


<PAGE>

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. The Company's operating revenues
and other  financial  information by segment for fiscal 2004,  2003 and 2002 are
presented in Note XXI -- Reportable Segments.

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:
<TABLE>
<CAPTION>

                                                                                Year Ended June 30,
                                                                       -----------------------------------
                                                                          2004         2003         2002
                                                                       ---------    ---------    ---------
<S>                                                                    <C>          <C>          <C>
Net earnings, as reported...........................................   $ 114,025    $  76,189    $  19,624
Add stock-based employee compensation expense
    included in reported net earnings, net of related taxes.........          --           --           --
Deduct total stock-based employee compensation
    expense determined under fair value based method
    for all awards, net of related taxes............................       1,699        1,373          953
                                                                       ---------    ---------    ---------
Pro forma net earnings..............................................   $ 112,326    $  74,816    $  18,671
                                                                       =========    =========    =========

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

Diluted -- as reported..............................................        1.30         1.22         0.31
Diluted -- pro forma................................................        1.29         1.21         0.30
</TABLE>

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 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 2004 and 2002 were $7.35 and $6.92,
respectively. There were no options granted above fair market value at the grant
date during 2004 and 2002, respectively. No options were granted in 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 available for common shareholders, unrealized holding gains and
losses on investment  securities,  minimum  pension  liability  adjustments  and
unrealized gain (loss) on hedging activities,  all of which are presented in the
Consolidated Statement of Stockholders' Equity.

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


<PAGE>


<TABLE>
<CAPTION>


                                                                              Year Ended June 30,
                                                                      ----------------------------------
                                                                          2004         2003       2002
                                                                      ----------------------------------

<S>                                                                    <C>         <C>         <C>
Net earnings ........................................................  $ 114,025   $  76,189   $  19,624
Other comprehensive income (loss):
   Unrealized loss in investment securities, net of tax benefit .....        (21)       (581)    (18,249)
   Unrealized gain (loss) on hedging activities, net of tax (benefit)      1,608      (5,568)        804
   Minimum pension liability adjustment, net of tax (benefit)  ......     10,768     (41,930)    (10,498)
                                                                       ---------   ---------   ---------
Other comprehensive income (loss) ...................................     12,355     (48,079)    (27,943)
                                                                       ---------   ---------   ---------

Comprehensive income (loss) .........................................  $ 126,380   $  28,110   $  (8,319)
                                                                       =========   =========   =========
</TABLE>
Accumulated  other  comprehensive  income (loss)  reflected in the  Consolidated
Balance Sheet at June 30, 2004 and 2003 includes  unrealized gains and losses on
hedging  activities and investment  securities,  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 has recorded an allowance for
doubtful   accounts,   totaling   $13,502,000,   $16,823,000,   $15,324,000  and
$28,347,000 at June 30, 2004, 2003, 2002 and 2001, respectively, relating to its
Distribution  segment trade receivables.  The allowance for doubtful accounts is
adjusted  for changes in  estimated  uncollectible  accounts and reduced for the
write-off of trade receivables.

In the Transportation and Storage segment, aggregate sales to Panhandle Energy's
top 10 customers  accounted for 70% of segment operating revenues and 19% of the
Company's  total  operating  revenues in fiscal  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 CMS Energy  Corporation,  Panhandle  Energy's
former parent,  which 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  in 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 has  recorded an allowance  for doubtful  accounts
totaling  $1,422,000  and  $4,138,000  at June 30, 2004 and 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 June 30, 2004 and 2003 was $116,292,000 and $117,679,000,  respectively,  and
consisted of 19,918,000 and 20,853,000  million  British  thermal units (MMBtu),
respectively.

In the Transportation and Storage segment,  inventories  consist of gas held for
operations and materials and supplies. All gas held for operations and materials
and supplies  purchased  are  recorded 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 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.

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,  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. See Note VII - Goodwill and Intangibles.

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

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.
Trunkline  records an asset whenever fuel is due from customers from prior under
recovery based on contractual and specific tariff provisions,  which support the
treatment as an asset.  Panhandle  Energy's other  companies that are subject to
fuel  tracker  provisions  record an expense when fuel is under  recovered.  The
pipelines' fuel reimbursement is in-kind and non-discountable.

Interest  Cost  Capitalized.   The  Company  capitalizes   interest  on  certain
qualifying  assets  that are  undergoing  activities  to prepare  them for their
intended use in accordance  with 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  in accordance  with the FASB  Standard,  Accounting  for Derivative
Instruments  and Hedging  Activities,  as  amended.  Under this  Statement,  all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either:  (i) a hedge of the fair value of a recognized  asset or liability or of
an  unrecognized  firm  commitment  (a fair  value  hedge);  (ii) a  hedge  of a
forecasted  transaction  or of the  variability  of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge);  or
(iii) an instrument that is held for trading or non-hedging  purposes (a trading
or  non-hedging  instrument).  Changes  in the fair value of a  derivative  that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is  attributable  to the hedged risk are recorded in earnings.
Changes in the fair value of a derivative  that qualifies as a cash-flow  hedge,
to the extent that the hedge is effective,  are recorded in other  comprehensive
income,  until  earnings  are affected by the  variability  of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings).  Hedge  ineffectiveness is recorded through
earnings  immediately.  Lastly,  changes in the fair value of derivative trading
and non-hedging instruments 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.

The Company utilizes derivative instruments on a limited basis to manage certain
business  risks.  Interest rate swaps and treasury rate locks are used to reduce
interest rate risks and to manage  interest  expense.  Commodity swaps have been
employed to manage price risk associated with certain energy contracts.

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
$6,407,000 and $6,757,000 as of June 30, 2004 and 2003, respectively. During the
year ended June 30, 2004,  changes in the carrying  amount of the ARO  liability
were attributable to $395,000 of additional  liabilities incurred,  and $628,000
of  accretion  expense.   Liabilities  settled  and  cash  flow  revisions  were
$1,373,000 for fiscal 2004.

In fiscal 2003, the Company reclassified  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
represented other regulatory obligations.

New Pronouncements.

In  April  2003,  the FASB  issued  Amendment  of  Statement  133 on  Derivative
Instruments  and Hedging  Activities.  The  Statement is effective for contracts
entered  into or  modified  after June 30,  2003 and for  hedging  relationships
designated  after  June  30,  2003.  The  Statement  (i)  clarifies  under  what
circumstances a contract with an initial net investment meets the characteristic
of  a  derivative,  (ii)  clarifies  when  a  derivative  contains  a  financing
component,  (iii)  amends  the  definition  of an  underlying  to  conform it to
language  used in FASB  Interpretation  Guarantor's  Accounting  and  Disclosure
Requirement for  Guarantees,  Including  Indirect  Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement did
not materially change the methods the Company uses to account for and report its
derivatives and hedging activities.

Effective  July 1, 2003, the Company  adopted the FASB Standard,  Accounting for
Certain  Financial  Instruments  with  Characteristics  of both  Liabilities and
Equity.  The Statement  establishes  guidelines on how an issuer  classifies and
measures certain financial  instruments with characteristics of both liabilities
and equity. The Statement further defines and requires that certain  instruments
within its scope be classified as liabilities on the financial  statements.  The
adoption  of the  Statement  did not have a  material  impact  on the  Company's
financial  position,  results  of  operations  or cash  flows  for  the  periods
presented.

Effective  January 1, 2004, the Company  adopted the FASB  Standard,  Employers'
Disclosures about Pensions and Other  Postretirement  Benefits - an amendment of
FASB  Statements  No.  87,  88,  and  106.  The  Statement  revises   employers'
disclosures  about  pension plans and other  postretirement  benefit  plans.  It
retains  the  disclosure  requirements  contained  in FASB  Statement  No.  132,
Employers' Disclosures about Pensions and Other Postretirement  Benefits,  which
it replaces,  and requires additional disclosure about the assets,  obligations,
cash flows and net periodic  benefit cost of defined  benefit  pension plans and
other defined benefit  postretirement  plans.  The Statement does not change the
measurement or  recognition  of those plans required by FASB  Statements No. 87,
Employers'   Accounting  for  Pensions,   No.  88,  Employers'   Accounting  for
Settlements   and   Curtailments  of  Defined  Benefit  Pension  Plans  and  for
Termination  Benefits,  and No. 106,  Employers'  Accounting for  Postretirement
Benefits Other Than Pensions.

In December 2003, the FASB issued  Consolidation of Variable Interest  Entities.
The  Interpretation  introduced  a new  consolidation  model,  which  determines
control and consolidation based on potential  variability in gains and losses of
the entity being  evaluated for  consolidation.  The  Interpretation  requires a
company to consolidate a variable  interest entity if the company is allocated a
majority of the entity's gains and/or losses, including fees paid by the entity.
The  Interpretation is effective for companies that have an interest in variable
interest  entities or potential  variable interest entities commonly referred to
as  special-purpose  entities  for  periods  ending  after  December  15,  2003.
Application  by  companies  for all  other  types of  entities  is  required  in
financial  statements  for periods  ending after March 15, 2004. The Company has
not identified any material  variable interest entities or interests in variable
interest entities for which the provisions of this Interpretation  would require
a change in the Company's current accounting for such interests.

In March 2004, the Emerging  Issues Task Force (EITF) reached final  consensuses
on Issue 03-6, Participating Securities and the Two-Class Method under FASB 128,
Earnings per Share. The Issue addresses the computation of earnings per share by
companies that have issued securities other than common stock that contractually
entitle the holder to participate in dividends and earnings of the company when,
and if, it declares  dividends on its common  stock.  The Issue is effective for
interim periods  beginning after March 31, 2004. Based on the Company's  capital
structure  at June 30,  2004,  this Issue did not change the method  used by the
Company to calculate its earnings per share for the period ended June 30, 2004.

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  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 Act on the  Company's
post-retirement  healthcare  plan  because  the  employer  is unable to conclude
whether  benefits  provided by the plan are  actuarially  equivalent to Medicare
Part D under the Act. The method of  determining  whether a sponsor's  plan will
qualify for actuarial  equivalency  is pending until the US Department of Health
and Human Services (HHS) completes its interpretative  work on the Act. Once the
interpretative  guidance  is  released by HHS,  if  eligible,  the Company  will
account for the subsidy as an actuarial  gain pursuant to the guidelines of this
standard.

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.


<PAGE>

                            II Acquisitions and Sales

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 for 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 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.

Panhandle  Energy is  primarily  engaged in the  interstate  transportation  and
storage  of  natural  gas  and  also  provides   liquefied   natural  gas  (LNG)
terminalling  and  regasification  services  and is  subject  to the  rules  and
regulations of the Federal Energy Regulatory  Commission  (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 (Sea
Robin),  a Louisiana  joint venture and 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 billion cubic feet (Bcf) per day 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 during fiscal 2004.

                                                               At June 11, 2003
                                                               ----------------
                                                                 (in thousands)

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

(1) 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, Inc. (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 commercial 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.


<TABLE>
<CAPTION>
                                                                            (Unaudited)
                                                                        Year Ended June 30,
                                                                        2003           2002
                                                                   -------------  --------------
<S>                                                                 <C>            <C>
Operating revenues..........................................        $  1,671,114   $   1,467,630
Net earnings from continuing operations.....................              132,458         56,073
Net earnings per share from continuing operations:
     Basic..................................................                 1.76           0.75
     Diluted................................................                 1.72           0.72
</TABLE>

                         III Other Income (Expense), Net

Other income in 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 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  in 2003 of  $18,394,000  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 in 2002 of  $14,278,000  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 by various operating subsidiaries, a gain of $1,200,000
realized  through the sale of the  propane  assets of PG Energy  Services  Inc.,
$1,004,000  of  realized  gains on the sale of a  portion  of  Southern  Union's
holdings  in  Capstone,  and  power  generation  and sales  income  of  $971,000
primarily from PEI Power  Corporation.  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
ongoing  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  investments  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.

                              V Earnings Per Share

The following  table  summarizes  the Company's  basic and diluted  earnings per
share calculations for 2004, 2003, and 2002:
<TABLE>
<CAPTION>

                                                                                    Year Ended June 30,
                                                                           -------------------------------------
                                                                               2004         2003         2002
                                                                           -----------  -----------  -----------
<S>                                                                        <C>          <C>          <C>
Net earnings available for common shareholders
     from continuing operations net of dividends on preferred stock .....  $   101,339  $    43,669  $     1,520
Net earnings from discontinued operations ...............................         --         32,520       18,104
                                                                           -----------  -----------  -----------
Net earnings available for common shareholders ..........................  $   101,339  $    76,189  $    19,624
                                                                           ===========  ===========  ===========

Weighted average shares outstanding -- basic ............................   75,442,238   60,584,293   59,420,048
                                                                            ==========   ==========   ==========

Weighted average shares outstanding -- diluted ..........................   77,694,532   62,523,107   62,596,874
                                                                            ==========   ==========   ==========

Basic earnings per share:
    Net earnings available for common shareholders
       from continuing operations net of dividends on preferred stock....  $      1.34   $     0.72   $      0.03
    Net earnings from discontinued operations............................           --         0.54          0.30
                                                                           -----------   ----------   -----------
    Net earnings available for common shareholders.......................  $      1.34   $     1.26   $      0.33
                                                                           ===========   ==========   ===========
Diluted earnings per share:
    Net earnings available for common shareholders
       from continuing operations net of dividends on preferred stock....  $      1.30   $     0.70   $      0.02
    Net earnings from discontinued operations............................           --         0.52          0.29
                                                                           -----------   ----------   -----------
    Net earnings available for common shareholders.......................  $      1.30   $     1.22   $      0.31
                                                                           ===========   ==========   ===========
</TABLE>

During the three-year  period ended June 30, 2004, no adjustments  were required
in net earnings  available  for common  shareholders  for the earnings per share
calculations.  Diluted earnings per share include average shares  outstanding as
well as common stock  equivalents  from stock  options,  warrants and  mandatory
convertible equity units.  Common stock equivalents were 1,095,220,  669,581 and
1,828,993 for the years ended June 30, 2004, 2003 and 2002, respectively. During
2004,  2003 and 2002,  the Company  repurchased  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 for the same period in 2002. At June 30, 2004,  1,089,147  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 June 11, 2003,  the Company issued  2,500,000  mandatory  convertible  equity
units at a public offering price of $50.00 per share.  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 - Stockholder's 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.

<PAGE>
<TABLE>
<CAPTION>
                                                                                                  June 30,
                                                                                       ----------------------------
                                                                                            2004           2003
                                                                                       ----------------------------
<S>                                                                                    <C>            <C>
Distribution plant...............................................................      $   1,662,345  $   1,611,098
Transmission plant...............................................................          1,159,825      1,238,972
General plant....................................................................            529,599        462,730
Underground storage plant........................................................            287,005        236,639
Gathering plant..................................................................             39,746         56,076
Other............................................................................             96,308        107,444
                                                                                       -------------  -------------
     Total plant.................................................................          3,774,828      3,712,959
Less contributions in aid of construction........................................             (2,212)        (2,418)
                                                                                       -------------  -------------
     Plant in service............................................................          3,772,616      3,710,541
Construction work in progress....................................................            169,264         75,484
                                                                                       -------------  -------------
                                                                                           3,941,880      3,786,025
Less accumulated depreciation and amortization...................................           (734,367)      (641,225)
                                                                                       -------------  -------------

     Net property, plant and equipment...........................................      $   3,207,513  $   3,144,800
                                                                                       =============  =============
</TABLE>
Acquisitions  of  rate-regulated  utilities are recorded at the historical  book
carrying value of utility plant.

Depreciation  and  Amortization.  Depreciation  and  amortization  of  plant  is
generally  computed using the straight-line  method at an average  straight-line
rate of approximately  3% per annum of the cost of such  depreciable  properties
less applicable  salvage.  Franchises are amortized over their respective lives.
Depreciation  and  amortization  of other property is provided at  straight-line
rates  estimated to recover the costs of the  properties,  after  allowance  for
salvage,  over their respective  lives.  Internally-developed  computer software
system costs are amortized over various periods.

                          VII Goodwill and Intangibles

Effective July 1, 2001, the Company adopted Goodwill and Other Intangible Assets
which was issued by the FASB in June 2001.  In accordance  with this  Statement,
the Company has ceased amortization of goodwill.  Goodwill, which was previously
classified  on the  Consolidated  Balance  Sheet  as  additional  purchase  cost
assigned to utility  plant and  amortized  on a  straight-line  basis over forty
years,  is now  subject  to at least an  annual  assessment  for  impairment  by
applying a fair-value based test.

The following displays changes in the carrying amount of goodwill:

                                                                       Total
                                                                   ------------
Balance as of July 1, 2001......................................   $    652,048
   Impairment losses............................................         (1,417)
   Sale of subsidiaries and other operations....................         (7,710)
                                                                   ------------
Balance as of June 30, 2002.....................................        642,921
   Impairment losses............................................             --
   Sale of subsidiaries and other operations....................             --
                                                                   ------------
Balance as of June 30, 2003.....................................        642,921
   Impairment losses............................................             --
   Reversal of income tax reserve...............................         (2,374)
                                                                   ------------
Balance as of June 30, 2004.....................................   $    640,547
                                                                   ============

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  (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 June 30, 2004,  the  Distribution  segment has goodwill of
$640,547,000.  The Distribution segment is tested annually for impairment in the
fourth quarter, after the annual forecasting process. There was no indication of
impairment at June 30, 2004.

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 as of the
acquisition  date. 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 June 30,
2004, the carrying amount of these intangibles was approximately  $8,720,000 and
is included in Property,  Plant and Equipment on the Consolidated Balance Sheet.
Amortization for fiscal 2004 and 2003 was  approximately  $583,000 and $200,000,
respectively.


<PAGE>

<TABLE>
<CAPTION>
                   VIII Deferred Charges and Deferred Credits

                                                                                                June 30,
                                                                                                --------
                                                                                            2004        2003
                                                                                            ----        ----
<S>                                                                                       <C>         <C>
Deferred Charges
  Pensions......................................................................     $     45,625  $   39,088
  Unamortized debt expense......................................................           38,596      34,209
  Income taxes..................................................................           31,441      30,514
  Retirement costs other than pensions..........................................           26,008      29,028
  Service Line Replacement program..............................................           16,722      18,974
  Environmental.................................................................           12,220      14,304
  Other.........................................................................           20,123      22,144
                                                                                     ------------  ----------
     Total Deferred Charges.....................................................     $    190,735  $  188,261
                                                                                     ============  ==========
</TABLE>


The  Company's   deferred   charges  include   regulatory   assets  relating  to
Distribution  segment  operations in the  aggregate  amount of  $99,314,000  and
$107,696,000,  respectively, at June 30, 2004 and 2003, of which $63,010,000 and
$74,116,000,  respectively, is being recovered through current rates. As of June
30, 2004 and 2003, the remaining  recovery  period  associated with these assets
ranges from 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 in accordance with
the FASB standard, Accounting for the Effects of Certain Types of Regulation.

<TABLE>
<CAPTION>
                                                                                              June 30,
                                                                                         -------------------
                                                                                         2004           2003
                                                                                         ----           ----
<S>                                                                              <C>               <C>
Deferred Credits
     Pensions................................................................... $      97,380     $      88,016
     Retirement costs other than pensions.......................................        60,404            65,144
     Cost of Removal............................................................        28,519            27,286
     Environmental..............................................................        23,082            32,322
     Derivative instrument liability............................................        13,704            26,151
     Customer advances for construction.........................................        13,518            12,008
     Provision for self-insured claims..........................................        10,542            12,000
     Investment tax credit......................................................         5,367             5,791
     Other......................................................................        40,430            53,436
                                                                                  ------------    --------------

         Total Deferred Credits................................................. $     292,946    $      322,154
                                                                                  ============    ==============
</TABLE>

The  Company's  deferred  credits  include  regulatory  liabilities  relating to
Distribution  segment  operations in the  aggregate  amount of  $11,164,000  and
$10,084,000,   respectively,  at  June  30,  2004  and  2003.  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 Investment Securities

At June 30, 2004,  all  securities  owned by the Company are accounted for under
the cost method.  The Company's  investments in securities consist of common and
preferred stock in non-public companies whose value is not readily determinable.
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 one of these investments.

<PAGE>

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 on its consolidated  statement of operations
to reduce the carrying value of the security to its estimated fair value.

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 June
30, 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 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. Unless otherwise 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  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,   performance  shares  and
restricted  stock.  Options  granted  under  the 1992 Plan are  exercisable  for
periods  of ten  years  from the date of grant or such  lesser  period as may be
designated  for particular  options,  and become  exercisable  after a specified
period of time from the date of grant in cumulative annual installments. Options
typically vest 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 (Pennsylvania 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 maintained 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
2004 and 2003, no options and 15,538 options,  respectively,  were exercised 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 2004 and 2003, no options were exercised and
220,635 and 217,571  options  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 past
three years:
<TABLE>
<CAPTION>

                                                                     2003 Plan                        1992 Plan
                                                                     ---------                        ---------
                                                                         Weighted                             Weighted
                                                      Shares Under       Average         Shares Under         Average
                                                        Option        Exercise Price       Option         Exercise Price
                                                        ------        --------------       ------         --------------
<S>                                                   <C>                <C>                  <C>         <C>
Outstanding July 1, 2001...........................           --         $        --          4,957,666   $        11.29
     Granted   ....................................           --                  --             75,249            13.83
     Exercised.....................................           --                  --         (1,020,546)            9.54
     Canceled .....................................           --                  --           (188,856)           14.45
                                                      ----------                             ----------

Outstanding June 30, 2002..........................           --                  --          3,823,513            11.65
     Granted  .....................................           --                  --                 --               --
     Exercised.....................................           --                  --           (662,982)            4.65
     Canceled .....................................           --                  --           (185,161)           14.67
                                                      ----------                             ----------
Outstanding June 30, 2003..........................           --                  --          2,975,370            13.02
     Granted  .....................................      729,227               17.67                 --               --
     Exercised.....................................           --                  --           (352,486)            9.91
     Canceled .....................................           --                  --             (2,190)           15.38
                                                      ----------                             ----------
Outstanding June 30, 2004..........................      729,227               17.67          2,620,694            13.44
                                                      ==========                             ==========
</TABLE>

The following table summarizes information about stock options outstanding under
the 1992 Plan at June 30, 2004:
<TABLE>
<CAPTION>
                        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
---------------    --------     -----------------   --------------     -------         --------------
<C>        <C>      <C>            <C>               <C>                <C>             <C>
$ 0.00   - $ 7.99    154,292        1.4 years         $    6.75          124,598         $    6.75
  8.00   -  11.99    291,780        2.9 years             10.22          291,780             10.22
 12.00   -  13.99    563,896        4.3 years             13.26          529,595             13.26
 14.00   -  17.99  1,610,726        5.9 years             14.72        1,062,093             14.60
                   ---------                                         -----------
                   2,620,694                                           2,008,066
                   =========                                         ===========
</TABLE>

The weighted average remaining contractual life of options outstanding under the
2003 Plan, the Pennsylvania  Option Plan and the Pennsylvania  Incentive Plan at
June 30,  2004 was 9.6,  2.1 and 3.9 years,  respectively.  There were no shares
available for future option grants under the 1992 Plan at June 30, 2004.


<PAGE>

The  shares  exercisable  under the  various  plans and  corresponding  weighted
average exercise price for the past three years are as follows:

                                                      Pennsylvania  Pennsylvania
                                              1992       Option       Incentive
                                              Plan        Plan           Plan
                                              ----        ----           ----

Shares exercisable at:
     June 30, 2004......................... 2,008,066    443,929       217,571
     June 30, 2003......................... 1,966,753    443,929       214,507
     June 30, 2002......................... 2,145,327    459,467       211,442

Weighted average exercise price at:
     June 30, 2004.........................   $ 13.12     $ 9.21      $  10.65
     June 30, 2003.........................     12.29       9.21         10.60
     June 30, 2002.........................      9.51       9.12         10.55

There were no shares exercisable under the 2003 Plan at June 30, 2004.

Warrant.  On February 10, 1994,  Southern Union granted a warrant 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 Company's  outside
legal counsel exercised the warrant through a non-cash exercise resulting in the
issuance of 84,758 shares of Company common stock.

Retained Earnings.  Under the most restrictive provisions in effect, as a result
of the sale of 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.

Fiscal 2005 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 has 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.  The Company will
only receive  additional  proceeds from the sale of the 7,850,000  shares of the
Company's  common stock that were sold through the forward sale agreements if it
settles its obligation  under such agreements  through the physical  delivery of
shares,  in which case it will receive  additional net proceeds of $142,000,000.
The forward sale agreements are required to be settled within 12 months from the
date of the offering.

Fiscal 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.

<PAGE>
On June 11,  2003,  the Company also 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 utilizes derivative instruments on a limited basis to manage certain
business  risks.  Interest  rate swaps and  treasury  rate locks are employed to
manage the Company's exposure to interest rate risk.

Cash Flow  Hedges.  As a result of the  acquisition  of  Panhandle  Energy,  the
Company is party to interest  rate swap  agreements  with an aggregate  notional
amount of $197,947,000 as of June 30, 2004 that fix the interest rate applicable
to floating rate long-term debt and which qualify for hedge accounting.  For the
year  ended  June  30,  2004,  the  amount  of  swap   ineffectiveness  was  not
significant.  As of June 30, 2004,  floating rate LIBOR-based  interest payments
are exchanged for weighted fixed rate interest payments of 5.88%, which does not
include the spread on the underlying variable debt rate of 1.625%. Interest rate
swaps are  carried  on the  Consolidated  Balance  Sheet at fair  value with the
effective  portion of the unrealized gain or loss adjusted  through  accumulated
other comprehensive  income. 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 June 30, 2004 and 2003,  the fair value  liability
position of the swaps was $14,445,000 and $26,058,000,  respectively. As of June
30,  2004,   approximately   $1,068,000  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 June 30, 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.

<PAGE>

Fair Value Hedges. In March 2004, Panhandle Energy entered into an interest rate
swap 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 agreement 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 June  30,  2004,  the  fair  value  liability  position  of the  swap  was
$4,960,000, which reduced the carrying value of the underlying debt.

Trading and  Non-Hedging  Activities.  During fiscal 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 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 an asset and a
matching adjustment to deferred cost of gas of $1,337,000.

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 fiscal years 2004,  2003 and 2002, the Company
recorded $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 $507,000 at June 30, 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 connection with the
Subsidiary Trust's issuance of the Preferred Securities and the related purchase
by Southern Union of all of the Subsidiary Trust's common  securities,  Southern
Union issued to the Subsidiary Trust $103,092,800  principal amount of its 9.48%
Subordinated  Deferrable Interest Notes, due 2025 (Subordinated Notes). The sole
assets of the Subsidiary Trust are 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  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.

<PAGE>

<TABLE>
<CAPTION>

                           XIII Debt and Capital Lease
                                                                              June 30,
                                                                              --------
                                                                        2004             2003
                                                                        ----             ----
<S>                    <C>                                        <C>              <C>
Southern Union Company
7.60% Senior Notes due 2024...................................... $    359,765     $    359,765
8.25% Senior Notes due 2029......................................      300,000          300,000
2.75% Senior Notes due 2006......................................      125,000          125,000
Term Note, due 2005..............................................      111,087          211,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029...........      113,435          115,884
7.70% Debentures, due 2027.......................................           --            6,756

Capital lease and other, due 2004 to 2007........................          277            9,179
                                                                  ------------     ------------
                                                                     1,009,564        1,127,671
Panhandle Energy
2.75% Senior Notes due 2007......................................      200,000               --
4.80% Senior Notes due 2008......................................      300,000               --
6.05% Senior Notes due 2013......................................      250,000               --
6.125% Senior Notes due 2004.....................................           --          292,500
7.875% Senior Notes due 2004.....................................       52,455          100,000
6.50% Senior Notes due 2009......................................       60,623          158,980

8.25% Senior Notes due 2010......................................       40,500           60,000
7.00% Senior Notes due 2029......................................       66,305          135,890
Term Loan due 2007...............................................      263,926          275,358
7.95% Debentures due 2023........................................           --           76,500
7.20% Debentures due 2024........................................           --           58,000
Net premiums on long-term debt...................................       16,199           61,506
                                                                  ------------     ------------
                                                                     1,250,008        1,218,734

Total consolidated debt and capital lease........................    2,259,572        2,346,405
    Less current portion.........................................       99,997          734,752
    Less fair value swap of Panhandle Energy.....................        4,960               --
                                                                  ------------     ------------
Total consolidated long-term debt and capital lease.............. $  2,154,615     $  1,611,653
                                                                  ============     ============
</TABLE>

The maturities of long-term debt and capital lease payments for each of the next
five years ending June 30 are: 2005 -- $99,997,000; 2006 -- $90,475,000; 2007 --
$565,718,000;   2008  --  $1,648,000;   2009  --  $301,646,000   and  thereafter
$1,183,890,000.

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 $1,166 and $1,079  (per
$1,000  note),  respectively  on June 30, 2004,  as quoted by a major  brokerage
firm.  The  carrying  amount  of  long-term  debt at June 30,  2004 and 2003 was
$2,259,573,000  and  $2,346,405,000,  respectively.  The fair value of long-term
debt  at  June  30,  2004  and  2003  was  $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 August 28, 2000,  the Company  entered into the Term Note 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 June 30, 2004, a balance of $111,087,000 was outstanding
on this 2002 Term Note at an  effective  interest  rate of 2.42%.  The 2002 Term
Note requires semi-annual  principal repayments on February 15th and August 15th
of each year, with payments of $35,000,000  each being due February 15, 2005 and
August 15, 2005. The remaining principal amount of $41,087,000 is due August 26,
2005. 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 has recorded a pre-tax gain on the  extinguishment  of
debt of  $6,354,000  in fiscal 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, pending
the repayment of the $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 first quarter of fiscal
year  1999.  The  installation  of the AMR  system  involved  an  investment  of
approximately $30,000,000, which is accounted for as a capital lease obligation.
As of June 30, 2004 and 2003, the capital lease  obligation  outstanding was 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.

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.  The  Long-Term  Facility  replaced the  Company's
$150,000,000  and $225,000,000  credit  facilities that expired on April 1, 2004
and May 29, 2004,  respectively.  The Company has additional  availability under
uncommitted  line of credit  facilities  (Uncommitted  Facilities)  with various
banks.  Borrowings  under the  Long-Term  Facility  are  available  for Southern
Union's  working  capital,  letter of  credit  requirements  and  other  general
corporate purposes.  The Long-Term Facility is subject to a commitment fee based
on the rating of the Company's senior unsecured notes (the Senior Notes).  As of
June 30, 2004,  the  commitment  fees were an  annualized  0.15%.  The Long-Term
Facility requires the Company to meet certain covenants in order for the Company
to be able to  borrow  under  that  agreement.  A  balance  of  $21,000,000  and
$251,500,000 was outstanding  under the Company's credit  facilities at June 30,
2004 and 2003,  respectively.  As of August  16,  2004,  there was a balance  of
$79,500,000 outstanding under the Long-Term Facility.

                              XIV Employee Benefits

Pension and Other Post-Retirement  Benefits. In fiscal 2004, the Company adopted
the  FASB   Standard,   Employers'   Disclosures   about   Pensions   and  Other
Postretirement  Benefits - an amendment of FASB  Statements No. 87, 88, and 106,
which  changed  the  Company's  reporting   requirements  for  its  pension  and
post-retirement  benefit plans.  See Note I - Summary of Significant  Accounting
Policies (New Pronouncements).

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.

The Company uses a March 31 measurement date for the majority of its plans.

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 June 30, 2004 and 2003.

<TABLE>
<CAPTION>
                                                                       Pension Benefits          Post-Retirement Benefits
                                                                 ----------------------------   ---------------------------
                                                                      2004           2003           2004           2003
                                                                 -------------   ------------   ------------   ------------
<S>                                                              <C>             <C>            <C>            <C>
Change in Benefit Obligation
     Benefit obligation at beginning of year..................   $     350,860   $    317,012   $     90,344   $     76,596
     Service cost.............................................           6,533          5,655          3,993          1,177
     Interest cost............................................          22,591         22,899          8,739          5,579
     Benefits paid............................................         (20,649)       (20,046)        (6,263)        (6,676)
     Actuarial loss...........................................          21,796         26,350          7,687         13,357
     Acquisition............................................              --             --           42,752             --
     Plan amendments..........................................           7,703          1,095          5,173            311
     Settlement recognition...................................          (2,341)        (2,105)            --             --
                                                                 -------------   ------------   ------------   ------------
     Benefit obligation at end of year........................   $     386,493   $    350,860   $    152,425   $     90,344
                                                                 =============   ============   ============   ============

Change in Plan Assets
     Fair value of plan assets at beginning of year...........   $     237,376   $    284,911   $     21,332   $     22,408
     Return on plan assets....................................          55,725        (30,900)         3,211             27
     Employer contributions...................................           6,043          5,516         15,724          5,572
     Benefits paid............................................         (20,649)       (20,046)        (6,263)        (6,675)
     Settlement recognition...................................          (2,341)        (2,105)            --             --
                                                                 -------------   ------------   ------------   ------------
     Fair value of plan assets at end of year.................   $     276,154   $    237,376   $     34,004   $     21,332
                                                                 =============   ============   ============   ============
</TABLE>


<PAGE>

<TABLE>
<CAPTION>
                                                                       Pension Benefits          Post-Retirement Benefits
                                                                 ----------------------------   ---------------------------
                                                                      2004           2003           2004           2003
                                                                 -------------   ------------   ------------   ------------
<S>                                                              <C>             <C>            <C>            <C>
Funded Status
     Funded status at end of year.............................   $    (110,339)  $   (113,484)  $   (118,421)  $    (69,012)
     Unrecognized net actuarial loss..........................         114,344        134,752         25,972         20,343
     Unrecognized prior service cost..........................          13,737          7,179          5,038            130
                                                                 -------------   ------------   ------------   ------------
     Prepaid/(accrued) prior to contributions for 3 months
       ended June 30..........................................          17,742         28,447        (87,411)       (48,539)
     Contributions for 3 months ended June 30.................           3,750          4,534          2,151          4,675
                                                                 -------------   ------------   ------------   ------------
     Net asset (liability) recognized at June 30..............   $      21,492   $     32,981   $    (85,260)  $    (43,864)
                                                                 =============   ============   ============   ============

Amounts Recognized in the Consolidated Balance Sheet
     Prepaid benefit cost.....................................   $      28,172   $     27,597   $         --   $         --
     Accrued benefit liability................................         (87,448)       (89,366)       (85,260)       (43,864)
     Intangible asset.........................................          10,366          3,671             --             --
     Accumulated other comprehensive loss.....................          70,402         91,079             --             --
                                                                 -------------   ------------   ------------   ------------
     Net asset (liability) recognized.........................   $      21,492   $     32,981   $    (85,260)  $    (43,864)
                                                                 =============   ============   ============   ============
</TABLE>

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  as of June  30,  2004  were  $355,095,000,  $319,902,000,  and
$228,704,000,   respectively,  and  for  those  same  plans  were  $323,116,000,
$291,811,000, and $197,911,000 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 as of June 30,  2004 were
$152,425,000  and  $34,004,000  respectively,  and for  those  same  plans  were
$90,344,000 and $21,332,000 respectively as of June 30, 2003.

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
year ended June 30, 2004, 2003 and 2002 were:
<TABLE>
<CAPTION>

                                                       Pension Benefits                     Post-Retirement Benefits
                                            --------------------------------------   --------------------------------------
                                                2004         2003         2002           2004         2003          2002
                                            ----------   -----------   -----------   ----------    ----------    ----------
<S>                                              <C>           <C>           <C>          <C>           <C>           <C>
Discount rate
     Beginning of year..................         6.50%         7.50%         7.50%        6.50%         7.50%         7.50%
     End of year........................         6.00%         6.50%         7.50%        6.00%         6.50%         7.50%
Rate of compensation increase (average).         3.60%         4.00%         5.00%          N/A           N/A           N/A
Health care cost trend rate.............          N/A           N/A           N/A        13.00%        13.00%        12.00%
</TABLE>

The  assumed  health  care cost trend  rate used in  measuring  the  accumulated
post-retirement benefit obligation was 13% during 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 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 year  ended  June 30,  2004,  2003 and 2002
includes the following components:
<TABLE>
<CAPTION>

                                                       Pension Benefits                     Post-Retirement Benefits
                                            --------------------------------------   --------------------------------------
                                               2004          2003         2002          2004          2003          2002
                                            ----------   -----------   -----------   ----------    ----------    ----------
<S>                                         <C>          <C>           <C>           <C>           <C>           <C>
Service cost............................    $    6,533   $     5,655   $     5,707   $    3,993    $    1,177    $    1,136
Interest cost...........................        22,591        22,899        22,570        8,739         5,579         5,362
Expected return on plan assets..........       (21,477)      (24,749)      (25,868)      (1,640)       (1,734)       (1,701)
Amortization of prior service cost......         1,145           790           984          266           (65)         (100)
Recognized actuarial gain (loss)........         8,402         2,433           194          485          (234)         (737)
Curtailment.............................            --            --         8,905           --            --         1,200
Special termination benefits............            --            --         8,957           --            --         1,309
Settlement recognition..................          (445)         (558)         (457)          --            --            --
                                            ----------   -----------   -----------   ----------    ----------    ----------
Net periodic pension cost...............    $   16,749   $     6,470   $    20,992   $   11,843    $    4,723    $    6,469
                                            ==========   ===========   ===========   ==========    ==========    ==========
</TABLE>

Curtailment and special  termination benefit charges were recognized during 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 year ended June 30, 2004, 2003 and 2002 were:
<TABLE>
<CAPTION>

                                                       Pension Benefits                     Post-Retirement Benefits
                                            --------------------------------------   --------------------------------------
                                                2004         2003         2002           2004         2003          2002
                                            ----------   -----------   -----------   ----------    ----------    ----------
<S>                                              <C>           <C>           <C>          <C>           <C>           <C>
Discount rate
     Beginning of year..................         7.50%         7.50%        8.00%        7.50%         7.50%         7.50%
     End of year........................         6.50%         7.50%        7.50%        6.50%         7.50%         7.50%
Expected return on assets -
      tax exempt accounts...............         9.00%         9.00%        9.00%        7.00%         9.00%         9.00%
Expected return on assets - taxable
  accounts..............................          N/A           N/A          N/A         5.00%         5.50%         5.40%
Rate of compensation increase (average).         4.00%         5.00%        5.00%          N/A           N/A           N/A
Health care cost trend rate.............          N/A           N/A          N/A        13.00%        12.00%        12.00%
</TABLE>

The assumed  health care cost trend rate used in  determining  the net  periodic
benefit  cost was 13% during 2004.  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 was 12% during 2003. 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:
<TABLE>
<CAPTION>

                                                                        One Percentage Point          One Percentage Point
                                                                       Increase in Health Care      Decrease in Health Care
                                                                             Trend Rate                    Trend Rate
                                                                             ----------                    ----------

<S>                                                                        <C>                        <C>
Effect on total service and interest cost components..............         $        1,512             $       (1,227)
Effect on post-retirement benefit obligation......................         $       14,212             $      (11,628)
</TABLE>

Plan Asset Information

Pension Plan Assets.  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.

Investment  theory and historical  capital market return data suggest that, over
long periods of time, there is a relationship  between the level of risk assumed
and the  level of return  that can be  expected  in an  investment  program.  In
general,  higher risk (i.e.,  volatility  of return) is  associated  with higher
return.  Given this relationship  between risk and return, a fundamental step in
determining the investment  policy is the  determination  of an appropriate risk
tolerance.  The Company examined two important factors that affect the Company's
risk  tolerance,  including  the  financial  ability to accept  risk  within the
investment program and willingness to accept return volatility.

Positive  factors  that  contribute  to a  higher  risk  tolerance  are:(i)  the
financial  strength of the  Company;  (ii) the  relationship  between the market
value of Plan assets and Plan  liabilities (a surplus can provide a cushion that
would  reduce  the  probability  of making  any  required  contributions  in the
short-term in the event of adverse  experience  versus  actuarial  assumptions);
(iii) the Company's  willingness to accept  short-term  volatility in the market
value of the Plan for the sake of earning higher long-term returns; (iv) and the
long-term  time horizon  available for  investment  provides the  opportunity to
benefit from  opportunities  for growth that may accrue to a patient  investment
strategy.

Offsetting  these factors are: (i)as a defined benefit pension plan, the risk of
investment losses is borne by the Company and significant  investment losses may
require  substantial  contributions  to the Plan to  maintain  required  funding
levels and such  contributions  may coincide with poor financial results for the
Company;  and (ii)cyclical  business  activity can  significantly  influence the
finances   of  the  Company  and  its   financial   ability  to  fund   required
contributions.

Post-retirement  Health and Life Plans' Assets. 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 (v) recognizes  that  investment  results over the
long-term may lag those of a typical balanced portfolio since a typical balanced
portfolio tends to be more  aggressively  invested.  Nevertheless,  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 June 30, 2004, and 2003, by
asset category is as follows:

                                               Pension          Post-Retirement
                                               At June 30,       At June 30,
                                              ------------       --------------
 Asset Category                               2004    2003       2004    2003
 --------------                               ----    ----       ----    ----

Equity securities.........................    68%       51%      21%      26%
Debt securities...........................    26%       45%      50%      64%
Other - cash equivalents..................     6%        4%      29%      10%
                                             ----     -----     -----    ----
     Total.................................  100%      100%      100%    100%
                                             ====     =====     =====    ====

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

Based on the Pension  Plan  objectives,  asset  allocations  are  maintained  as
follows:  equity of 50% to 75%,  fixed  income of 25% 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 $11,600,000
and $12,608,000 to its pension plans and the estimated  amount of $13,553,000 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         Other
                                                         Benefits      Benefits

2005.................................................    $ 23,547      $ 6,572
2006.................................................      20,579        6,922
2007.................................................      21,161        6,994
2008.................................................      22,205        7,514
2009.................................................      22,543        8,210
Years 2010 - 2014....................................     136,657       53,149

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 ProvEnergy;
(iv) non-union employees of ProvEnergy; (v) union employees of Valley Resources;
(vi)  non-union  employees of Valley  Resources;  (vii) union  employees of Fall
River Gas;  and (viii)  non-union  employees  of 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.

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 contributions 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
contributions to the plan during 2004, 2003 and 2002 were $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 benefits  previously
provided under defined benefit plans.  Employer  contributions to these separate
accounts,   referred  to  as  Retirement  Power  Accounts,  within  the  defined
contribution  plan were  determined  based on the  employee's  age plus years of
service plus  accumulated  sick leave as of December 31, 1998. The  contribution
amounts are  determined as a percentage of  compensation  and range from 3.5% to
8.5%.  Company  contributions to Retirement Power Accounts during 2004, 2003 and
2002 were $5,149,000, $1,469,000 and $826,000, respectively.

Panhandle  Energy.  Following the June 11, 2003  acquisition by Southern  Union,
Panhandle  Energy  instituted  certain  retiree  health care and life  insurance
benefits under other post employment  benefits (OPEB) and added certain benefits
to substantially all of its employees under a defined  contribution  401(k) plan
(Savings  Plan).  Under the Savings Plan,  Panhandle  Energy provides a matching
contribution of 50% of the first 4% of the participant's  compensation paid into
the Savings Plan. In addition,  Panhandle Energy makes additional  contributions
ranging  from  4% to  6% of  the  employee's  eligible  pay,  depending  on  the
employee's  age and years of service.  The adoption of the OPEB plan resulted in
the  recording  of a  $43,000,000  liability  as of June 11, 2003 and  Panhandle
Energy  continues to fund the plan at  approximately  $8,000,000 per year. Since
Panhandle  Energy  retirement  eligible active  employees 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.


<PAGE>
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
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: $16.4 million of
voluntary  and  accepted  ERP's,   primarily   through   enhanced  benefit  plan
obligations,  and other employee benefit plan  obligations;  $6.8 million of RIF
within the corporate offices and related employee separation benefits;  and $6.0
million   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 June 30,  2004  and  2003,  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 June 30, 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
<TABLE>
<CAPTION>
                                                                                Year Ended June 30,
                                                                                -------------------
                                                                          2004        2003           2002
                                                                          ----        ----           ----
<S>                                                                  <C>           <C>            <C>
Income tax expense:
  Current:
     Federal.....................................................    $    1,497    $  (15,258)    $  (8,848)
     State.......................................................           151        (6,563)        (1,391)
                                                                     ----------    ----------     ---------
                                                                          1,648       (21,821)      (10,239)
                                                                     ----------    ----------     ---------
  Deferred:
     Federal....................................................     $   60,380        38,926        13,050
     State......................................................          7,075         7,168           600
                                                                     ----------    ----------     ---------
                                                                         67,455        46,094        13,650
                                                                     ----------    ----------     ---------
Total income tax expense from continuing operations.............     $   69,103    $   24,273     $   3,411
                                                                     ==========    ==========     =========
</TABLE>

Deferred  credits  include  $5,367,000 and  $5,791,000 of  unamortized  deferred
investment tax credit as of June 30, 2004 and 2003.

Deferred  income taxes result from temporary  differences  between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
<TABLE>
<CAPTION>

                                                                 June 30,
                                                                 --------
                                                            2004          2003
                                                            ----          ----
<S>                                                  <C>            <C>
Deferred income tax assets:
     Alternative minimum tax credit................. $     24,054   $      6,263
     Insurance accruals.............................        1,601          2,028
     Bad debt reserves..............................        5,721          4,096
     Post-retirement benefits.......................        1,346          1,078
     Minimum pension liability......................       33,511         35,159
     Other..........................................        8,442         10,313
                                                     ------------   ------------
         Total deferred income tax assets........... $     74,675   $     58,937
                                                     ------------   ------------
</TABLE>

<PAGE>

<TABLE>
<CAPTION>

                                                                 June 30,
                                                                 --------
                                                             2004        2003
                                                             ----        ----
<S>                                                   <C>            <C>
Deferred income tax liabilities:
     Property, plant and equipment................... $   (313,387)  $ (261,100)
     Unamortized debt expense........................      (21,607)      (5,455)
     Regulatory liability............................      (13,151)     (14,483)
     Other...........................................      (55,831)     (56,510)
                                                      ------------   ----------
         Total deferred income tax liabilities.......     (403,976)   (337,548)
                                                      ------------   ----------
Net deferred income tax liability....................     (329,301)    (278,611)
    Less current income tax assets...................       19,659        4,096
                                                      ------------   ----------
 Accumulated deferred income taxes................... $   (348,960)  $ (282,707}
                                                      ============   ==========
</TABLE>
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.
<TABLE>
<CAPTION>
                                                                                                Year Ended June 30,
                                                                                                -------------------
                                                                                            2004        2003         2002
                                                                                            ----        ----         ----

<S>                                                                                    <C>          <C>           <C>
Computed statutory income tax expense from continuing operations at 35%.........       $    64,095  $   23,780    $   1,726
Changes in income taxes resulting from:
     State income taxes, net of federal income tax benefit......................             4,697         326          695
     Amortization/write-down of goodwill........................................                --          --        3,113
     Internal Revenue Service audit settlement..................................                --          --       (1,570)
     Investment Tax Credit amortization.........................................              (424)       (421)        (608)
     Other......................................................................               735         588           55
                                                                                       -----------  ----------    ---------
Actual income tax expense from continuing operations............................       $    69,103  $   24,273    $   3,411
                                                                                       ===========  ==========    =========
</TABLE>


                            XVI Regulation and Rates

Missouri  Gas Energy.  On November 4, 2003,  Missouri Gas Energy filed a request
with the MPSC to increase base rates by  $44,800,000  and to implement a weather
mitigation   rate  design  that  would   significantly   reduce  the  impact  of
weather-related  fluctuations on customer  bills. On January 30, 2004,  Missouri
Gas  Energy  filed an  updated  claim  which  raised the amount of the base rate
increase  request to  $54,200,000.  As of July 19,  2004,  upon the close of the
record and reflecting  settlement of a number of issues,  MGE's request stood at
approximately   $39,000,000  and  the  MPSC  Staff's   recommendation  stood  at
approximately  $13,000,000.  Statutes  require that the MPSC reach a decision in
the case within an eleven-month  period from the original filing date. It is not
presently  possible to determine what action the MPSC will  ultimately take with
respect to this rate increase request.

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.  Construction on the Trunkline LNG expansion project (Phase
I) commenced in September 2003 and is expected to be completed by the end of the
2005 calendar year. In February 2004,  Trunkline LNG filed a further incremental
LNG expansion project (Phase II) with FERC and is awaiting commission  approval.
Phase II 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-calendar 2006.

In February 2004,  Trunkline filed an application  with FERC to request approval
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.

                                   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  June  30 are as  follows:
2005--$17,777,000;   2006--$14,708,000;   2007--$13,970,000;   2008--$10,018,000
2009--$6,549,000  and thereafter  $8,102,000.  Rental  expense was  $17,821,000,
$4,342,000,  and  $5,759,000  for the years ended June 30, 2004,  2003 and 2002,
respectively.


<PAGE>

                       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. 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. 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 1st Street
and Campbell in Kansas City, Missouri and is owned by Missouri Gas Energy (MGE).
During  July 1999,  the  Company  entered  the two sites into  MDNR's  Voluntary
Cleanup Program 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 million.  Remediation  of
Station B has not been requested by MDNR at this time.

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 Department  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.  On June 16, 2004, MGE submitted a UST Site  Characterization
Work Plan to MDNR for review and approval.

New England Gas Company.  Prior to its  acquisition  by the Company in September
2000,   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 million 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 on April
17, 2002, by a qualified  contractor  selected in a competitive bidding process.
Remediation  was completed on October 10, 2002,  and a Closure  Report was filed
with RIDEM in December 2002.  The cost of  environmental  work  conducted  after
remediation  resumed was $4 million.  Remediation of the remaining 37.5 acres of
the site (known as the "Phase 2"  remediation  project) is not scheduled at this
time.

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.

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,  the Company submitted a Site Investigation
Report on December 5, 2003, to RIDEM.  On April 15, 2004,  the Company  obtained
verbal approval from RIDEM to conduct additional  investigation  activity at the
site.

In a letter dated March 17, 2003, RIDEM sent the New England Gas Company (NEG) 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  NEG  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,  NEG 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,  NEG  began  assessment  work on June  2,  2003.  A Site
Inspection  Report and a Human Health Risk  Assessment  were filed with RIDEM on
October 31, 2003, and RIDEM provided NEG comments to the Site 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. On July 19, 2004, NEG 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 NEG's work plans. In response, NEG notified RIDEM of
its intent to begin assessment field work on August 26, 2004.

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  NEG
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 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.

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  Massachusetts  Department of  Environmental  Protection  (MADEP),  the
Company  submitted an Immediate  Response Action Plan (Action Plan) to the MADEP
on July 26, 2004. The Action Plan proposes an investigation to determine whether
or not coal gasification  related material was historically  dumped in the State
Avenue Area.

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  (the  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 United States
Environmental   Protection   Agency   (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 million out of the  bankruptcy  estates.  This  payment is
payable  $1.25  million  to the  Company  for  payment  of  environmental  costs
associated with the former Fall River Gas Company,  and $3.75 million payable to
the Company and National Grid jointly for payment of 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 a  letter  dated  March  11,  2003,  the  MADEP  provided  NEG  a  Notice  of
Responsibility  for 66 5th Street in Fall River,  Massachusetts.  This Notice of
Responsibility  requested  that site  assessment  activities be conducted at the
former MGP at 66 5th 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.  NEG submitted an Immediate  Response Action (IRA)
Work Plan on May 20,  2003.  The IRA Report was  submitted  to MADEP on July 18,
2003. Investigation work performed to date indicates that cyanide concentrations
at the  downgradient  properties  are  unrelated  to the NEG  property at 66 5th
Street.

In 2003, NEG 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 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 NEG. Based upon the Phase I filing,  NEG is
required to file a Phase II report with MADEP by September 18, 2005, to complete
the site characterization.

PG Energy.  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. On March 23, 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  the  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 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 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.  The Company does not believe
the  outcome  of these  matters  will  have a  material  adverse  effect  on its
financial position, results of operations or cash flows.

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.

Panhandle  Energy  Environmental  Matters --  Panhandle  Energy  has  identified
environmental  impacts  at  certain  sites  on its  systems  and has  undertaken
clean-up  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.  Some  remediation is being  performed by former  Panhandle  Energy
affiliates in accordance with indemnity  agreements that also indemnify  against
certain future environmental litigation and claims.

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.  Eight 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.  Based on the information
found  during  the  initial  investigation,  Panhandle  Energy  and the 21 other
non-affiliated   parties  have  decided  to  further  delineate  the  extent  of
contamination  by authorizing a Phase II  investigation  at this site. Once data
from the Phase II investigation is evaluated,  Panhandle Energy and the 21 other
non-affiliated  parties will determine what additional actions will be taken. 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 in calendar 2004
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.

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 million 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 million for capital  improvements  through
March 2007, based on current projections.

The EPA promulgated  various Maximum  Achievable Control Technology (MACT) rules
in August 2003 and 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 May  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 million for capital improvements, based on current projections.

Regulatory

On May 31, 2002, the staff of the MPSC recommended that the Commission  disallow
approximately  $15 million in gas costs incurred  during the period July 1, 2000
through June 30, 2001.  Missouri Gas Energy filed its response in  opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's  assertions.  Missouri Gas Energy intends to vigorously defend itself in
this  proceeding.  This matter  went into  recess  following a hearing in May of
2003.  Following the May hearing,  the Commission staff reduced its disallowance
recommendation to approximately $9.3 million.  The hearing concluded in November
2003 and the matter was fully  submitted to the  Commission in February 2004 and
is awaiting decision by the Commission.

On November 27, 2001,  August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended  that the  Commission  disallow  approximately  $5.9  million,  $5.9
million and $4.3 million,  respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1,  1997  through  June 30,  1998,  respectively.  The  basis of these  proposed
disallowances  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. MGE intends to vigorously defend itself in these proceedings.  On
November 4, 2002, the  Commission  adopted a procedural  schedule  calling for a
hearing in this  matter some time after May 2003.  No date for this  hearing 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 by the first  calendar  quarter of 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.  Panhandle  Energy's  pipelines,  with respect to certain
producer contract settlements, may be contractually required to reimburse or, in
some  instances,  to  indemnify  producers  against  such  royalty  claims.  The
potential  liability of the producers to the  government and of the pipelines to
the producers  involves  complex issues of law and fact which are likely to take
substantial  time  to  resolve.  If  required  to  reimburse  or  indemnify  the
producers,  Panhandle 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.

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.  The Company is  committed  under  various  agreements  to purchase
certain  quantities  of gas in the  future.  At June  30,  2004,  the  Company's
Distribution  segment 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 $1,099,972,000. 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 June 30, 2004, the interest rate on the
TIF Debt was 3.25% and estimated  incremental tax revenues are expected to cover
approximately  25% of the fiscal 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 June 30, 2004.  The balance  outstanding on the TIF Debt was $8,710,000 as of
June 30, 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 fiscal 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 fiscal 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  May  2002;  and  a  four-year   contract  with  one  bargaining  unit
representing  employees  of New England  Gas  Company's  Fall River  operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.

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 $58,566,000 at June 30,
2004 and  $7,761,000  at June 30,  2003,  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:
<TABLE>
<CAPTION>
                                                         Year Ended June 30,
                                                         -------------------
                                                         2003            2002
                                                    -------------    -----------
<S>                                                 <C>              <C>
Operating revenues................................  $     144,490    $   309,936
                                                    =============    ===========
Net operating revenues, excluding depreciation
   and amortization (a)...........................  $      51,480    $   105,730
                                                    =============    ===========
Net earnings from discontinued operations (b).....  $      32,520    $    18,104
                                                    =============    ===========
</TABLE>
---------------------------------
(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.

<TABLE>
<CAPTION>

                       XX Quarterly Operations (Unaudited)

                Year Ended                                                  Quarter Ended
               June 30, 2004                 September 30        December 31       March 31       June 30            Total
               -------------                 ---------------   ---------------   ------------  ------------    ------------
<S>                                          <C>               <C>               <C>            <C>            <C>
Operating revenues.......................... $      231,394    $     507,113     $  774,579     $    286,888   $  1,799,974
Net operating revenues, excluding
   depreciation and amortization............        169,309          240,097        297,892          182,843        890,141
Net earnings (loss) from continuing
   operations...............................         (3,707)          38,422         75,367            3,943        114,025
Net earnings (loss) available for common
   shareholders.............................         (3,707)          34,418         71,026             (398)       101,339
Diluted net earnings (loss) per share
   available for common shareholders:(1)
   Continuing operations....................           (.05)             .45            .91             (.01)         1.30
   Available for common shareholders........           (.05)             .45            .91             (.01)         1.30

                 Year Ended                                                 Quarter Ended
               June 30, 2003                September 30         December 31       March 31       June 30             Total
               -------------                ---------------   --------------     -----------   ------------    ------------

Operating revenues.......................... $      99,710   $      346,104     $   535,663    $    207,030    $  1,188,507
Net operating revenues, excluding
   depreciation and amortization............        54,464          118,031         161,400          89,516         423,411
Net earnings (loss) from continuing
   operations...............................        (9,186)          18,519          46,234         (11,898)         43,669
Net earnings from discontinued operations...         2,691           10,900          17,665           1,264          32,520
Net earnings (loss) available for common
   shareholders.............................        (6,495)          29,419          63,899         (10,634)         76,189
Diluted net earnings (loss) per share
   available for common shareholders:(1)
   Continuing operations....................        (.16)               .30            .75             (.19)            .70
   Discontinued operations..................         .05                .18            .29              .02             .52
   Available for common shareholders........        (.11)               .48           1.04             (.17)           1.22
</TABLE>

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

The Company evaluates segment performance based on several factors, of which the
primary  financial  measure is  operating  income  (which the  Company  formerly
referred to as net operating revenues).  The accounting policies of the segments
are  substantially  the same as those  described  in the summary of  significant
accounting policies (see Note I - Summary of Significant  Accounting  Policies).
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 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  in  addition  to  Panhandle  Energy's  operations  its  regulated  utility
operations  would be treated as one separate and  distinct  reportable  segment.
During  fiscal 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.

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.,  offer  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 provides 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.

<PAGE>

The following table sets forth certain  selected  financial  information for the
Company's segments for fiscal 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.
<TABLE>
<CAPTION>

                                                                                           Year Ended June 30,
                                                                           ------------------------------------------------
                                                                                2004              2003                2002
                                                                           ----------------  --------------   -------------
<S>                                                                        <C>               <C>              <C>
Revenues from external customers:
     Distribution.................................................         $   1,304,405     $   1,158,964    $     968,933
     Transportation and Storage...................................               491,083            24,529               --
     All Other (a)................................................                 4,486             5,014           11,681
                                                                           -------------     -------------    -------------
Total consolidated operating revenues.............................         $   1,799,974     $   1,188,507    $     980,614
                                                                           =============     =============    =============
Depreciation and amortization:
     Distribution.................................................         $      57,601     $      56,396    $      53,937
     Transportation and Storage...................................                59,988             3,197               --
     All Other....................................................                   572               590            2,387
                                                                           -------------     -------------    -------------
Total segment depreciation and amortization.......................               118,161            60,183           56,324
Reconciling Item -- Corporate.....................................                   594               459            2,665
                                                                           -------------     -------------    -------------
Total consolidated depreciation and amortization..................         $     118,755     $      60,642    $      58,989
                                                                           =============     =============    =============
Operating income:
     Distribution.................................................         $     118,894     $     142,762    $     135,502
     Transportation and Storage...................................               193,702             9,635               --
     All Other....................................................                (3,514)               13               --
                                                                           -------------     -------------    -------------
Total segment operating income....................................               309,082           152,410          135,502
Reconciling Items:
     Corporate....................................................                (3,555)          (10,039)         (15,218)
     Business restructuring charges...............................                    --                --          (29,159)
                                                                           -------------     -------------    -------------
    Consolidated operating income.....................................     $     305,527     $     142,371    $      91,125
                                                                           =============     =============    =============
Total assets:
     Distribution.................................................         $   2,231,970     $   2,243,257    $   2,156,106
     Transportation and Storage...................................             2,197,289         2,212,467               --
     All Other....................................................                42,133            50,073           53,339
                                                                           -------------     -------------    -------------
Total segment assets..............................................             4,471,392         4,505,797        2,209,445
Reconciling Items:
     Corporate....................................................               101,066            85,141           75,173
     Sale of assets - Texas Operations............................                    --                --          395,446
                                                                           -------------     -------------    -------------
Total consolidated assets.........................................         $   4,572,458     $   4,590,938    $   2,680,064
                                                                           =============     =============    =============

Expenditures for long-lived assets:
     Distribution.................................................         $      78,791     $      67,327    $      68,042
     Transportation and Storage...................................               131,378             5,128               --
     All Other....................................................                   856             1,653            1,365
                                                                           -------------     -------------    -------------
Total segment expenditures for long-lived assets..................               211,025            74,108           69,407
Reconciling item - Corporate......................................                15,028             5,622            1,291
                                                                           -------------     -------------    -------------
Total consolidated expenditures for long-lived assets.............         $     226,053     $      79,730    $      70,698
                                                                           =============     =============    =============

Reconciliation of operating income to earnings from continuing
     operations before income taxes:
     Operating income.............................................         $     305,527     $     142,371    $      91,125
     Interest.....................................................              (127,867)          (83,343)         (90,992)
     Dividends on preferred securities of subsidiary trust........                    --            (9,480)          (9,480)
     Other income, net............................................                 5,468            18,394           14,278
                                                                           -------------     -------------    -------------
          Earnings from continuing operations before income taxes.         $     183,128     $      67,942    $       4,931
                                                                           =============     =============    =============
</TABLE>




<PAGE>


             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Stockholders and Board of Directors of
Southern Union Company:


In our opinion,  the  accompanying  consolidated  balance  sheet and the related
consolidated  statements  of  operations,  of cash  flows  and of  stockholders'
equity,  present fairly,  in all material  respects,  the financial  position of
Southern  Union Company and  subsidiaries  (the  "Company") at June 30, 2004 and
2003,  and the results of their  operations and their cash flows 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).
These 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.


PricewaterhouseCoopers  LLP

Houston, Texas
August 31, 2004



<PAGE>








                                                                      Exhibit 21

                           SUBSIDIARIES OF THE COMPANY



         Name                                  State or Country of Incorporation
 ----------------------                        ---------------------------------

Panhandle Eastern Pipe Line Company, LP                  Delaware
Trunkline Gas Company, LLC                               Delaware
Trunkline LNG Holdings, LLC                              Deleware
Trunkline LNG Company, LLC                               Delaware
Pan Gas Storage, LLC                                     Deleware

Note:    Certain  wholly-owned  subsidiaries  of Southern  Union Company are not
         named above. Considered in the aggregate as a single subsidiary,  these
         unnamed entities would not constitute a "significant subsidiary" at the
         end of the year covered by this report.  Additionally,  the Company has
         other  subsidiaries  that  conduct  no  business  except to the  extent
         necessary to maintain their corporate name or existence.


<PAGE>



                                                                      Exhibit 23

            CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


We  hereby  consent  to the  incorporation  by  reference  in  the  Registration
Statements on Form S-3 (File No.  333-113757) and Form S-8 (File Nos.  33-37261,
33-69596,  33-69598,  33-61558,  333-79443,   333-08994,  333-42635,  333-89971,
333-36146, 333-36150, 333-47144 and 333-112527) of Southern Union Company of our
report dated August 30, 2004 relating to the consolidated  financial  statements
which appear in this Form 10-K.


PricewaterhouseCoopers LLP

Houston, Texas
August 31, 2004


<PAGE>



                                                                      Exhibit 24

                                POWER OF ATTORNEY


KNOW ALL PERSONS BY THESE  PRESENTS  that each person  whose  signature  appears
below  constitutes and appoints  Thomas F. Karam and David J. Kvapil,  or any of
them,  acting  individually  or  together,  as such  person's  true  and  lawful
attorney(s)-in-fact   and  agent(s),   with  full  power  of  substitution   and
revocation,  to act in any capacity for such person and in such  person's  name,
place and stead in any and all  capacities,  to sign the  Annual  Report on Form
10-K for the fiscal  year ended  June 30,  2004 of  Southern  Union  Company,  a
Delaware corporation,  and any amendments thereto, and to file the same with all
exhibits  thereto,  and  other  documents  in  connection  therewith,  with  the
Securities and Exchange Commission and the New York Stock Exchange.

Dated:    August 30, 2004


GEORGE L. LINDEMANN                     ADAM M.LINDEMANN
---------------------------             ----------------------------------------
George L. Lindemann                     Adam M. Lindemann



JOHN E. BRENNAN                         DAVID BRODSKY
---------------------------             ----------------------------------------
John E. Brennan                         David Brodsky



THOMAS F. KARAM                         GEORGE ROUNTREE, III
--------------------------              ----------------------------------------
Thomas F. Karam                         George Rountree, III



FRANK W. DENIUS                         RONALD W.SIMMS
--------------------------              ----------------------------------------
Frank W. Denius                         Ronald W. Simms



KURT A. GITTER, M.D.
--------------------------
Kurt A. Gitter, M.D.











<PAGE>







                                                                    Exhibit 31.1


                                 CERTIFICATIONS

I, George L. Lindemann, certify that:

     (1)  I have  reviewed  this annual  report on Form 10-K of  Southern  Union
          Company;

     (2)  Based on my  knowledge,  this  report  does  not  contain  any  untrue
          statement  of a  material  fact  or  omit to  state  a  material  fact
          necessary to make the statements  made, in light of the  circumstances
          under which such  statements were made, not misleading with respect to
          the period covered by this report;

     (3)  Based on my knowledge,  the financial statements,  and other financial
          information  included in this report,  fairly  present in all material
          respects the financial condition, results of operations and cash flows
          of the  registrant  as of,  and for,  the  periods  presented  in this
          report;

     (4)  The registrant's other certifying officer(s) and I are responsible for
          establishing  and maintaining  disclosure  controls and procedures (as
          defined  in  Exchange  Act  Rules  13a-15(e)  and  15d-15(e))  for the
          registrant and have:

          (a)  Designed such disclosure controls and procedures,  or caused such
               disclosure  controls  and  procedures  to be  designed  under our
               supervision,  to ensure that material information relating to the
               registrant,  including  its  consolidated  subsidiaries,  is made
               known to us by others within those entities,  particularly during
               the period in which this report is being prepared;

          (b)  Evaluated  the  effectiveness  of  the  registrant's   disclosure
               controls  and   procedures  and  presented  in  this  report  our
               conclusions  about the  effectiveness of the disclosure  controls
               and  procedures,  as of the  end of the  period  covered  by this
               report based on such evaluation; and

          (c)  Disclosed in this report any change in the registrant's  internal
               control  over  financial   reporting  that  occurred  during  the
               registrant's most recent fiscal quarter (the registrant's  fourth
               fiscal  quarter  in  the  case  of an  annual  report)  that  has
               materially  affected,  or  is  reasonably  likely  to  materially
               affect,   the   registrant's   internal  control  over  financial
               reporting; and

     (5)  The  registrant's  other  certifying  officer(s) and I have disclosed,
          based on our most recent evaluation of internal control over financial
          reporting, to the registrant's auditors and the audit committee of the
          registrant's  board of directors (or persons performing the equivalent
          functions):

          (a)  All  significant  deficiencies  and  material  weaknesses  in the
               design or operation of internal control over financial  reporting
               which are reasonably  likely to adversely affect the registrant's
               ability  to  record,  process,  summarize  and  report  financial
               information; and

          (b)  Any fraud,  whether or not material,  that involves management or
               other employees who have a significant  role in the  registrant's
               internal control over financial reporting.


Date:  August 31, 2004

GEORGE L. LINDEMANN
------------------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
(principal executive officer)



<PAGE>






                                                                   Exhibit 31.2


                                 CERTIFICATIONS

I, David J. Kvapil, certify that:

     (1)  I have  reviewed  this annual  report on Form 10-K of  Southern  Union
          Company;

     (2)  Based on my  knowledge,  this  report  does  not  contain  any  untrue
          statement  of a  material  fact  or  omit to  state  a  material  fact
          necessary to make the statements  made, in light of the  circumstances
          under which such  statements were made, not misleading with respect to
          the period covered by this report;

     (3)  Based on my knowledge,  the financial statements,  and other financial
          information  included in this report,  fairly  present in all material
          respects the financial condition, results of operations and cash flows
          of the  registrant  as of,  and for,  the  periods  presented  in this
          report;

     (4)  The registrant's other certifying officer(s) and I are responsible for
          establishing  and maintaining  disclosure  controls and procedures (as
          defined  in  Exchange  Act  Rules  13a-15(e)  and  15d-15(e))  for the
          registrant and have:

          (a)  Designed such disclosure controls and procedures,  or caused such
               disclosure  controls  and  procedures  to be  designed  under our
               supervision,  to ensure that material information relating to the
               registrant,  including  its  consolidated  subsidiaries,  is made
               known to us by others within those entities,  particularly during
               the period in which this report is being prepared;

          (b)  Evaluated  the  effectiveness  of  the  registrant's   disclosure
               controls  and   procedures  and  presented  in  this  report  our
               conclusions  about the  effectiveness of the disclosure  controls
               and  procedures,  as of the  end of the  period  covered  by this
               report based on such evaluation; and

          (c)  Disclosed in this report any change in the registrant's  internal
               control  over  financial   reporting  that  occurred  during  the
               registrant's most recent fiscal quarter (the registrant's  fourth
               fiscal  quarter  in  the  case  of an  annual  report)  that  has
               materially  affected,  or  is  reasonably  likely  to  materially
               affect,   the   registrant's   internal  control  over  financial
               reporting; and

     (5)  The  registrant's  other  certifying  officer(s) and I have disclosed,
          based on our most recent evaluation of internal control over financial
          reporting, to the registrant's auditors and the audit committee of the
          registrant's  board of directors (or persons performing the equivalent
          functions):

               (a)  All significant  deficiencies and material weaknesses in the
                    design or  operation  of  internal  control  over  financial
                    reporting  which are reasonably  likely to adversely  affect
                    the registrant's ability to record,  process,  summarize and
                    report financial information; and

               (b)  Any fraud, whether or not material, that involves management
                    or  other  employees  who  have a  significant  role  in the
                    registrant's internal control over financial reporting.


Date:  August 31, 2004

DAVID J. KVAPIL
------------------------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
(principal financial officer)



<PAGE>


                                                                    Exhibit 32.1


                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection  with the Form 10-K of Southern Union Company (the  "Company") for
the fiscal year ended June 30, 2004, as filed with the  Securities  and Exchange
Commission on the date hereof (the "Report"),  I, George L. Lindemann,  Chairman
of the Board and Chief Executive Officer of the Company, certify, pursuant to 18
U.S.C.  ss. 1350, as adopted  pursuant to ss. 906 of the  Sarbanes-Oxley  Act of
2002,  that to my knowledge (i) the Report fully complies with the  requirements
of Section  13(a) or 15(d) of the  Securities  Exchange Act of 1934, as amended,
and (ii)  the  information  contained  in the  Report  fairly  presents,  in all
material  respects,  the  financial  condition  and results of operations of the
Company.



GEORGE L. LINDEMANN
--------------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
August 31, 2004



This Certification is being furnished solely to accompany the Report pursuant to
18 U.S.C.  ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002,  and shall not be deemed "filed" by the Company for purposes of Section
18 of the  Securities  Exchange  Act of  1934,  as  amended,  and  shall  not be
incorporated  by reference  into any filing of the Company under the  Securities
Act of 1933,  as amended,  or the  Securities  Exchange Act of 1934, as amended,
whether  made  before  or after  the date of this  Report,  irrespective  of any
general incorporation language contained in such filing.

A signed  original of this written  statement  required by Section 906, or other
documents  authenticating,  acknowledging,  or otherwise  adopting the signature
that  appears  in typed  form  within the  electronic  version  of this  written
statement  required by Section 906, has been provided to the Company and will be
retained by the Company and furnished to the Securities and Exchange  Commission
or its staff upon request.



<PAGE>


                                                                   Exhibit 32.2


                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection  with the Form 10-K of Southern Union Company (the  "Company") for
the fiscal year ended June 30, 2004, as filed with the  Securities  and Exchange
Commission on the date hereof (the "Report"), I, David J. Kvapil, Executive Vice
President and Chief Financial  Officer of the Company,  certify,  pursuant to 18
U.S.C.  ss. 1350, as adopted  pursuant to ss. 906 of the  Sarbanes-Oxley  Act of
2002,  that to my knowledge (i) the Report fully complies with the  requirements
of Section  13(a) or 15(d) of the  Securities  Exchange Act of 1934, as amended,
and (ii)  the  information  contained  in the  Report  fairly  presents,  in all
material  respects,  the  financial  condition  and results of operations of the
Company.




DAVID J. KVAPIL
----------------------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
August 31, 2004



This Certification is being furnished solely to accompany the Report pursuant to
18 U.S.C.  ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002,  and shall not be deemed "filed" by the Company for purposes of Section
18 of the  Securities  Exchange  Act of  1934,  as  amended,  and  shall  not be
incorporated  by reference  into any filing of the Company under the  Securities
Act of 1933,  as amended,  or the  Securities  Exchange Act of 1934, as amended,
whether  made  before  or after  the date of this  Report,  irrespective  of any
general incorporation language contained in such filing.

A signed  original of this written  statement  required by Section 906, or other
documents  authenticating,  acknowledging,  or otherwise  adopting the signature
that  appears  in typed  form  within the  electronic  version  of this  written
statement  required by Section 906, has been provided to the Company and will be
retained by the Company and furnished to the Securities and Exchange  Commission
or its staff upon request.