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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D. C. 20549




                                    FORM 8-K
                                 CURRENT REPORT



     Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


         Date of Report (Date of earliest event reported) March 10, 2003




                             SOUTHERN UNION COMPANY
             (Exact name of registrant as specified in its charter)



          Delaware                    1-6407                     75-0571592
 (State or other jurisdiction of (Commission File Number)     (I.R.S. Employer
        incorporation                                        Identification No.)



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



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














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ITEM 5.  OTHER EVENTS

Effective January 1, 2003, Southern Union Company (Southern Union or the
Company) sold its Southern Union Gas natural gas operating division and related
assets located in Texas to ONEOK, Inc., which under generally accepted
accounting principles have been reported as discontinued operations beginning in
the Company's Form 10-Q for the quarterly period ended December 31, 2002.

The Company is filing updated audited historical financial statements for the
years ended June 30, 2002, 2001 and 2000 for the discontinued operations. Under
Securities and Exchange Commission (SEC) requirements, presentation of Southern
Union Gas Company's historic results as discontinued operations is required for
previously issued annual financial statements for each of the three years shown
in the Company's last annual report on Form 10-K if such filing is incorporated
by reference into subsequent filings with the SEC made under the Securities Act
of 1933, as amended. Southern Union is re-issuing these historical financial
statements at this time in connection with the filing of a Registration
Statement on Form S-3 (SEC File No. 333-102388) relating to the registration of
securities for sale by the Company.

This Current Report on Form 8-K updates only the information specifically stated
herein. All other items of the Annual Report on Form 10-K for the year ended
June 30, 2002 remain unchanged. No attempt has been made to update matters in
that Form 10-K except to the extent expressly provided above.


ITEM 7.  FINANCIAL STATEMENTS AND EXHIBITS

(c)      Exhibit No.

         99.1    Southern Union's audited financial statements, accompanying
                 notes and management's discussion and analysis of results of
                 operations and financial condition for the years ended June 30,
                 2002, 2001 and 2000 updated to reflect the Company's
                 discontinued operations due to the sale of Southern Union Gas
                 and related assets.

         99.2    Consent of Independent Accountants.










<PAGE>



                                    SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.


                                                  SOUTHERN UNION COMPANY
                                                       (Registrant)



Date     March 10, 2003                          By  DAVID J. KVAPIL
         --------------                              -----------------------
                                                     David J. Kvapil
                                                     Executive Vice President
                                                     and Chief Financial Officer


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                                                                                     EXHIBIT 99.1

                           SOUTHERN UNION COMPANY AND SUBSIDIARIES

                                      Index

                                                                                          Page(s)
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Management's Discussion and Analysis of Results of Operations and Financial
  Condition                                                                               1 to 16

Selected Financial Data .............................................................       17

Financial Statements:
     Consolidated statement of operations -- years ended June 30, 2002,
         2001 and 2000 ..............................................................       F-1
     Consolidated balance sheet -- June 30, 2002 and 2001 ...........................    F-2 to F-3
     Consolidated statement of cash flows -- years ended June 30, 2002,
         2001 and 2000 ..............................................................       F-4
     Consolidated statement of common stockholders' equity -- years ended
        June 30, 2002, 2001 and 2000 ................................................       F-5
     Notes to consolidated financial statements .....................................    F-6 to F-32
     Report of independent accountants ..............................................       F-33


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<S>     <C>    <C>    <C>    <C>    <C>    <C>

                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION


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Overview Southern Union Company's (Southern Union and together with its
subsidiaries, the Company) core business is the distribution of natural gas as a
public utility through its three operating divisions. Missouri Gas Energy serves
498,000 customers in central and western Missouri (including Kansas City, St.
Joseph, Joplin and Monett). PG Energy (acquired in November 1999) serves 157,000
customers in northeastern and central Pennsylvania (including Wilkes-Barre,
Scranton and Williamsport). New England Gas Company (acquired in September 2000)
serves 295,000 customers in Rhode Island and Massachusetts (including
Providence, Newport and Cumberland, Rhode Island, and Fall River, North
Attleboro and Somerset, Massachusetts). South Florida Natural Gas, which was
sold in December 2001, served 4,500 customers in central Florida (including New
Smyrna Beach, Edgewater and areas of Volusia County, Florida). Southern Union
Gas, which was sold in January 2003, served 541,000 customers in Texas
(including Austin, Brownsville, El Paso, Galveston, Harlingen, McAllen and Port
Arthur).

Effective January 1, 2003, the Company sold its Southern Union Gas natural gas
operating division and related assets to ONEOK, Inc. for approximately
$420,000,000 in cash. 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). Mercado markets natural gas to commercial and industrial customers.
SUPro provides 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 owns and operates 118.8 miles of
intrastate pipeline that serves commercial, industrial and utility customers in
central, south and coastal Texas. SUEI and Investments participate in
energy-related projects internationally. Energia Estrella del Sur,
S. A. de C. V., a wholly-owned Mexican subsidiary of SUEI and Investments, has a
43% equity ownership in a natural gas distribution company, along with other
related operations, which currently serves 23,000 customers in Piedras Negras,
Mexico, across the border from Southern Union Gas' Eagle Pass, Texas service
area. Norteno owns and operates interstate pipelines that serve the gas
distribution properties of Southern Union Gas and the Public Service Company of
New Mexico. Norteno also transports gas through its interstate network to the
country of Mexico for Pemex Gas y Petroquimica Basica. In accordance with the
Financial Accounting Standards Board (FASB) standard, Accounting for the
Impairment or Disposal of Long-Lived Assets, the assets to be sold and
liabilities to be assumed from the Texas Operations have been segregated and
reported as "held for sale" in the consolidated balance sheet. In addition, the
related results of operation have been segregated and reported as "discontinued
operations" in the consolidated statement of operations and consolidated
statement of cash flows for all periods presented in this document.  The Company
anticipates that the proceeds from the sale will qualify as part of a like-kind
exchange of property covered by Section 1031 of the Internal Revenue Code
thereby enabling the Company to achieve certain tax deferrals.

In September 2000, Southern Union acquired Providence Energy Corporation
(ProvEnergy), Fall River Gas Company (Fall River Gas), and Valley Resources
(Valley Resources). Collectively, these companies (hereafter referred to as the
Company's New England Operations) were acquired for approximately $422,000,000
in cash and 1,370,629 shares (before adjustment for any subsequent stock
dividends) of Southern Union common stock, as well as the assumption of
approximately $140,000,000 in long-term debt. The results of operations from
ProvEnergy and Fall River Gas have been included in the Company's consolidated
statement of operations since September 28, 2000, and the results of operations
from Valley Resources have been included in the Company's consolidated statement
of operations since September 20, 2000. Thus, the Company's consolidated results
of operations for the periods subsequent to these acquisitions are not
comparable to the same periods in prior years. These acquisitions were accounted
for using the purchase method.

The New England Operations' primary business is the distribution of natural gas
through the New England Gas Company. Subsidiaries of the Company acquired with
the New England Gas Company and currently operating include ProvEnergy Power LLC
(ProvEnergy Power), Fall River Gas Appliance Company (Fall River Appliance),
                                       1
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Valley Appliance Merchandising Company (VAMCO) and Alternate Energy Corporation
(AEC). ProvEnergy Power provides outsourced energy management services and owns
50% of Capital Center Energy Company LLC, a joint venture formed between
ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air.
Fall River Appliance rents water heaters and conversion burners, primarily to
residential customers. VAMCO rents natural gas burning appliances and offers
appliance service contract programs to residential customers. In fiscal 2002,
VAMCO also provided construction management services for natural gas-related
projects to commercial and industrial customers. AEC is an energy consulting
firm.

Subsidiaries acquired with the New England Gas Company and subsequently sold
include Morris Merchants, Inc. (Morris Merchants), Valley Propane, Inc. (Valley
Propane) and ProvEnergy Oil Enterprises, Inc. (ProvEnergy Oil). In October 2001,
Morris Merchants, 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, which sold liquid
propane to residential, commercial and industrial customers, was sold for
$5,301,000. In August 2001, ProvEnergy Oil, 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.

In November 1999, Southern Union acquired Pennsylvania Enterprises, Inc.
(hereafter referred to as the Company's Pennsylvania Operations) for
approximately $500,000,000, including assumption of approximately $115,000,000
of long-term debt. The Company issued approximately 16,700,000 shares (before
adjustment for any subsequent stock dividends) of common stock and paid
approximately $38,000,000 in cash to complete the transaction. The results of
operations from the Pennsylvania Operations have been included in the Company's
consolidated statement of operations since November 4, 1999. Thus, the Company's
consolidated results of operations for the periods subsequent to the acquisition
are not comparable to the same periods in prior years. The acquisition was
accounted for using the purchase method.

The Pennsylvania Operations' primary business is the distribution of natural gas
through PG Energy. Subsidiaries of the Company acquired with PG Energy and
currently operating include PG Energy Services Inc., (Energy Services) and PEI
Power Corporation (Power Corp.). Energy Services offers the inspection,
maintenance and servicing of residential and small commercial gas-fired
equipment to residential and commercial users. Power Corp., an exempt wholesale
generator (within the meaning of the Public Utility Holding Company Act of
1935), sells electricity to the broad mid-Atlantic wholesale energy market
administered by PJM Interconnection, L.L.C.

Subsidiaries and assets acquired with PG Energy and subsequently sold include
Energy Services' propane operations and its commercial and industrial gas
marketing contracts, Keystone Pipeline Services, Inc. (Keystone) and Theta Land
Corporation. In April 2002, 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 June 2001, the Company
sold Keystone, which engaged primarily in the construction, maintenance, and
rehabilitation of natural gas distribution pipelines, for $3,300,000, resulting
in a pre-tax gain of $707,000. In January 2000, Theta Land Corporation, which
owned approximately 44,000 acres of land, was sold for $12,150,000. No financial
gain or loss was recognized on this transaction.

                  Results of Operations - Continuing Operations

Net Earnings Southern Union Company's 2002 (fiscal year ended June 30) net
earnings from continuing operations were $1,520,000 ($.03 per common share,
diluted for outstanding options and warrants -- hereafter referred to as per
share), compared with $40,159,000 ($.70 per share) in 2001. Net earnings for the
year ended June 30, 2002, were impacted by lower operating margin resulting from
unusually mild weather that was 19% warmer than in 2001, an after-tax
restructuring charge of $8,990,000 and a non-cash charge to reserve for the
impairment of the Company's investment in a technology company of $3,200,000,
net of tax. These items were partially offset by $5,292,000 in after-tax gains
generated from the settlement of interest rate swaps. Net earnings in 2002 also
reflect the absence of significant sales of the Company's holdings in Capstone
Turbine Corporation and real estate, which generated after-tax gains of
$42,631,000 in 2001. In addition, net earnings in 2001 reflect goodwill
amortization of $14,992,000 while goodwill amortization ceased in 2002 as a
result of the adoption of a new accounting pronouncement. Average common and
common share equivalents outstanding decreased 2% in

                                       2

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2002 due to the repurchase of 2,115,916 shares of the Company's common stock.
Substantially all of these repurchases occurred in private off-market
large-block transactions.

The Company's 2001 net earnings from continuing operations were $40,159,000
($.70 per share), compared with a loss from continuing operations of $10,251,000
($.21 loss per share) in 2000. Net earnings for the year ended June 30, 2001
were positively impacted by the sale of a portion of Southern Union's holdings
in Capstone Turbine Corporation realizing after-tax gains of $42,631,000. Net
earnings in 2001 also reflect the acquisition of the New England Operations that
contributed $8,002,000 in net earnings. While operating margin benefited from
weather that was 27% colder than 2000, purchased gas costs increased over 79% in
2001 compared with the prior year resulting in an increase in bad debt expense
of $13,644,000, net of tax. Average common and common share equivalents
outstanding increased 15% in 2001 due to the issuance of 1,370,629 shares and
16,713,735 shares, before adjustment for any subsequent stock dividends, of the
Company's common stock in connection with the acquisition of Fall River Gas and
the Pennsylvania Operations, respectively.

Operating Revenues Operating revenues in 2002 compared with 2001 decreased
$481,197,000, or 33%, to $980,614,000 while gas purchase and other energy costs
decreased $458,619,000, or 44%, to $573,077,000.

The decrease in both operating revenues and gas purchase and other energy costs
between periods was primarily due to a 17% decrease in gas sales volumes to
101,112 MMcf in 2002 from 122,134 MMcf in 2001 and by a 23% decrease in the
average cost of gas from $7.32 per Mcf in 2001 to $5.63 per Mcf in 2002. The
decrease in gas sales volumes is primarily due to warmer-than-normal weather in
all of the Company's service territories as compared to colder-than-normal
weather in 2001. The decrease in the average cost of gas is due to decreases 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 current
competitive pricing occurring within the entire energy industry. Additionally
impacting operating revenues in 2002 was a $16,460,000 decrease in gross receipt
taxes primarily due to a decrease 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. The decrease in operating revenues in 2002
was partially offset by the timing of the acquisition of the New England
Operations in September 2000, as well as the $10,973,000 annual revenue increase
granted to Missouri Gas Energy effective August 2001 and the $10,800,000 annual
revenue increase granted to PG Energy effective January 2001.

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, operating margin is 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 2002 increased 2,007 MMcf to 65,757 MMcf at an
average transportation rate per Mcf of $.56 in 2002 and $.53 in 2001.

Operating revenues in 2001 compared with 2000 increased $894,978,000, or 158%,
to $1,461,811,000 while gas purchase and other energy costs increased
$685,778,000, or 198%, to $1,031,696,000.

The increase in both operating revenues and gas purchase and other energy costs
between periods was primarily due to a 71% increase in gas sales volumes to
122,134 MMcf in 2001 from 71,256 MMcf in 2000 and by a 79% increase in the
average cost of gas from $4.09 per Mcf in 2000 to $7.32 per Mcf in 2001. The
increase in the average cost of gas was 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. The acquisition of the New England
Operations contributed $429,074,000 to the overall increase in operating
revenues, $270,599,000 in gas purchase and other energy costs and 32,012 MMcf of
the increase in gas sales volume. The Pennsylvania Operations generated a net
increase from 2000 to 2001 of $155,093,000 in operating revenues, $135,766,000
in gas purchase and other energy costs, and 5,557 MMcf of the increase in gas
sales volume. Additionally impacting operating revenues in 2001 was a
$25,272,000 increase in gross receipt taxes primarily due to an increase in gas
purchase and other energy costs in the Missouri service territories in 2001 as
compared to 2000 as well as the acquisition of the New England Operations. The
remaining increase in operating revenues, gas purchase and other energy costs,
and gas sales volume resulted principally from the colder-than-normal weather in
the Missouri service territories in 2001 as compared to the unusually mild
temperatures in 2000.
                                       3

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Gas transportation volumes in 2001 increased 12,703 MMcf to 63,750 MMcf at an
average transportation rate per Mcf of $.53 compared with $.46 in 2000. The New
England Gas Company contributed an increase of 7,399 MMcf, while PG Energy
experienced a net increase of 6,027 MMcf in 2001.

Operating Margin Operating margin in 2002 (operating revenues less gas purchase
and other energy costs and revenue-related taxes) decreased by $6,118,000,
compared with an increase of $183,928,000, in 2001. Operating margins 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 and divestitures. Sales volumes, which
benefited from colder-than-normal weather in 2001, were negatively impacted by
unusually mild temperatures throughout fiscal year 2002 as well as in 2000. If
normal weather had been present throughout the Company's service territories in
2002 and 2000, operating margin would have increased by approximately
$26,849,000 and $17,978,000, respectively. Missouri, Pennsylvania and New
England accounted for 37%, 24% and 39%, respectively, of the Company's operating
margin in 2002 and 37%, 23% and 39%, respectively, in 2001.

Weather Weather in the Missouri Gas Energy service territories in 2002 was 85%
of a 30-year measure, 20% warmer than in 2001. Weather in the PG Energy service
territories in 2002 was 86% of a 30-year measure, 19% warmer than in 2001.
Weather in the New England service territories in 2002 was 85% of a 30-year
measure, 17% warmer than the nine months ended June 30, 2001.

Weather in Missouri in 2001 was 106% of a 30-year measure, 33% colder than in
2000. Weather in Pennsylvania in 2001 was 105% of a 30-year measure, 14% colder
than for the eight months ended June 30, 2000. Weather in New England was 102%
of a 30-year measure for the nine months ended June 30, 2001.

Customers The average number of customers served in 2002, 2001 and 2000 was
942,849, 970,927 and 605,000, respectively. Changes in customer totals between
years primarily reflect the impact of acquisitions and divestitures. Missouri
Gas Energy served 487,602 customers in central and western Missouri. PG Energy
served 155,870 customers in northeastern and central Pennsylvania, and New
England Gas Company served 290,417 customers in Rhode Island and Massachusetts
during 2002. South Florida Natural Gas and Atlantic Gas Corporation, a propane
subsidiary of the Company, served 4,376 and 661 customers, respectively, until
their sale in December 2001. In Rhode Island and Massachusetts, Valley Propane,
which was sold in September 2001, served 2,800 propane customers while
ProvEnergy Fuels, Inc., served 14,900 fuel oil customers until its sale in
August 2001. Energy Services served 2,600 propane customers until April 2002,
when the propane operations were sold.

Operating Expenses Operating, maintenance and general expenses in 2002 decreased
$15,321,000, or 8%, to $171,147,000. A decrease in bad debt expense of
$15,000,000 resulted from a decrease in delinquent customer receivables as a
result of lower gas prices and warmer weather in 2002 as compared with 2001.
Additionally, in connection with the Company's Cash Flow Improvement Plan
announced in July 2001 and discussed below, the Company realized savings of
approximately $10,600,000 during 2002 primarily due to the acceptance of
voluntary Early Retirement Programs (ERPs) in certain of its operating divisions
and a limited reduction in force (RIF) within its corporate offices. In
connection with the Cash Flow Improvement Plan, the Company divested of certain
non-core assets in fiscal year 2002 which contributed $5,557,000 more in
operating expenses in 2001 as compared with 2002. Southern Union has begun to
recover certain amounts from various insurance carriers for past and future
environmental expenditures. To the extent that such related past expenditures
had been expensed by the Company, a portion of these recoveries are recorded as
a reduction to operating expenses. During 2002, the Company recognized a
reduction in operating expenses of $2,591,000 for past environmental
expenditures. See Commitments and Contingencies in the Notes to the Consolidated
Financial Statements. These items were partially offset by $12,931,000 of
increased operating expenses in 2002 due to the timing of the acquisition of the
New England Operations, and $6,225,000 of increased pension and other
postretirement benefits expense, primarily due to volatility in the stock
markets.

Depreciation and amortization expense in 2002 decreased $10,172,000 to
$58,989,000. The decrease was primarily due to the elimination of goodwill
amortization resulting from the Company's adoption of Goodwill and Other
Intangible Assets effective July 1, 2001. In accordance with this Standard, the
Company has ceased the amortization of goodwill, which generated $14,992,000 of
expense in 2001, and currently accounts for goodwill on

                                       4

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an impairment-only approach. See Other Matters -- Critical Accounting Policies
and Goodwill in the Notes to the Consolidated Financial Statements. The decrease
in 2002 also reflects $5,941,000 of reduced depreciation expense from reduced
depreciation rates in Missouri as a result of changes in the previously
mentioned rate settlement. These items were partially offset by $5,845,000 of
increased depreciation expense in 2002, due to the timing of the acquisition of
the New England Operations, and normal growth in plant. Additionally, in
connection with the previously mentioned Cash Flow Improvement Plan, the Company
began the divestiture of certain non-core subsidiaries and 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 in 2002. See Goodwill in the Notes to
the Consolidated Financial Statements.

Taxes other than on income and revenues, principally consisting of property,
payroll and state franchise taxes increased $356,000 to $23,708,000 in 2002.
Increases in property taxes were partially offset by decreases in payroll taxes
due to a reduction in employees resulting from the Company's reorganization and
restructuring initiatives as well as from the sale of non-core subsidiaries and
assets.

Operating, maintenance and general expenses in 2001 increased $96,728,000, or
108%, to $186,468,000. Increases of $65,878,000 and $12,737,000 were the result
of the acquisitions of the New England Operations and the Pennsylvania
Operations, respectively. An increase in bad debt expense in the Missouri
service territories of $14,457,000 resulted from an increase in delinquent
customer receivables as a result of higher gas prices and colder weather. Also
impacting operating expenses were increases in employee payroll and benefit
costs.

Depreciation and amortization expense in 2001 increased $31,243,000 to
$69,161,000 as a result of the acquisition of the New England Operations and the
Pennsylvania Operations and normal growth in plant. Taxes other than on income
and revenues increased $11,363,000 to $23,352,000 in 2001. The increase was also
primarily the result of the acquisition of the New England Operations.

Business Restructuring Charges Business reorganization and restructuring
initiatives were commenced in August 2001 as part of a previously announced Cash
Flow Improvement Plan designed to increase annualized pre-tax cash flow from
operations by at least $50 million by the end of fiscal year 2002. Actions taken
by the Company 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. As a result of actions
associated with the business reorganization and restructuring, the Company
expects an annual cost savings in a range of $30 million to $35 million. In
connection with the corporate reorganization and restructuring efforts, the
Company recorded a one-time 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 have been completed as of
June 30, 2002. See Business Restructuring Charges in the Notes to the
Consolidated Financial Statements.

Employees The Company's continuing operations employed 1,855, 2,404 and 1,641
individuals as of June 30, 2002, 2001 and 2000, 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.

During fiscal year 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 (formerly Valley Resources), effective May 2002;
a four-year contract with one bargaining unit representing employees of New
England Gas Company's Fall River operations (formerly Fall River Gas), effective
April 2002; and a one year extension of a contract with one bargaining unit
representing employees of
                                       5

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New England Gas Company's Cumberland operations, which was effective May 2002.

During fiscal 2001, the Company agreed to three-year contracts with two
bargaining units representing Pennsylvania employees, which were effective in
April 2001 and August of 2000, respectively. In December 1998, the Company
agreed to five-year contracts with each bargaining-unit representing Missouri
employees, which were effective in May 1999.

Interest Expense and Dividends on Preferred Securities Total interest expense in
2002 decreased by $11,936,000, or 12%, to $90,992,000. Interest expense
decreased by $11,299,000 in 2002 on the $485,000,000 bank note (the 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 Term Note interest was due to significant reductions in LIBOR
rates during 2002 and the principal repayment of $135,000,000 of the Term Note
during 2002.

Interest expense on short-term debt in 2002 decreased from $7,913,000 to
$7,187,000, primarily due to the significant decrease in LIBOR rates during
2002, which was partially offset by an increase in the average amount of
short-term debt outstanding from $123,829,000 to $176,600,000 during the year.
The increase in the average amount of short-term debt outstanding during 2002
was primarily due to (i) higher than normal beginning short-term debt
outstanding due to high gas costs and accounts receivable in 2001, (ii) an
increase in the Company's seasonal borrowing requirements due to the acquisition
of the New England Operations, and (iii) the repayment of various principal
amounts of the Term Note with borrowings under the Company's credit facilities.
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. The average rate of interest on short-term debt decreased
from 6.4% to 3.2% in 2002.

Total interest expense in 2001 increased by $51,975,000, or 102%, to
$102,928,000. Interest expense on long-term debt and capital leases increased by
$46,725,000 in 2001 primarily due to the Term Note entered into by the Company
for the acquisition of the New England Operations, the issuance of $300,000,000
of 8.25% Senior Notes on November 3, 1999 (8.25% Senior Notes) for the
acquisition of the Pennsylvania Operations and the assumption of debt by the
Company from the New England Operations and Pennsylvania Operations. The 8.25%
Senior Notes were issued to fund the acquisition of Pennsylvania Enterprises,
Inc. and to extinguish $135,000,000 in existing debt of the Pennsylvania
Operations. The Company assumed $113,321,000 in long-term debt of the New
England Operations and $45,000,000 in long-term debt of the Pennsylvania
Operations which was not refinanced or extinguished with the Term Note or the
8.25% Senior Notes.

Interest expense on short-term debt in 2001 increased $6,647,000 to $7,913,000
primarily due to the increase in the average short-term debt outstanding by
$102,827,000 to $123,829,000. An increase in the average outstanding balance of
short-term credit facilities reflects the higher cost of gas and the expansion
of the Company's operations into Rhode Island and Massachusetts with the
acquisition of the New England Operations during 2001. The average rate of
interest on short-term debt increased from 6% in 2000 to 6.4% in 2001.

Other Income (Expense), Net Other income, net, in 2002 was $14,278,000, compared
with $81,401,000 in 2001. Other income in 2002 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 Turbine Corporation (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 Gas Corporation (Southwest), and a $1,500,000 loss on the sale of
South Florida Natural Gas, a natural gas division of Southern Union, and
Atlantic Gas Corporation, a Florida propane subsidiary of the Company.

                                       6

<PAGE>
Other income in 2001 of $81,401,000 included realized gains on the sale of
investment securities of $74,582,000, a $13,532,000 gain on the sale of non-core
real estate and $6,838,000 of interest and dividend income. These items were
partially offset by $12,855,000 of legal costs associated with Southwest.

Other expense in 2000 of $8,601,000 included $10,363,000 of legal costs
associated with Southwest. This item was partially offset by net rental income
of Lavaca Realty Company of $1,757,000.

Federal and State Income Taxes Federal and state income tax expense from
continuing operations in 2002 and 2001 was $3,411,000 and $30,099,000,
respectively. Federal and state income tax benefit in 2000 was $2,112,000. The
Company's consolidated federal and state effective income tax rate was 69%, 43%
and 17% in 2002, 2001 and 2000, respectively. The fluctuation in the effective
federal and state income tax rate in 2002 compared with 2001 is primarily the
result of the sale of the Florida Operations in 2002 which had non-tax
deductible goodwill on its financial statements, along with the change in the
level of pre-tax earnings.  The fluctuation in the effective federal and state
income tax rate in 2001 compared with 2000 was impacted by the change in the
level of goodwill amortization due to the acquisitions of the Pennsylvania
Operations and the New England Operations, along with the fluctuation in the
level of pre-tax earnings.

                 Results of Operations - Discontinued Operations

Net Earnings Net earnings from discontinued operations were $18,104,000 ($.32
per share) in 2002 compared with $16,524,000 ($.29 per share) in 2001. The
increase in earnings from discontinued operations was impacted by a $4,379,000
pre-tax reduction in bad debt expense due to a decrease in delinquent customer
receivables resulting from lower gas prices and warmer weather in 2002 as
compared with 2001, and the absence of expense in 2002 relating to financial
derivative energy trading activity of a former subsidiary which generated
$5,685,000 of pre-tax losses in 2001. These items were partially offset by a
$3,286,000 decrease in operating margin primarily due to a reduction in sales
volumes from 54,520 MMcf in 2001 to 49,115 MMcf in 2002 as a result of weather
that was 93% of normal in 2002 as compared with 112% of normal in 2001.
Additionally in 2002, the Texas Operations recorded a one-time pre-tax charge of
$2,153,000 in connection with the previously discussed reorganization and
restructuring efforts under the Cash Flow Improvement Plan.

Net earnings from discontinued operations were $16,524,000 ($.29 per share) in
2001 compared with $20,096,000 ($.41 per share) in 2000. The decrease in
earnings from discontinued operations was impacted by a $4,322,000 pre-tax
increase in bad debt expense due to an increase in delinquent customer
receivables resulting from higher gas prices and colder weather in 2001 as
compared with 2000, and the recording of $3,449,000 of additional pre-tax losses
relating to financial derivative trading activity of a former subsidiary in 2001
as compared with 2000. Also impacting operating expenses in 2001 were increases
in employee payroll and benefit costs. These items were partially offset by a
$6,224,000 increase in operating margin primarily due to an increase in sales
volumes from 48,522 MMcf in 2000 to 54,520 MMcf in 2001 as a result of weather
that was 112% of normal in 2001 as compared with 71% of normal in 2000.

                         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, debt service and certain tax payments.
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 to meet its short-term cash needs.

The Company has increased the scale of its natural gas operations and the size
of its customer base by pursuing and consummating business combination
transactions. On September 20, 2000, the Company acquired Valley Resources, on
September 28, 2000, the Company acquired both Fall River Gas and ProvEnergy, and
on November 4, 1999, the Company acquired the Pennsylvania Operations. See
Acquisitions and Divestitures in the Notes to the Consolidated Financial
Statements. 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
                                       7

<PAGE>
weather conditions. Future acquisitions or merger-related 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 Other
Matters -- Cautionary Statement Regarding Forward-Looking Information.

Cash flows from operating activities before changes in operating assets and
liabilities for 2002 were $177,715,000 compared with $94,465,000 and $72,305,000
for 2001 and 2000, respectively. After changes in operating assets and
liabilities, cash flows from operating activities were $273,616,000 in 2002
compared with cash flows used in operating activities of $147,099,000 in 2001
and cash flows from operating activities of $66,865,000 for 2000. Changes in
operating assets and liabilities provided cash of $95,901,000 in 2002. Changes
in operating assets and liabilities used cash of $241,564,000 and $5,440,000 in
2001 and 2000, respectively. The current year changes in operating assets and
liabilities reflect the collection of the unusually high accounts receivable
balance that occurred due to the high gas costs during the winter season of 2001
that negatively impacted the Company's collection efforts and the recovery of
over $53 million in deferred purchased gas costs that the Company incurred
during 2001 due to the regulatory lag in passing along such increased purchased
gas costs to customers. The timing of acquisitions and the timing of natural gas
purchases stored in inventory also impacted operating activities in prior years.

At June 30, 2002, 2001 and 2000, the Company's primary source of liquidity
included borrowings available under the Company's credit facilities. On June 10,
2002, the Company entered into a short-term credit facility in the amount of
$150,000,000 (the Short-Term Facility) that matures on June 9, 2003. The
Short-Term Facility replaced another short-term credit facility for the same
principal amount that expired on May 28, 2002. Also on June 10, 2002, the
Company amended the terms and conditions of its $225,000,000 long-term credit
facility (the Long-Term Facility), which expires on May 29, 2004. The Company
has additional availability under uncommitted line of credit facilities
(Uncommitted Facilities) with various banks. Borrowings under the Short-Term
Facility and Long-Term Facility (together, the Facilities) are available for
Southern Union's working capital, letter of credit requirements and other
general corporate purposes. The Facilities are subject to a commitment fee based
on the rating of the Senior Notes. As of June 30, 2002, the commitment fees were
an annualized 0.13% on the Short-Term Facility and 0.15% on the Long-Term
Facility. The Facilities require the Company to meet certain covenants in order
for the Company to be able to borrow under those agreements. A balance of
$131,800,000 and $190,600,000 was outstanding under the Facilities at June 30,
2002 and 2001, respectively. As of August 31, 2002 there was a balance of
$227,500,000 outstanding under these Facilities.

The Company leases certain facilities, equipment and office space under
cancelable and noncancelable operating leases. The minimum annual rentals from
continuing operations under operating leases for the next five years ending June
30 are as follows: 2003-- $3,003,000; 2004-- $2,645,000; 2005-- $2,283,000;
2006-- $2,206,000; 2007-- $2,539,000 and thereafter $4,737,000. The Company is
also committed under various agreements to purchase certain quantities of gas in
the future. At June 30, 2002, the Company has purchase commitments from
continuing operations for certain quantities of gas at variable, market-based
prices that have an annual value of $73,885,000. 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 in 2002 decreased
$395,527,000 to $39,226,000. Cash flow used in investing activities increased by
$283,887,000 to $434,753,000 in 2001. Investing activity cash flow was primarily
affected by additions to property, plant and equipment, acquisition and sales of
operations, sales and purchases of investment securities, the sale of non-core
real estate and other assets, and the settlement of interest rate swaps.

During 2002, 2001 and 2000, the Company expended $70,698,000, $100,752,000 and
$70,971,000, respectively, for capital expenditures excluding acquisitions.
These expenditures primarily related to distribution system replacement and
expansion. Included in these capital expenditures were $7,860,000, $14,040,000
and $14,286,000 for the Missouri Gas Energy Safety Program in 2002, 2001 and
2000, respectively. Cash flow from operations has historically been utilized to
finance capital expenditures and is expected to be the primary source for future
capital expenditures.

                                       8

<PAGE>
During 2002, the Company sold non-core subsidiaries and assets, which generated
proceeds of $40,935,000, resulting in net pre-tax gains of $4,914,000. In 2001,
Southern Union sold its Austin, Texas headquarters building, Lavaca Plaza, for
$20,638,000, resulting in a pre-tax gain of $13,532,000 and also disposed of a
former subsidiary of the Pennsylvania Operations, which generated proceeds of
$3,300,000 resulting in a pre-tax gain of $707,000. In January 2000, a former
subsidiary of the Pennsylvania Operations was sold for $12,150,000. No financial
gain or loss was recognized on this transaction.

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.

In September 2000, Southern Union acquired the New England Operations for
1,370,629 pre-stock dividend shares of Southern Union common stock and
$414,497,000 in cash. In November 1999, Southern Union acquired the Pennsylvania
Operations for 16,713,735 pre-stock dividend shares of common stock and
$38,366,000 in cash. On the date of acquisition, Pennsylvania Operations had
$576,000 in cash and cash equivalents.

During 2002 and 2001, the Company sold a portion of its investment holdings in
Capstone for $1,213,000 and $84,762,000, respectively, resulting in pre-tax
gains of $1,004,000 and $74,582,000, respectively. During 2002, 2001 and 2000,
the Company purchased investment securities of $938,000, $12,495,000 and
$21,001,000, respectively.

Pursuant to a 1989 Missouri Public Service Commission (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 $9,602,000
in 2003 related to this program and up to $170 million over the remaining life
of the program of 17 years.

Financing Activities Cash flow used in financing activities was $235,609,000 in
2002 compared to cash flow from financing activities of $555,242,000 and
$111,830,000 in 2001 and 2000, respectively. Financing activity cash flow
changes were primarily due to the net impact of acquisition financing, repayment
of debt, net activity under the revolving credit facilities and purchase of
treasury stock. As a result of these financing transactions, the Company's total
debt to total capital ratio at June 30, 2002 was 60.3%, compared with 61.9% and
46.8% at June 30, 2001 and 2000, respectively. The Company's effective debt cost
rate under the current debt structure is 6.60% (which includes interest and the
amortization of debt issuance costs and redemption premiums on refinanced debt).

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. As of June 30, 2002, a balance of $350,000,000 was outstanding on this
Term Note. 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 the Facilities. The 2002 Term
Note requires semi-annual principal repayments on February 15th and August 15th
of each year, with payments of $25,000,000 each being due February 15, 2003,
August 15, 2003, February 15, 2004, and August 15, 2004 and payments of
$35,000,000 each being due February 15, 2005 and August 15, 2005. The remaining
principal amount of $141,087,000 is due August 26, 2005. No additional draws can
be made on the 2002 Term Note. The interest rate on borrowings under the 2002
Term Note is a floating rate based on LIBOR or prime interest rates. See
Quantitative and Qualitative Disclosures About Market Risk.

                                       9

<PAGE>
Concurrent with the acquisition of the Pennsylvania Operations on November 4,
1999, the Company issued $300,000,000 of 8.25% Senior Notes due 2029 which were
used to: (i) fund the cash portion of the consideration to be paid to the
Pennsylvania Operations shareholders; (ii) refinance and repay certain debt of
Pennsylvania Operations, and (iii) repay outstanding borrowings under the
Company's various credit facilities. These senior notes are senior unsecured
obligations and rank equally in right of payment with each other and with the
Company's other unsecured and unsubordinated obligations, including the 7.60%
Senior Notes due 2024. In connection with the acquisition of the Pennsylvania
Operations, the Company assumed $30,000,000 of 8.375% Series First Mortgage
Bonds due in December 2002 and $15,000,000 of 9.34% Series First Mortgage Bonds
due in 2019.

On December 6, 2001 and October 19, 2001, respectively, the Company filed shelf
registrations for $200,000,000 of subordinated debt securities and preferred
securities of financing trusts and $400,000,000 of senior debt securities.
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 currently has
regulatory approval to issue up to $88,900,000 of these securities for certain
uses.

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 June 6, 2002, Moody's Investor Service, Inc. (Moody's) reduced its credit
rating on the Company's senior unsecured debt to Baa3 with a stable outlook from
Baa2 with a negative outlook. The Company's senior unsecured debt is currently
rated BBB+ by Standard and Poor's Rating Information Service (S&P), a rating
that it has held since April 1998. Although no further downgrades are
anticipated, such an event would not 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 $30,541,000 at June 30,
2002 and $2,716,000 at June 30, 2001, which guarantee payment of natural gas
purchases, insurance claims and other various commitments.

           Quantitative and Qualitative Disclosures About Market Risk

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

At June 30, 2002, the Company had issued fixed-rate long-term debt, capital
lease and Preferred Securities aggregating $940,413,000 in principal amount and
having a fair value of $924,647,000. 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 $59,335,000 if interest and dividend rates were to
decline by 10% from their levels at June 30, 2002. 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 $481,800,000 at June 30, 2002
and primarily consisted of the Term Note entered into by the Company for the
acquisition of the New England Operations and amounts borrowed under the
Facilities of the Company. The floating-rate obligations under the Term Note and
the Facilities 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, 2002 levels, the Company's consolidated
interest expense would increase by a total of approximately $112,000 each month
in which such increase continued.

                                       10

<PAGE>
The risk of an economic loss is reduced at this time as a result of the
Company's regulated status. Any unrealized gains or losses are accounted for in
accordance with the FASB Accounting for the Effects of Certain Types of
Regulation as a regulatory asset/liability.

The change in exposure to loss in earnings and cash flow related to interest
rate risk from June 30, 2001 to June 30, 2002 is not material to the Company.

See Preferred Securities of Subsidiary Trust and Debt and Capital Lease in the
Notes to the Consolidated Financial Statements.

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 in January 2002. The TIF Debt bears interest at a
floating rate with a floor of 6.0% and a ceiling of 7.75% and matures on June
30, 2011. The loan requires interest-only payments until June 30, 2003, and
semi-annual interest and principal payments thereafter. As of June 30, 2002, the
interest rate on the TIF Debt is 6.0% and estimated incremental tax revenues are
expected to cover approximately 45% of the fiscal year 2003 annual debt service.
The balance outstanding on the TIF Debt was $9,710,000 as of June 30, 2002.

In accordance with adoption of FASB standard, Accounting for Derivative
Instruments and Hedging Activities on July 1, 2000 the Company recorded a
net-of-tax cumulative-effect gain of $602,000 in earnings to recognize the fair
value of the gas derivative contracts at Energy Services that are not designated
as hedges. The Company also recorded $826,000 in accumulated other comprehensive
income which recognizes the fair value of two interest rate swap derivatives
that were designated as cash flow hedges.

During fiscal year 2002, the Company was party to three interest rate swaps that
were created to manage exposure against volatility in interest payments on
variable rate debt and which qualify for hedge accounting. As of June 30, 2002,
$954,000 in after-tax comprehensive income generated through the expiration of
two of these swaps was partially offset by the fair value of the Company's
remaining obligation under one swap which resulted in $150,000 of unrealized
losses, net of tax. For the fiscal year ended June 30, 2002, the Company
recorded net settlement payments of $1,408,000 on these swaps through interest
expense. Hedge ineffectiveness, which is recorded in interest expense, was
immaterial for fiscal 2002. No component of the swaps' gain or loss was excluded
from the assessment of hedge effectiveness. At June 30, 2002, the fair value of
the remaining interest rate swap was a liability of $519,000 and is offset by a
matching adjustment to other comprehensive income. The Company expects to
reclassify as interest expense $291,000 in derivative losses, net of taxes, from
accumulated other comprehensive income as the settlement of swap payments occur
over the next twelve months. The maximum term over which the Company is hedging
exposures to the variability of cash flows is 17 months. During fiscal year
2001, the Company was party to an interest rate swap designed to reduce exposure
to changes in the fair value of a fixed rate lease commitment. This interest
rate swap, designated as a fair value hedge, was terminated in October 2000
resulting in a pre-tax gain of $182,000.

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 a deferred liability of
$7,921,000 at June 30, 2001. For the fiscal year ended June 30, 2002, the
Company recorded $6,204,000 through other income relating to the expiration of
contracts resulting from this trading activity. The majority of the remaining
deferred liability of $1,717,000 at June 30, 2002 related to these derivative
instruments will be recognized as income in the Consolidated Statement of
Operations over the next three years 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.

                                       11

<PAGE>
                                  Other Matters

Stock Splits and Dividends On July 15, 2002, August 30, 2001, June 30, 2000 and
August 6, 1999, Southern Union distributed a 5% common stock dividend to
stockholders of record on July 1, 2002, August 16, 2001, June 19, 2000 and July
23, 1999, respectively. A portion of each of these 5% stock dividends 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.

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 service territories, principally in Texas, Arizona and New
Mexico, and present 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 service territories
certain MGP sites are currently the subject of governmental actions. See Other
Matters -- Cautionary Statement Regarding Forward-Looking Information and
Commitments and Contingencies in the Notes to the Consolidated Financial
Statements.

On February 1, 1999, Southern Union submitted a proposal to the Board of
Directors of Southwest Gas Corporation (Southwest) to acquire all of Southwest's
outstanding common stock for $32.00 per share. Southwest at that time had a
pending merger agreement with ONEOK, Inc. (ONEOK) at $28.50 per share, executed
on December 14, 1998. On February 22, 1999, Southern Union and Southwest both
publicly announced Southern Union's proposal, after the Southwest Board of
Directors determined that Southern Union's proposal was a Superior Proposal (as
defined in the Southwest merger agreement with ONEOK). At that time Southern
Union entered into a Confidentiality and Standstill Agreement with Southwest at
Southwest's insistence. On April 25, 1999, Southwest's Board of Directors
rejected Southern Union's $32.00 per share offer and accepted an amended offer
of $30.00 per share from ONEOK. On April 27, 1999, Southern Union increased its
offer to $33.50 per share and agreed to pay interest which, together with
dividends, would provide Southwest shareholders with a 6% annual rate of return
on its $33.50 offer, commencing February 15, 2000, until closing. Southwest's
Board of Directors rejected Southern Union's revised proposal. On January 21,
2000, ONEOK announced that it was withdrawing from the Southwest merger
agreement.

There were several actions commenced by parties involved in efforts to acquire
Southwest. All of these actions eventually were transferred to the District of
Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of
summary judgments granted, there are no claims remaining against Southern Union.
On August 6, 2002, Southwest and Southern Union settled their claims against
each other in consideration of a payment to be made to Southern Union by
Southwest Gas of $17,500,000. On August 9, 2002, ONEOK and Southwest settled all
claims asserted against each other in consideration of a $3,000,000 payment to
be made to Southwest by ONEOK.

The remaining issues to be resolved at trial involve claims by the Company
against ONEOK and certain individuals. Southern Union's damage claims have been
limited to its out-of-pocket costs and punitive damages. Trial is scheduled to
commence October 15, 2002.

In August 1998, the City of Edinburg obtained a jury verdict totaling
approximately $13,000,000 jointly and severally against PG&E Gas
Transmission-Texas Corporation (formerly Valero Energy Corporation (Valero)),
and a number of its subsidiaries, as well as former Valero subsidiary Rio Grande
Valley Gas Company (RGV) and RGV's successor company, Southern Union Company for
the alleged underpayment of franchise fees. (Southern Union purchased RGV from
Valero in 1993.) The trial court reduced the jury award to approximately
$8,500,000. Subsequently, the Texas (13th District) Court of Appeals further
reduced the award to $4,085,000. The Court of Appeals also remanded a portion of
the case to the trial court with instructions to retry certain issues. The
Company continues to pursue reversal on appeal. In August 2002, the Supreme
Court of Texas granted the Company's petition for review. Oral arguments have
been scheduled for November 20, 2002. Effective January 1, 2003, all potential
remaining liability for this case was assigned to ONEOK as part of the sale of
the Company's Texas Operations to ONEOK.

                                       12

<PAGE>
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. As of September 20, 2002, the Commission had not yet adopted a
procedural schedule or set the matter for hearing.

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. As
of September 20, 2002, the Commission had not yet adopted a procedural schedule
or set the matter for hearing.

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
Commitments and Contingencies in the Notes to Consolidated Financial Statements.

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 gas service 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. Gas service rates, which consist of a
monthly fixed charge and a gas usage charge, are established by regulatory
authorities and are intended to permit utilities the opportunity to recover
operating, administrative and financing costs and to have the opportunity to
earn a reasonable return on equity. The monthly fixed charge provides a base
revenue stream while the usage charge increases the Company's revenues and
earnings in colder weather when natural gas usage increases.

On May 24, 2002, the Rhode Island Public Utilities Commission (RIPUC) approved a
settlement agreement between the New England Gas Company and the RIPUC. 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.

On July 5, 2001, the MPSC issued an order approving a unanimous settlement of
Missouri Gas Energy's rate request. The settlement provides for an annual
$9,892,000 base rate increase, as well as $1,081,000 in added revenue from new
and revised service charges. The majority of the rate increase will be recovered
through increased monthly fixed charges to gas sales service customers. New
rates became effective August 6, 2001, two months before the statutory deadline
for resolving the case. The approved settlement resulted in the dismissal of all
pending judicial reviews of prior rate cases. The settlement also provides for
the development of a two-year experimental low-income program that will help
certain customers in the Joplin area pay their natural gas bills.

                                       13
<PAGE>
Pursuant to the RIPUC's Written Order issued April 30, 2001, Providence Gas'
Price Stabilization Plan was extended through June 2002. The related settlement
agreement provided for additional gas distribution margin of $12,030,000 over
the 21-month period, October 2000 through June 2002, or approximately $6,240,000
for the twelve months ended September 2001. The settlement agreement also
contained a weather mitigation clause and a non-firm margin incentive mechanism.
The weather mitigation clause allowed Providence Gas to defer the margin impact
of weather that was greater than 2% colder-than-normal and to recover the margin
impact of weather that was greater than 3% warmer-than-normal by making the
corresponding adjustment to the deferred revenue account (DRA). The non-firm
margin incentive mechanism allowed Providence Gas to retain 25% of all non-firm
margins earned in excess of $1,200,000. Under the settlement agreement,
Providence Gas was able to earn up to 10.7%, but not less than 7.0%, using the
average return on equity for the two 12-month periods of October 2000 through
September 2001 and July 2001 through June 2002.

Effective October 1, 2000, the RIPUC approved a settlement agreement between
Providence Gas, the RIPUC, the Energy Council of Rhode Island, and The George
Wiley Center. The settlement agreement recognized the need for an increase in
distribution system revenues of $4,500,000, recovered through an adjustment to
the throughput portion of the gas charge, and provided for a 21-month base rate
freeze.

In December 2000, the Pennsylvania Public Utility Commission (PPUC) approved a
settlement agreement that provided for a rate increase designed to produce
$10,800,000 of additional annual revenue. The new rates became effective on
January 1, 2001.

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. New
England Gas Company has a weather normalization clause in the tariff covering
its Rhode Island operations. These clauses allow for the adjustments that help
stabilize customers' monthly bills and the Company's earnings from the varying
effects of weather.

Critical Accounting Policies A critical accounting policy is one that is both
important to portrayal of the Company's financial condition and results, and
requires management's most difficult, subjective or complex judgments, often as
a result of the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be perceived with certainty. The Company bases its estimates on
historical experience and on various other assumptions that are believed to be
reasonable under the circumstances, the results of which form the basis for
making judgments. These estimates may change as new events occur, as more
experience is acquired, as additional information is obtained and as the
Company's operating environment changes. The Company believes the following are
the most significant estimates used in the preparation of its consolidated
financials statements.

Accounting for Rate Regulation -- The FASB Standard, Accounting for the Effects
of Certain Types of Regulation, provides that rate-regulated entities account
for and report assets and liabilities consistent with the recovery of those
costs in rates if the rates established are designed to recover the costs of
providing the regulated service. The Company's gas utility operations adhere to
the accounting and reporting requirements of this Statement. Certain expenses
and revenues dependent on utility regulation or rate determination that would
customarily be reflected in income are deferred on the balance sheet and
recognized in income as the applicable amounts are included in service rates and
recovered from or refunded to customers. The aggregate amount of regulatory
assets and liabilities reflected in the consolidated balance sheets are $91.1
million and $6.4 million at June 30, 2002, and $89.3 million and $3.6 million at
June 30, 2001, respectively.

Impairment of Long-Lived Assets and Assets Held for Sale -- Long-lived assets,
which principally include property, plant and equipment, goodwill and equity
investments 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 periodically reviews the carrying values of these assets for impairment
or whenever events or changes in circumstances indicate that the carrying
amounts may not be recoverable. An impairment loss is recorded in the period in
which it is determined that the carrying amount is not recoverable. This
requires the Company to make long-term forecasts of future revenues and costs
related to the assets subject to review. 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.

                                       14
<PAGE>
During June 2002, the Company evaluated goodwill for impairment. The
determination of whether an impairment has occurred is based on an estimate of
discounted 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, 2002, 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.

Accounting for Investments in Equity Securities -- The Company holds securities
of Capstone Turbine Corporation (Capstone), which are classified as "available
for sale" under the FASB Standard, Accounting for Certain Investments in Debt
and Equity Securities. Accordingly, these securities are stated at fair value,
based on quoted market price, with unrealized gains and losses recorded in a
separate component of common stockholders' equity. All other securities owned by
the Company are accounted for under the cost method. The Company's other
investments in securities consist of common and preferred stock in non-public
companies whose value is not readily determinable. The Company reviews its
portfolio of other 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 the Company determines that the decline in value of an
investment security is other than temporary, the Company will record a charge on
its consolidated statement of operations to reduce the carrying value of the
security to its estimated fair value.

In June 2002, Southern Union determined that the decline in value of its
investment in PointServe was other than temporary. Accordingly, the Company
recorded a non-cash charge of $10,380,000, to reduce the carrying value of this
investment to its estimated fair value. The Company recognized this valuation
adjustment 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 $4,206,000 at June 30, 2002 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.

Accounting Pronouncements In June 2001, the FASB issued Accounting for Asset
Retirement Obligations. The Statement requires the fair value of a liability for
an asset retirement legal obligation to be recognized in the period in which it
is incurred and when the amount of the liability can be reasonably estimated.
When the liability is initially recorded, associated costs are capitalized by
increasing the carrying amount of the related long-lived 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 asset. The Statement is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Statement requires entities to record a cumulative
effect of change in accounting principle in the income statement in the period
of adoption. The Company intends to adopt this Statement during the quarter
ended September 30, 2002. Based on analysis completed to date, the Company does
not expect the Statement will have a material effect on its financial position,
results of operations or cash flows. The Company anticipates completing its
analysis by the end of the first quarter of fiscal year 2003. 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.

                                       15

<PAGE>
In August 2001, the FASB issued Accounting for the Impairment or Disposal of
Long-lived Assets. The Statement provides new guidance on the recognition of
impairment losses on long-lived assets to be held and used or to be disposed of
and also broadens the definition of what constitutes a discontinued operation
and how the results of a discontinued operation are to be measured and
presented. The Statement replaces the FASB Statement, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of and
the Accounting Principles Board Opinion, Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business. Under
the Statement, assets held for sale that are a component of an entity will be
included in discontinued operations if the operations and cash flows will be or
have been eliminated from the ongoing operations of the entity and the entity
will not have any significant continuing involvement in the operations
prospectively. The Statement is effective for fiscal years beginning after
December 15, 2001, and interim periods within those fiscal years, with early
adoption encouraged. The Statement is not expected to materially change the
methods the Company uses to measure impairment losses on long-lived assets, but
will result in additional future dispositions being reported as discontinued
operations than was previously permitted. The Company intends to adopt the
Statement during the quarter ended September 30, 2002.

In June 2002, the FASB issued Accounting for Costs Associated with Exit or
Disposal Activities. The Statement addresses financial accounting and reporting
for costs associated with exit or disposal activities and nullifies the Emerging
Issues Task Force issue, Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring). The Statement requires that a liability for a cost
associated with an exit or disposal activity be recognized and measured
initially at fair value only when the liability is incurred. The Statement is
effective for exit or disposal activities that are initiated after December 31,
2002, with early application encouraged. The Statement is not expected to
materially change the methods the Company uses to measure exit or disposal
costs, but may result in liabilities for such costs relating to future
dispositions being reported in periods subsequent to the Company's commitment to
an exit plan.

See the Notes to Consolidated Financial Statements for the Company's adoption of
Goodwill and Other Intangible Assets on July 1, 2001, and 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 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. 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 outcomes and results may differ materially from what is
expressed or forecasted in such forward-looking statements. The Company
undertakes no obligation to update publicly 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 or contribute to actual results differing materially
from such forward-looking statements include the following: cost of gas; gas
sales volumes; 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; the outcome of pending and future litigation; governmental regulations
and proceedings affecting or involving the Company; unanticipated environmental
liabilities; changes in business strategy; 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; the impairment or sale of investment securities; ability to access
capital markets on reasonable terms; and 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.

                                       16
<PAGE>

SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>


                                                                                   As of and for the year ended June 30,
                                                                  -----------------------------------------------------------------
                                                                     2002(a)     2001(b)       2000(c)        1999         1998(d)
                                                                  ---------   ----------    ----------     ----------     ---------
                                                                             (dollars in thousands, except per share amounts)
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Total operating revenues ........................................ $ 980,614   $1,461,811   $   566,833    $   378,292    $ 403,297
Net earnings (loss):
     Continuing operations (e) ..................................     1,520       40,159       (10,251)        (8,036)      (9,747)
     Discontinued operations (g) ................................    18,104       16,524        20,096         18,481       21,976
     Available for common stock .................................    19,624       57,285         9,845         10,445       12,229
Net  earnings (loss) per common and common share equivalents (f):
     Continuing operations ......................................       .03          .70          (.21)          (.21)        (.27)
     Discontinued operations ....................................       .32          .29           .41            .49          .60
     Available for common stock .................................       .35          .99           .20            .28          .33
Total assets .................................................... 2,680,064    2,907,299     2,021,460      1,087,348    1,047,764
Common stockholders' equity .....................................   685,346      721,857       735,455        301,058      296,834
Short-term debt and capital lease
     obligation .................................................   108,203        5,913         2,193          2,066        1,777
Long-term debt and capital lease
     obligation, excluding current portion ...................... 1,082,210    1,329,631       733,774        390,931      406,407
Company-obligated mandatorily
     redeemable preferred securities of
      subsidiary trust ..........................................   100,000      100,000       100,000        100,000      100,000

Average customers served ........................................   942,849      970,927       605,000        480,939      474,189


</TABLE>

(a)  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 in continuing operations an after-tax restructuring
     charge of $8,990,000. See Goodwill and Employee Benefits in the Notes to
     Consolidated Financial Statements.
(b)  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 results of operations
     since their respective acquisition dates. For these reasons, the
     consolidated results of operations of the Company for the periods
     subsequent to the acquisitions are not comparable to the same periods in
     prior years.
(c)  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
     results of operations since November 4, 1999. For these reasons, the
     consolidated results of operations of the Company for the periods
     subsequent to the acquisition are not comparable to the same periods in
     prior years.
(d)  On December 31, 1997, Southern Union acquired Atlantic Utilities for
     755,650 pre-split and pre-stock dividend shares of common stock valued at
     $18,041,000 and cash of $4,436,000. Atlantic Utilities was sold in December
     2001.
(e)  As of June 30, 1998, Missouri Gas Energy wrote off $8,163,000 pre-tax in
     previously recorded regulatory assets as a result of announced rate orders
     and court rulings.
(f)  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 (i) the 5% stock
     dividends distributed on July 15, 2002, August 30, 2001, June 30, 2000,
     August 6, 1999 and December 9, 1998, and (ii) the 50% stock dividend
     distributed on July 13, 1998.
(g)  Effective January 1, 2003, the Company sold its Southern Union Gas Company
     natural gas operating division and related assets, which have been
     accounted for as discontinued operations for all 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.  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.

                                       17
<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF OPERATIONS

<TABLE>
<CAPTION>
                                                                               Year Ended June 30,
                                                                  ------------------------------------------
                                                                      2002           2001            2000
                                                                  ------------    -----------    -----------
                                                                    (thousands of dollars, except shares and
                                                                                  per share amounts)
<S>                                                               <C>             <C>            <C>
Operating revenues ............................................   $    980,614    $ 1,461,811    $   566,833
Cost of gas and other energy ..................................       (573,077)    (1,031,696)      (345,918)
Revenue-related taxes .........................................        (33,409)       (49,869)       (24,597)
                                                                   ------------   ------------   -----------

     Operating margin .........................................        374,128        380,246        196,318

Operating expenses:
     Operating, maintenance and general .......................        171,147        186,468         89,740
     Business restructuring charges ...........................         29,159           --             --
     Depreciation and amortization ............................         58,989         69,161         37,918
     Taxes, other than on income and revenues .................         23,708         23,352         11,989
                                                                  ------------    -----------    -----------
         Total operating expenses .............................        283,003        278,981        139,647
                                                                  ------------    -----------    -----------
         Net operating revenues ...............................         91,125        101,265         56,671
                                                                  ------------    -----------    -----------


Other income (expenses):
     Interest .................................................        (90,992)      (102,928)       (50,953)
     Dividends on preferred securities of subsidiary trust ....         (9,480)        (9,480)        (9,480)
     Other, net ...............................................         14,278         81,401         (8,601)
                                                                  ------------    -----------    -----------

         Total other expenses, net ............................        (86,194)       (31,007)       (69,034)
                                                                  ------------    -----------    -----------


Earnings (loss) from continuing operations before income taxes           4,931         70,258        (12,363)

Federal and state income taxes (benefit) ......................          3,411         30,099         (2,112)
                                                                  ------------    -----------    -----------

Net earnings (loss) from continuing operations ................          1,520         40,159        (10,251)
                                                                  ------------    -----------    -----------

Discontinued operations:
     Earnings from discontinued operations before income taxes          29,801         26,425         31,797
     Federal and state income taxes ...........................         11,697          9,901         11,701
                                                                  ------------    -----------    -----------
Net earnings from discontinued operations .....................         18,104         16,524         20,096
                                                                  ------------    -----------    -----------

Net earnings before cumulative effect of change in accounting
     principle ................................................         19,624         56,683          9,845

Cumulative effect of change in accounting principle, net of tax           --              602            --
                                                                  ------------    -----------     ----------

Net earnings available for common stock .......................   $     19,624    $    57,285     $    9,845
                                                                  ============    ===========     ==========

Net earnings (loss) from continuing operations per share:
     Basic ....................................................   $        .03    $       .73     $     (.21)
                                                                  ============    ===========     ==========
     Diluted ..................................................   $        .03    $       .70     $     (.21)
                                                                  ============    ===========     ==========

Net earnings available for common stock per share:
     Basic ....................................................   $        .36    $      1.05     $      .21
                                                                  ============    ===========     ==========

     Diluted ..................................................   $        .35    $       .99     $      .20
                                                                  ============    ===========     ==========

Weighted average shares outstanding:
     Basic ....................................................     53,886,998      54,680,807     47,840,785
                                                                  ============    ============    ===========
     Diluted ..................................................     56,770,235      57,716,973     50,053,017
                                                                  ============    ============    ===========
</TABLE>
                                                     See accompanying notes

                                                             F-1
<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEET



                                     ASSETS
<TABLE>
<CAPTION>


                                                                      June 30,
                                                           ---------------------------
                                                               2002           2001
                                                           -----------    ------------
                                                              (thousands of dollars)

<S>     <C>    <C>    <C>    <C>    <C>    <C>
Property, plant and equipment:
     Plant in service ..................................   $ 1,767,349    $ 1,728,461
     Construction work in progress .....................         6,535         18,572
                                                           -----------    -----------
                                                             1,773,884      1,747,033
     Less accumulated depreciation and amortization ....      (604,114)      (569,674)
                                                           -----------    -----------

         Net property, plant and equipment .............     1,169,770      1,177,359



Current assets:
     Cash and cash equivalents .........................          --            1,219
     Accounts receivable, billed and unbilled, net .....        95,036        180,403
     Inventories, principally at average cost ..........       101,076        104,297
     Deferred gas purchase costs .......................         3,597         57,033
     Investment securities available for sale ..........         1,163         29,447
     Prepayments and other .............................        13,527         18,562
     Assets held for sale ..............................       395,446        411,124
                                                           -----------    -----------

         Total current assets ..........................       609,845        802,085

Goodwill, net of accumulated amortization of $27,510 and
          $28,408, respectively ........................       642,921        652,048

Deferred charges .......................................       206,130        222,108

Investment securities, at cost .........................         9,786         19,081

Real estate ............................................          --            2,506

Other ..................................................        41,612         32,112








         Total assets ..................................   $ 2,680,064    $ 2,907,299
                                                           ===========    ===========

</TABLE>



                             See accompanying notes.

                                      F-2
<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                     CONSOLIDATED BALANCE SHEET (Continued)



                      STOCKHOLDERS' EQUITY AND LIABILITIES

<TABLE>
<CAPTION>

                                                                                        June 30,
                                                                              --------------------------
                                                                                   2002           2001
                                                                              -----------    -----------
                                                                                 (thousands of dollars)
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Common stockholders' equity:
     Common stock, $1 par value; authorized 200,000,000 shares; issued
         58,055,436 shares at June 30, 2002 ...............................   $    58,055    $    54,553
     Premium on capital stock .............................................       707,912        676,324
     Less treasury stock:  3,125,993 and 1,046,617 shares, respectively,
         at cost ..........................................................       (57,673)       (15,869)
     Less common stock held in Trust: 1,138,821 and 1,184,857 shares,
         respectively .....................................................       (17,821)       (19,196)
     Deferred compensation plans ..........................................         9,373          7,499
     Accumulated other comprehensive income (loss) ........................       (14,500)        13,443
     Retained earnings ....................................................          --            5,103
                                                                              -----------    -----------

                                                                                  685,346        721,857

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

Long-term debt and capital lease obligation ...............................     1,082,210      1,329,631
                                                                              -----------    -----------

         Total capitalization .............................................     1,867,556      2,151,488

Current liabilities:
     Long-term debt and capital lease obligation due within one year ......       108,203          5,913
     Notes payable ........................................................       131,800        190,600
     Accounts payable .....................................................        71,343         84,933
     Federal, state and local taxes .......................................         9,212         32,342
     Accrued interest .....................................................        17,019         15,737
     Accrued dividends on preferred securities of subsidiary trust ........         2,370          2,370
     Customer deposits ....................................................         7,572          7,889
     Other ................................................................        38,686         60,316
     Liabilities related to assets held for sale ..........................        67,718         57,994
                                                                              -----------    -----------

         Total current liabilities ........................................       453,923        458,094

Deferred credits and other ................................................       141,933         94,426

Accumulated deferred income taxes .........................................       216,652        203,291



         Total stockholders' equity and liabilities .......................   $ 2,680,064    $ 2,907,299
                                                                              ===========    ===========

</TABLE>



                                          See accompanying notes.

                                                  F-3
<PAGE>


                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

                                                                             Year Ended June 30,
                                                                    -----------------------------------
                                                                       2002         2001        2000
                                                                    ---------    ---------    ---------
                                                                          (thousands of dollars)
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Cash flows from (used in) operating activities:
     Net earnings ...............................................   $  19,624    $  57,285    $   9,845
     Adjustments to reconcile net earnings to net cash flows from
        (used in) operating activities:
         Depreciation and amortization ..........................      58,989       69,161       37,918
         Deferred income taxes ..................................      28,397       27,778          435
         Provision for bad debts ................................      12,260       27,260        3,389
         Provision for investment impairment ....................      10,380         --           --
         Financial derivative trading gains .....................      (6,204)        --           --
         Amortization of debt expense ...........................       2,936        3,118        1,242
         Gain on sale of investment securities ..................      (1,004)     (74,582)        --
         Gain on sale of subsidiaries and other assets ..........      (6,414)     (14,239)        --
         Loss on sale of subsidiaries ...........................       1,500         --           --
         Gain on settlement of interest rate swaps ..............     (17,166)        --           --
         Cumulative effect of change in accounting principle ....        --           (602)        --
         Business restructuring charges .........................      24,440         --           --
         Net cash provided by assets held for sale ..............      48,618          320       19,211
         Other ..................................................       1,359       (1,034)         265
         Changes in operating assets and liabilities, net of
            acquisitions:
              Accounts receivable, billed and unbilled ..........      71,932     (111,732)       4,243
              Accounts payable ..................................     (11,965)     (13,134)      14,705
              Customer deposits .................................         (53)      (2,136)      (4,088)
              Deferred gas purchase costs .......................      53,436      (59,054)     (15,099)
              Inventories .......................................       1,044      (32,125)         447
              Deferred charges and credits ......................      16,804       (9,316)      (2,299)
              Prepaids and other current assets .................      (3,735)      (7,802)       1,433
              Taxes and other current liabilities ...............     (31,562)      (6,265)      (4,782)
                                                                    ---------    ---------    ---------
         Net cash flows from (used in) operating activities .....     273,616     (147,099)      66,865
                                                                    ---------    ---------    ---------
Cash flows (used in) from investing activities:
     Additions to property, plant and equipment .................     (70,698)    (100,752)     (70,971)
     Acquisition of operations, net of cash received ............        --       (414,497)     (38,366)
     Notes receivable ...........................................      (2,750)        --           --
     Purchase of investment securities ..........................        (938)     (12,495)     (21,001)
     Customer advances ..........................................        (403)         717        1,277
     Proceeds from sale of investment securities ................       1,213       85,761         --
     Proceeds from sale of subsidiaries and other assets ........      40,935       23,938       12,150
     Proceeds from sale of interest rate swaps ..................      17,166         --           --
     Net cash (used in) provided by assets held for sale ........     (23,215)     (22,012)     (28,890)
     Other ......................................................        (536)       4,587       (5,065)
                                                                    ---------    ---------    ---------
         Net cash flows used in investing activities ............     (39,226)    (434,753)    (150,866)
                                                                    ---------    ---------    ---------
Cash flows (used in) from financing activities:
     Issuance of long-term debt .................................        --        535,000      300,000
     Issuance cost of debt ......................................        (921)      (3,474)      (7,292)
     Purchase of treasury stock .................................     (41,632)        --        (14,425)
     Repayment of debt and capital lease obligation .............    (145,131)    (167,270)    (138,791)
     Net (payments) borrowings under revolving credit facilities      (58,800)     190,597      (21,000)
     Proceeds from exercise of stock options ....................       8,346          707          680
     Cash overdrafts ............................................         123         --         (6,655)
     Other ......................................................       2,406         (318)        (687)
                                                                    ---------    ---------    ---------
         Net cash flows (used in) from financing activities .....    (235,609)     555,242      111,830
                                                                    ---------    ---------    ---------
Change in cash and cash equivalents .............................      (1,219)     (26,610)      27,829
Cash and cash equivalents at beginning of year ..................       1,219       27,829         --
                                                                    ---------    ---------    ---------
Cash and cash equivalents at end of year ........................   $    --      $   1,219    $  27,829
                                                                    =========    =========    =========

Cash paid for interest, net of amounts capitalized, in 2002, 2001 and 2000 was
$99,643,000, $107,295,000 and $57,223,000, respectively. Cash refunded for
income taxes in 2002 was $4,214,000, while cash paid for income taxes in 2001
and 2000 was $17,753,000 and $2,565,000, respectively.

</TABLE>



                                             See accompanying notes.

                                                     F-4
<PAGE>

<TABLE>
<CAPTION>

                                                      SOUTHERN UNION COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

                                                                                    Common    Accumulated
                                           Common       Premium      Treasury       Stock        Other
                                          Stock, $1    on Capital    Stock, at     Held  in   Comprehen-     Retained
                                          Par Value      Stock         Cost         Trust    sive Income     Earnings     Total
                                          ---------  ------------    ---------    ---------  -----------     ---------  --------
                                                                      (thousands of dollars)

<S>          <C>                           <C>        <C>             <C>         <C>         <C>            <C>        <C>
Balance July 1, 1999 ..................    $ 31,240   $  276,610      $  (794)    $ (4,927)   $    (436)     $  --      $301,693

   Comprehensive income:
     Net earnings .....................        --           --           --           --           --          9,845       9,845
     Unrealized gain in investment
       securities, net of tax .........        --           --           --           --        115,175          --       115,175
     Minimum pension liability
       adjustment, net of tax .........        --           --           --           --            436         --           436
                                                                                                                       ---------
     Comprehensive income .............                                                                                  125,456
                                                                                                                       ---------
   Purchase of common stock held
     in trust .........................        --           --           --         (9,864)        --           --        (9,864)
   5% stock dividend ..................       2,359        7,452         --           --           --         (9,845)        (34)
   Purchase of treasury stock .........        --           --        (14,425)        --           --           --       (14,425)
   Issuance of stock for acquisition ..      16,714      315,235         --           --           --           --       331,949
   Exercise of stock options ..........         208          538         (335)         269         --           --           680
                                          ---------    ---------    ---------    ---------    ---------    ---------   ---------
Balance June 30, 2000 .................      50,521      599,835      (15,554)     (14,522)     115,175         --       735,455

   Comprehensive income:
     Net earnings .....................        --           --           --           --           --         57,285      57,285
     Unrealized loss in investment
       securities, net of tax benefit .        --           --           --           --        (96,323)        --       (96,323)
     Minimum pension liability
       adjustment, net of tax .........        --           --           --           --         (4,324)        --        (4,324)
     Cumulative effect of change in
       accounting principle, net of tax        --           --           --           --            826         --           826
     Unrealized loss on hedging
       activities, net of tax benefit .        --           --           --           --         (1,911)        --        (1,911)
                                                                                                                        --------
     Comprehensive income (loss) ......                                                                                  (44,447)
                                                                                                                        --------
   Payment on note receivable .........        --            290         --           --           --           --           290
   Purchase of common stock held
     in trust .........................        --           --           --         (4,009)        --           --        (4,009)
   5% stock dividend ..................       2,556       49,626         --           --           --        (52,182)       --
   Benefit plan modification ..........        --           --           --          6,560         --           --         6,560
   Issuance of stock for acquisition ..       1,371       25,930         --           --           --           --        27,301
   Exercise of stock options ..........         105          643         (315)         274         --           --           707
                                          ---------    ---------    ---------    ---------    ---------    ---------     -------
Balance June 30, 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 .........        --           --           --           --        (18,249)        --       (18,249)
     Minimum pension liability
       adjustment, net of tax .........        --           --           --           --        (10,498)        --       (10,498)
     Unrealized gain on hedging
       activities, net of tax benefit .        --           --           --           --            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
                                          =========    =========    =========    =========    ==========   =========    ========






                                                                     See accompanying notes

                                                                             F-5
</TABLE>

<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
wholly-owned subsidiaries, the Company) is currently a public utility primarily
engaged in the distribution and sale of natural gas to residential, commercial
and industrial customers located primarily in Missouri, Pennsylvania, Rhode
Island and Massachusetts. See Note II -- Acquisitions and Divestitures, and Note
XIX -- Discontinued Operations and Assets Held for Sale. Certain subsidiaries
own or hold interests in real estate and other assets, which are primarily used
in the Company's utility business. Substantial operations of the Company are
subject to regulation. Accounting policies conform to the Financial Accounting
Standards Board (FASB) standard, Accounting for the Effects of Certain Types of
Regulation in the case of regulated operations.

Basis of Presentation Effective January 1, 2003, the Company sold its Southern
Union Gas Company natural gas operating division and related assets (the Texas
Operations) to ONEOK, Inc. In accordance with the FASB standard, Accounting for
the Impairment or Disposal of Long-Lived Assets, the assets to be sold and
liabilities to be assumed from the Texas Operations have been segregated and
reported as "held for sale" in the consolidated balance sheet. In addition, the
related results of operation have been segregated and reported as "discontinued
operations" in the consolidated statement of operations and consolidated
statement of cash flows for all periods presented in this document. See Note XIX
--Discontinued Operations and Assets Held for Sale.

Principles of Consolidation The consolidated financial statements include the
accounts of Southern Union and its wholly-owned subsidiaries. Investments in
which the Company has significant influence over the operations of the investee
and the Company owns a 20% to 50% interest are accounted for using the equity
method. 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.

Gas Utility Revenues and Gas Purchase Costs Gas utility customers are billed on
a monthly-cycle basis. The related cost of gas and revenue taxes are matched
with cycle-billed revenues through utilization of purchased gas adjustment
provisions in tariffs approved by the regulatory agencies having jurisdiction.
Revenues from gas delivered but not yet billed are accrued, along with the
related gas purchase costs and revenue-related taxes. Unbilled revenues, net of
related gas purchase costs and revenue-related taxes, were $7,450,000 and
$8,076,000 at June 30, 2002 and 2001, respectively. The distribution and sale of
natural gas in Missouri, Pennsylvania, Rhode Island and Massachusetts
contributed in excess of 95% of the Company's total revenue, net earnings from
continuing operations and identifiable assets in 2002, 2001 and 2000. Three
suppliers provided 61%, 71% and 47% of the Company's gas purchases in 2002, 2001
and 2000, respectively.

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 July 15, 2002 unless otherwise noted.

Accumulated Other Comprehensive Income The Company reports comprehensive income
and its components in accordance with the FASB Standard, Reporting Comprehensive
Income. The main components of comprehensive income that relate to the Company
are net earnings, unrealized holding gains and losses on investment securities,
minimum pension liability adjustments, unrealized loss on hedging activities and
cumulative effect of change in accounting principle, all of which are presented
in the consolidated statement of stockholders' equity.

Unrealized holding gains on investment securities were $603,000, $18,852,000 and
$115,175,000 in 2002, 2001 and 2000, respectively. The reclassification
adjustment for gains included in net income, net of tax, for reporting other
comprehensive income was $567,000, $43,726,000 and nil in 2002, 2001 and 2000,
respectively. The unrealized holding gains or losses on investment securities
and the reclassification adjustment for gains are combined and reflected on the
consolidated statement of stockholders' equity.

Credit Risk 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 certain

                                      F-6
<PAGE>

                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

customers. The Company has recorded an allowance for doubtful accounts totaling
$15,324,000, $28,347,000, $6,675,000 and $5,847,000 at June 30, 2002, 2001, 2000
and 1999, respectively. The allowance for doubtful accounts is adjusted for
changes in estimated uncollectible accounts and reduced for the write-off of
trade receivables.

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

Inventories Inventories consist of natural gas in underground storage and
materials and supplies. Natural gas in underground storage of $92,448,000 and
$101,549,000 at June 30, 2002 and 2001, respectively, consists of 23,166,000 and
20,535,000 British thermal units, respectively.

Segment Reporting The 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 gas distribution industry
in the United States and has no other reportable industry segments.

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, which was adopted on July 1,
2001. Under this Statement, the Company recognizes derivatives on the
consolidated balance sheet at their fair value. On the date that the Company
enters into a derivative contract, it designates the derivative as: (i) a hedge
of the fair value of a recognized asset or liability or of an unrecognized firm
commitment (a "fair value" hedge); (ii) a hedge of a forecasted transaction or
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 (including gains or losses on firm
commitments), 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.

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 ("Highly effective" means that cumulative changes in the value
of the hedging instrument are between 80% to 125% of the inverse cumulative
changes in the fair value or cash flows of the hedged item). 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 consolidated 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 are employed to hedge the effect of changes
in interest rates related to certain debt instruments and commodity swaps and
options to manage price risk associated with certain energy contracts.

In accordance with adoption of this Statement on July 1, 2000, the Company
recorded a net-of-tax cumulative-effect gain of $602,000 in earnings to
recognize the fair value of the gas derivative contracts at PG Energy Services,
Inc., a wholly-owned subsidiary, that are not designated as hedges. The Company
also recorded

                                      F-7
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$826,000 in accumulated other comprehensive income which recognizes the fair
value of two interest rate swap derivatives that were designated as cash flow
hedges.

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, which was adopted at the beginning of
fiscal year 2002. 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.

New Pronouncements In June 2001, the FASB issued Accounting for Asset Retirement
Obligations. The Statement requires the fair value of a liability for an asset
retirement legal obligation to be recognized in the period in which it is
incurred and when the amount of the liability can be reasonably estimated. When
the liability is initially recorded, associated costs are capitalized by
increasing the carrying amount of the related long-lived 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 asset. The Statement is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Statement requires entities to record a cumulative
effect of change in accounting principle in the income statement in the period
of adoption. The Company intends to adopt this Statement during the quarter
ending September 30, 2002. Based on analysis completed to date, the Company does
not expect the Statement will have a material effect on its financial position,
results of operations or cash flows. The Company anticipates completing its
analysis by the end of the first quarter of fiscal year 2003. 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.

In August 2001,  the FASB issued  Accounting for the Impairment or Disposal
of Long-lived  Assets. The Statement provides new guidance on the recognition of
impairment  losses on long-lived assets to be held and used or to be disposed of
and also broadens the definition of what  constitutes a  discontinued  operation
and  how  the  results  of a  discontinued  operation  are  to be  measured  and
presented.  The  Statement  replaces  the  FASB  Statement,  Accounting  for the
Impairment of Long-Lived  Assets and for Long-Lived Assets to be Disposed of and
the    Accounting    Principles    Board   Opinion,    Reporting    Results   of
Operations-Reporting  the Effects of Disposal of a Segment of a Business.  Under
the  Statement,  assets held for sale that are a component  of an entity will be
included in discontinued  operations if the operations and cash flows will be or
have been  eliminated  from the ongoing  operations of the entity and the entity
will  not  have  any  significant   continuing  involvement  in  the  operations
prospectively.  The Statement was  effective  for fiscal years  beginning  after
December 15, 2001,  and interim  periods  within those fiscal years,  with early
adoption  encouraged.  The  Statement is not expected to  materially  change the
methods the Company uses to measure  impairment losses on long-lived assets, but
will result in additional  future  dispositions  being reported as  discontinued
operations  than was  previously  permitted.  The  Company  intends to adopt the
Statement during the quarter ending September 30, 2002.

In June 2002, the FASB issued Accounting for Costs Associated with Exit or
Disposal Activities. The Statement addresses financial accounting and reporting
for costs associated with exit or disposal activities and nullifies the Emerging
Issues Task Force issue, Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring). The Statement requires that a liability for a cost
associated with an exit or disposal activity be recognized and measured
initially at fair value only when the liability is incurred. The Statement is
effective for exit or disposal activities that are initiated after December 31,
2002, with early application encouraged. The Statement is not expected to
materially change the methods the Company uses to measure exit or disposal
costs, but may result in liabilities for such costs relating to future
dispositions being reported in periods subsequent to the Company's commitment to
an exit plan.

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.

                                      F-8
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                        II Acquisitions and Divestitures

In September 2000, Southern Union acquired Providence Energy Corporation
(ProvEnergy), Fall River Gas Company (Fall River Gas), and Valley Resources
(Valley Resources). Collectively, these companies (hereafter referred to as the
Company's New England Operations) were acquired for approximately $422,000,000
in cash and 1,370,629 shares (before adjustment for any subsequent stock
dividends) of Southern Union common stock, as well as the assumption of
approximately $140,000,000 in long-term debt. The results of operations from
ProvEnergy and Fall River Gas have been included in the Company's consolidated
statement of operations since September 28, 2000, and the results of operations
from Valley Resources have been included in the Company's consolidated statement
of operations since September 20, 2000. Thus, the Company's consolidated results
of operations for the periods subsequent to these acquisitions are not
comparable to the same periods in prior years. These acquisitions were accounted
for using the purchase method with related goodwill of approximately
$355,000,000. Effective July 1, 2001, goodwill, which was previously amortized
on a straight-line basis over forty years, is now accounted for on an
impairment-only approach. See Note VII - Goodwill.

The New England Operations' primary business is the distribution of natural gas
through the New England Gas Company. Subsidiaries of the Company acquired with
the New England Gas Company and currently operating include ProvEnergy Power LLC
(ProvEnergy Power), Fall River Gas Appliance Company (Fall River Appliance),
Valley Appliance Merchandising Company (VAMCO) and Alternate Energy Corporation
(AEC). ProvEnergy Power provides outsourced energy management services and owns
50% of Capital Center Energy Company LLC, a joint venture formed between
ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air.
Fall River Appliance rents water heaters and conversion burners, primarily to
residential customers. VAMCO rents natural gas burning appliances and offers
appliance service contract programs to residential customers. In fiscal 2002,
VAMCO also provided construction management services for natural gas-related
projects to commercial and industrial customers. AEC is an energy consulting
firm.

Subsidiaries acquired with the New England Gas Company and subsequently sold
include Morris Merchants, Inc. (Morris Merchants), Valley Propane, Inc. (Valley
Propane) and ProvEnergy Oil Enterprises, Inc. (ProvEnergy Oil). In October 2001,
Morris Merchants, 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, which sold liquid
propane to residential, commercial and industrial customers, was sold for
$5,301,000. In August 2001, ProvEnergy Oil, 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.

In November 1999, Southern Union acquired Pennsylvania Enterprises, Inc.
(hereafter referred to as the Company's Pennsylvania Operations) for
approximately $500,000,000, including assumption of approximately $115,000,000
of long-term debt. The Company issued approximately 16,700,000 shares (before
adjustment for any subsequent stock dividends) of common stock and paid
approximately $38,000,000 in cash to complete the transaction. The results of
operations from the Pennsylvania Operations have been included in the Company's
consolidated statement of operations since November 4, 1999. Thus, the Company's
consolidated results of operations for the periods subsequent to the acquisition
are not comparable to the same periods in prior years. The acquisition was
accounted for using the purchase method with related goodwill of approximately
$261,000,000. Effective July 1, 2001, goodwill, which was previously amortized
on a straight-line basis over forty years, is now accounted for on an
impairment-only approach. See Note VII -- Goodwill.

The Pennsylvania Operations' primary business is the distribution of natural gas
through PG Energy. Subsidiaries of the Company acquired with PG Energy and
currently operating include PG Energy Services Inc., (Energy Services) and PEI
Power Corporation (Power Corp.). Energy Services offers the inspection,
maintenance and servicing of residential and small commercial gas-fired
equipment to residential and commercial users. Power Corp., an exempt wholesale
generator (within the meaning of the Public Utility Holding Company Act of
1935), sells electricity to the broad mid-Atlantic wholesale energy market
administered by PJM Interconnection, L.L.C.

Subsidiaries and assets acquired with PG Energy and subsequently sold include
Energy Services' propane operations and its commercial and industrial gas
marketing contracts, Keystone Pipeline Services, Inc. (Keystone)

                                      F-9

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and Theta Land Corporation. In April 2002, 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 June 2001,
the Company sold Keystone, which engaged primarily in the construction,
maintenance, and rehabilitation of natural gas distribution pipelines, for
$3,300,000, resulting in a pre-tax gain of $707,000. In January 2000, Theta Land
Corporation, which owned approximately 44,000 acres of land, was sold for
$12,150,000. No financial gain or loss was recognized on this transaction.

In December 2001, a subsidiary of the Company sold its 43-mile Carrizo Springs
Pipeline for $1,000,000, resulting in a pre-tax gain of $561,000. Also in
December 2001, the Company sold South Florida Natural Gas, a natural gas
division of Southern Union, and Atlantic Gas Corporation, a Florida propane
subsidiary of the Company (collectively, the Florida Operations), for
$10,000,000, resulting in a pre-tax loss of $1,500,000.

Pro Forma Financial Information

The following unaudited pro forma financial information for the year ended June
30, 2001 is presented as though the following events had occurred at the
beginning of the period presented: (i) acquisition of the New England
Operations; (ii) the issuance of the Term Note; and (iii) the refinancing of
certain short-term and long-term debt at the time of the acquisitions. The pro
forma financial information is not necessarily indicative of the results which
would have actually been obtained had the acquisition of the New England
Operations, the issuance of the Term Note, or the refinancings been completed as
of the assumed date for the period presented or which may be obtained in the
future.

                                                              Year Ended
                                                             June 30, 2001
                                                             -------------
Operating revenue .........................................   $1,505,471
Income from continuing operations before extraordinary item       19,226
Net earnings from continuing operations ...................       19,226
Net earnings per share from continuing operations:
     Basic ................................................          .35
     Diluted ..............................................          .33

                         III Other Income (Expense), Net

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 Turbine Corporation (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 Gas Corporation (Southwest), and a $1,500,000 loss on the sale of
the Florida Operations. See Note XVIII -- Commitments and Contingencies.

Other income of $81,401,000 in 2001 included realized gains on the sale of
Capstone of $74,582,000, a $13,532,000 gain on the sale of non-core real estate
and $6,838,000 of interest and dividend income. These items were partially
offset by $12,855,000 of legal costs associated with Southwest.

Other expense of $8,601,000 in 2000 included $10,363,000 of legal costs
associated with Southwest. This item was partially offset by net rental income
of Lavaca Realty Company of $1,757,000.

                                      F-10
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                            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 2002, 2001, and 2000:

<TABLE>
<CAPTION>
                                                                                Year Ended June 30,
                                                                     ------------------------------------------
                                                                         2002           2001           2000
                                                                     ------------   ------------   ------------

<S>                                                                  <C>            <C>            <C>
Net earnings (loss) from continuing operations ....................  $      1,520   $     40,159   $    (10,251)
Net earnings from discontinued operations .........................        18,104         16,524         20,096
Cumulative effect of change in accounting principle, net of tax              --              602           --
                                                                     ------------   ------------   ------------
Net earnings available for common stock ...........................  $     19,624   $     57,285   $      9,845
                                                                     ============   ============   ============
Weighted average shares outstanding -- basic ......................    53,886,998     54,680,807     47,840,785
                                                                     ============   ============   ============
Weighted average shares outstanding -- diluted ....................    56,770,235     57,716,973     50,053,017
                                                                     ============   ============   ============

Basic earnings per share:
    Net earnings (loss) from continuing operations ................  $       0.03   $       0.73   $      (0.21)
    Net earnings from discontinued operations .....................          0.33           0.31           0.42
    Cumulative effect of change in accounting principle, net of tax          --             0.01           --
                                                                      -----------   ------------   ------------
    Net earnings available for common stock .......................   $      0.36   $       1.05   $       0.21
                                                                      ===========   ============   ============
Diluted earnings per share:
    Net earnings (loss) from continuing operations ................   $      0.03   $       0.70   $      (0.21)
    Net earnings from discontinued operations .....................          0.32           0.28           0.41
    Cumulative effect of change in accounting principle, net of tax          --             0.01           --
                                                                      -----------   ------------   ------------
    Net earnings available for common stock .......................   $      0.35   $       0.99   $       0.20
                                                                      ===========   ============   ============
</TABLE>

During the three-year period ended June 30, 2002, no adjustments were required
in net earnings available for common stock for the earnings per share
calculations. Diluted earnings per share include average shares outstanding as
well as common stock equivalents from stock options and warrants. Common stock
equivalents were 1,660,711, 1,908,564 and 1,519,387 for the years ended June 30,
2002, 2001 and 2000, respectively. During 2002, the Company repurchased
2,115,916 shares of its common stock outstanding at prices ranging from $16.50
to $21.57 per share. Substantially all of these repurchases occurred in private
off-market large-block transactions.

                                                      F-11

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                        VI Property, Plant and Equipment

Plant Plant in service and construction work in progress are stated at original
cost net of contributions in aid of construction. 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 utility
properties and other property constituting operating units. Gain or loss from
minor dispositions of property is charged to accumulated depreciation and
amortization. The Company capitalizes the cost of significant
internally-developed computer software systems and amortizes the cost over the
expected useful life. See Note XIII -- Debt and Capital Lease.


                                                          June 30,
                                                ---------------------------
                                                      2002         2001
                                                ------------   ------------
Distribution plant ...........................  $  1,551,459   $  1,486,600
General plant ................................       161,054        128,849
Other ........................................        56,012        113,075
                                                ------------   ------------
     Total plant .............................     1,768,525      1,728,524
Less contributions in aid of construction ....        (1,176)           (63)
                                                ------------   ------------
     Plant in service ........................     1,767,349      1,728,461
Construction work in progress ................         6,535         18,572
                                                 ------------  ------------
                                                   1,773,884      1,747,033
Less accumulated depreciation and amortization      (604,114)      (569,674)
                                                 -----------    -----------

     Net property, plant and equipment .......   $ 1,169,770    $ 1,177,359
                                                 ===========    ===========

Acquisitions of rate-regulated entities are recorded at the historical book
carrying value of utility plant. On September 28, 2000, ProvEnergy and Fall
River Gas were acquired in which historical utility plant and equipment had a
cost of $357,822,000 and $64,384,000, respectively, and accumulated depreciation
and amortization of $138,857,000 and $24,401,000, respectively. On September 20,
2000, Valley Resources was acquired in which historical utility plant and
equipment had a cost and accumulated depreciation and amortization of
$105,888,000 and $47,010,000, respectively.

Depreciation and Amortization Depreciation of utility plant is provided 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
regulatory-approved periods.

Depreciation of property, plant and equipment in 2002, 2001 and 2000 was
$57,571,000, $54,170,000 and $31,952,000, respectively.

                                      F-12
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                  VII Goodwill

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 table reflects the Company's comparative net earnings from
continuing operations and net earnings, both before the change in accounting
principle and goodwill amortization under Goodwill and Other Intangible Assets:
<TABLE>
<CAPTION>

                                                                         Year Ended June 30,
                                                               ------------------------------------
                                                                   2002        2001         2000
                                                               ----------  -----------  -----------
<S>                                                            <C>         <C>          <C>
Reported net earnings (loss) from continuing operations .....  $    1,520  $    40,159  $   (10,251)
Goodwill amortization, net of taxes .........................        --         14,992        5,965
                                                               ----------  -----------  -----------
Adjusted net earnings (loss) from continuing operations .....  $    1,520  $    55,151  $    (4,286)
                                                               ==========  ===========  ===========

Basic earnings (loss) per share from continuing operations:
   Reported net earnings (loss) from continuing operations ..  $      .03  $       .73  $      (.21)
   Goodwill amortization ....................................       --             .28          .12
                                                               ----------  -----------  ------------
   Adjusted net earnings (loss) from continuing operations ..  $      .03  $      1.01   $     (.09)
                                                               ==========  ===========   ===========

Diluted earnings (loss) per share from continuing operations:
   Reported net earnings (loss) from continuing operations ..  $      .03  $       .70   $      (.21)
   Goodwill amortization ....................................        --            .26           .12
                                                               ----------  -----------   -----------
   Adjusted net earnings (loss) from continuing operations ..  $      .03  $       .96   $      (.09)
                                                               ==========  ===========   ===========


                                                                         Year Ended June 30,
                                                               -------------------------------------
                                                                   2002        2001          2000
                                                               ----------  -----------   -----------
Reported net earnings .......................................  $   19,624  $    56,683   $     9,845
Goodwill amortization, net of taxes .........................         --        17,463         8,382
                                                               ----------  -----------   -----------
Adjusted net earnings .......................................  $   19,624  $    74,146   $    18,227
                                                               ==========  ===========   ===========

Basic earnings per share:
   Reported net earnings ....................................  $      .36  $      1.05   $       .21
   Goodwill amortization ....................................        --            .32           .17
                                                               ----------  -----------   -----------

   Adjusted net earnings ....................................  $      .36  $      1.37   $       .38
                                                               ==========  ===========   ===========

Diluted earnings (per share:
   Reported net earnings ....................................  $      .35  $       .99   $       .20
   Goodwill amortization ....................................         --           .30           .16
                                                               ----------  -----------   -----------
   Adjusted net earnings ....................................  $      .35  $      1.29   $       .36
                                                               ==========  ===========   ===========


The following displays changes in the carrying amount of goodwill for the year ended June 30, 2002:

                                                                                             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
                                                                                           =========
                                                  F-13
<PAGE>

</TABLE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

                   VIII Deferred Charges and Deferred Credits

                                               June 30,
                                         -------------------
                                           2002       2001
                                         --------   --------
Deferred Charges
  Pensions ...........................   $ 52,481   $ 56,749
  Income taxes .......................     24,000     33,872
  Unamortized debt expense ...........     33,897     36,010
  Retirement costs other than pensions     33,032     36,078
  Service Line Replacement program ...     21,360     23,765
  Environmental ......................     16,646     16,566
  Other ..............................     24,714     19,068
                                         --------   --------
    Total Deferred Charges ...........   $206,130   $222,108
                                         ========   ========

The Company's deferred charges include regulatory assets in the aggregate amount
of $91,116,000 and $89,318,000, respectively, at June 30, 2002 and 2001. These
regulatory assets 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. The Company records
regulatory assets in accordance with the FASB Standard Accounting for the
Effects of Certain Types of Regulation.

                                                 June 30,
                                            -------------------
                                              2002       2001
                                            --------   --------
Deferred Credits
     Pensions ...........................   $ 45,645   $  9,394
     Retirement costs other than pensions     37,669     34,460
     Customer advances for construction .     11,119     10,905
     Environmental ......................      7,206      1,832
     Investment tax credit ..............      6,212      6,819
     Operating reserves .................      6,208      8,432
     Other ..............................     27,874     22,584
                                            --------   --------
       Total Deferred Credits ...........   $141,933   $ 94,426
                                            ========   ========

The Company's deferred credits include regulatory liabilities in the aggregate
amount of $6,389,000 and $3,569,000, respectively, at June 30, 2002 and 2001.
These regulatory liabilities primarily relate to retirement benefits other than
pensions and income taxes. The Company records regulatory liabilities in
accordance with the FASB Standard Accounting for the Effects of Certain Types of
Regulation.

                            IX Investment Securities

At June 30, 2002, the Company held securities of Capstone Turbine Corporation
(Capstone). This investment is classified as "available for sale" under the FASB
Standard Accounting for Certain Investments in Debt and Equity Securities;
accordingly, these securities are stated at fair value, with unrealized gains
and losses recorded in a separate component of common stockholders' equity.
Realized gains and losses on sales of investments, as determined on a specific
identification basis, are included in the consolidated statement of operations
when incurred. As of June 30, 2002 and 2001, the Company's investment in
Capstone had a fair value of $1,163,000 and $29,447,000, respectively, and an
unrealized holding gain, net of tax, of $603,000 and $18,852,000, respectively.
The Company has classified this investment as current, as it plans to monetize
its investment as soon as practicable and use the proceeds to reduce outstanding
debt.

                                      F-14

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2002 and 2001, all other securities owned by the Company are
accounted for under the cost method. The Company's other 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 certain of
these investments.

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, the Company will record a charge on its consolidated statement of
operations to reduce the carrying value of the security to its estimated fair
value.

In June 2002, Southern Union determined that the decline in value of its
investment in PointServe was other than temporary. Accordingly, the Company
recorded a non-cash charge of $10,380,000 to reduce the carrying value of this
investment to its estimated fair value. The Company recognized this valuation
adjustment 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 $4,206,000 at June 30, 2002 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 July 15, 2002, August 30, 2001, June 30, 2000 and
August 6, 1999 Southern Union distributed its annual 5% common stock dividend to
stockholders of record on July 1, 2002, August 16, 2001, June 19, 2000 and July
23, 1999, respectively. A portion of each of the 5% stock dividends 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 The Company maintains its 1992 Long-Term Stock Incentive Plan (1992
Plan) under which options to purchase 7,702,077 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. The Company also had an incentive stock option plan (1982
Plan) that provided for the granting of 787,500 options, until December 31,
1991. Options granted under both the 1992 Plan and the 1982 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 416,747
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

                                      F-15
<PAGE>

                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Under the terms of the Pennsylvania Incentive Plan, a
total of 200,120 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. During 2000, 13,892 options
were granted to a Director of the Company at an exercise price of $15.63. These
options granted vest 20% per year for five years. No additional options will be
granted under the Pennsylvania Incentive Plan.

The Company accounts for its incentive plans under the Accounting Principles
Board opinion, Accounting for Stock Issued to Employees and related
authoritative interpretations. The Company recorded no compensation expense for
2002, 2001 and 2000. During 1997, the Company adopted the FASB Standard,
Accounting for Stock-Based Compensation, for footnote disclosure purposes only.
Had compensation cost for these incentive plans been determined consistent with
this Statement, the Company's net earnings (loss) from continuing operations and
diluted earnings (loss) per share would have been $576,000 and $.01
respectively, in 2002, $38,559,000 and $.67, respectively, in 2001 and
$(12,960,000) and $(.26), respectively, in 2000. Had compensation cost for these
incentive plans been determined consistent with this Statement, the Company's
net earnings available for common stock and diluted earnings per share would
have been $17,894,000 and $.32 respectively, in 2002, $55,043,000 and $.95,
respectively, in 2001 and $8,190,000 and $.16, respectively, in 2000. Because
this Statement has not been applied to options granted prior to July 1, 1995,
the resulting pro forma compensation cost may not be representative of that to
be expected in future years.

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 2002, 2001 and 2000, respectively: dividend yield of nil for all three
years; volatility of 33.5% in 2002 and 27.5% for 2001 and 2000; risk-free
interest rate of 3.75% in 2002, 5% in 2001 and 6% in 2000; and expected life
outstanding of 7 years for 2002, 5.5 years for 2001 and 7.2 years for 2000.
<TABLE>
<CAPTION>

                                     1992 Plan                      1982 Plan
                             ----------------------------  ----------------------------
                                             Weighted                      Weighted
                             Shares Under    Average        Shares Under    Average
                               Option      Exercise Price     Option     Exercise Price
                             ------------  --------------   ------------ --------------
<S>              <C>            <C>        <C>                   <C>     <C>
Outstanding July 1, 1999...     2,813,846  $         9.46        373,928 $         2.66
     Granted ...............    1,131,957           15.65          --              --
     Exercised .............     (129,693)           6.27       (238,559)          2.68
     Canceled ..............      (33,406)          14.72          --              --
                              -----------                   ------------
Outstanding June 30, 2000...    3,782,704           11.37        135,369           2.63
     Granted ...............      844,119           16.96          --              --
     Exercised .............      (90,203)           8.44       (135,369)          2.63
     Canceled ..............      (40,145)          14.83          --              --
                              -----------                   ------------
Outstanding June 30, 2001...    4,496,475           12.45          --              --
                              -----------                   ============
     Granted ...............       21,001           16.90
     Exercised .............     (925,637)          10.53
     Canceled ..............     (146,518)          15.78
                              -----------
Outstanding June 30, 2002       3,445,321           12.85

                                                  F-16
<PAGE>
                     SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding under
the 1992 Plan at June 30, 2002:

                                Options Outstanding                                        Options Exercisable
  ----------------------------------------------------------------------------        -------------------------------
                                            Weighted Average        Weighted                              Weighted
      Range of               Number of         Remaining            Average             Number of         Average
   Exercise Prices            Options       Contractual Life     Exercise Price          Options       Exercise Price
  -----------------        -----------      ----------------     --------------         --------       --------------
  $ 0.00  - $  3.56            317,101           .3 years        $     3.31              317,101        $     3.31
    3.57  -    7.12            281,749          1.8 years              5.96              281,749              5.96
    7.13  -    8.90            233,966          3.4 years              7.45              180,095              7.46
    8.91  -   12.47            363,355          4.9 years             11.29              362,550             11.28
   12.48  -   16.02          1,415,573          6.9 years             15.23              714,598             15.02
   16.03  -   17.81            833,577          8.3 years             16.96               89,659             16.96
                           -----------                                                 ---------
                             3,445,321                                                 1,945,752
                           ===========                                                 =========

The shares exercisable under the various plans and corresponding weighted
average exercise price for the past three years are as follows:
                                                                                           Pennsylvania            Pennsylvania
                                                          1992             1982               Option                Incentive
                                                          Plan             Plan                Plan                    Plan
                                                       ---------         --------          -------------          --------------
Shares exercisable at:
     June 30, 2002..............................       1,945,752               --                416,747                 191,784
     June 30, 2001..............................       2,286,834               --                416,747                 189,004
     June 30, 2000..............................       1,815,402           135,369               416,747                 186,227

Weighted average exercise price at:
     June 30, 2002..............................        $  10.49           $   --          $       10.04          $        11.63
     June 30, 2001..............................            9.44               --                  10.04                   11.57
     June 30, 2000..............................            8.17             2.63                  10.04                   11.49
</TABLE>

The weighted average remaining contractual life of options outstanding under the
Pennsylvania Option Plan and the Pennsylvania Incentive Plan at June 30, 2002
was 4 and 5.9 years, respectively. There were 2,726,053 shares available for
future option grants under the 1992 Plan at June 30, 2002. No shares were
available for future option grants under the 1982 Plan at June 30, 2002.

On February 10, 1994, Southern Union granted a warrant which expires on February
10, 2004, to purchase up to 116,348 shares of Common Stock at an exercise price
of $5.96 to the Company's outside legal counsel.

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. In addition, Southern Union's charter relating to the issuance of
preferred stock limits the payment of cash or asset dividends on capital stock.
Currently, the Company is in compliance with the restrictive provisions in the
indenture governing the Senior Notes.

                XI Derivative Instruments and Hedging Activities

Cash Flow Hedges During fiscal year 2002, the Company was party to three
interest rate swaps that were created to manage exposure against volatility in
interest payments on variable rate debt and which qualify for hedge accounting.
As of June 30, 2002, $954,000 in after-tax comprehensive income generated
through the expiration of two of these swaps was partially offset by the fair
value of the Company's remaining obligation under one swap which resulted in
$150,000 of unrealized losses, net of tax. For the fiscal year ended June 30,
2002, the Company recorded net settlement payments of $1,408,000 on these swaps
through interest expense. Hedge ineffectiveness, which is recorded in interest
expense, was immaterial for fiscal 2002. No component of the swaps' gain or loss
was excluded from the assessment of hedge effectiveness.

                                      F-17

<PAGE>

                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2002 and 2001, the Company's derivative liabilities that are
designated and qualify as cash flow hedges have a fair value of $519,000 and
$2,009,000, respectively, and are offset by matching adjustments to other
comprehensive income. The derivative liabilities are classified as other current
liabilities in the Consolidated Balance Sheet. As of June 30, 2002, the Company
expects to reclassify as interest expense $291,000 in derivative losses, net of
taxes, from accumulated other comprehensive income as the settlement of swap
payments occur over the next twelve months. The maximum length of time over
which the Company is hedging its exposure to the payment of variable interest
rates is 17 months.

Fair Value Hedges During fiscal year 2001, the Company was party to an interest
rate swap designed to reduce exposure to changes in the fair value of a fixed
rate lease commitment. This interest rate swap, designated as a fair value
hedge, was terminated in October 2000 resulting in a pre-tax gain of $182,000.

Trading and Non-Hedging Activities In March 2001, the Company discovered
unauthorized financial derivative energy trading activity by a non-regulated,
wholly-owned subsidiary. All unauthorized trading activity was subsequently
closed in March and April of 2001 resulting in a cumulative cash expense of
$191,000, net of taxes, and deferred income of $7,921,000 at June 30, 2001. For
the fiscal year ended June 30, 2002, the Company recorded $6,204,000 through
other income relating to the expiration of contracts resulting from this trading
activity. The majority of the remaining deferred liability of $1,717,000 at June
30, 2002 related to these derivative instruments will be recognized as income in
the Consolidated Statement of Operations over the next three years based on the
related contracts.

The Company was also previously committed under two gas derivative contracts
related to certain non-regulated operations acquired in conjunction with the
acquisition of the Pennsylvania Operations in November 1999. These two contracts
were not designated as hedges and therefore did not qualify to receive hedge
accounting treatment. During the quarter ended December 31, 2000, the Company
recorded the expiration of these contracts as a pre-tax loss of $526,000 through
other income. This loss was offset by a pre-tax gain of $494,000 recorded
through cost of gas arising from the monthly settlement of the two derivative
contracts that expired in November 2000.

                  XII Preferred Securities of Subsidiary Trust

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 (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. The interest and other payment dates on the Subordinated
Notes correspond to the distribution and other payment dates on the Preferred
Securities and the Common Securities. Under certain circumstances, the
Subordinated Notes may be distributed to holders of the Preferred Securities and
holders of the Common Securities in liquidation of the Subsidiary Trust. The
Subordinated Notes were redeemable at the option of the Company on or after May
17, 2000, at a redemption price of $25 per Subordinated Note plus accrued and
unpaid interest. The Preferred Securities and the Common Securities will be
redeemed on a pro rata basis to the same extent as the Subordinated Notes are
repaid, at $25 per Preferred Security and Common Security plus accumulated and
unpaid distributions. Southern Union's obligations under the Subordinated Notes
and related agreements, taken together, constitute a full and unconditional
guarantee by Southern Union of payments due on the Preferred Securities. As of
June 30, 2002, the quoted market price per Preferred Security was $25.00. As of
June 30, 2002 and 2001, 4,000,000 shares of Preferred Securities were
outstanding.

                                      F-18
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                           XIII Debt and Capital Lease

                                                    June 30,
                                            -----------------------
                                                2002         2001
                                            -----------------------

7.60% Senior Notes due 2024 .............   $  362,515   $  364,515
8.25% Senior Notes due 2029 .............      300,000      300,000
Term Note, due 2005 .....................      350,000      485,000
8.375% First Mortgage Bonds, due 2002 ...       30,000       30,000
5.62% First Mortgage Bonds, due 2003 ....        3,082        4,800
10.25% First Mortgage Bonds, due 2008 ...        1,909        2,182
6.82% First Mortgage Bonds, due 2018 ....       14,464       15,000
9.34% First Mortgage Bonds, due 2019 ....       15,000       15,000
9.63% First Mortgage Bonds, due 2020 ....       10,000       10,000
9.44% First Mortgage Bonds, due 2020 ....        6,500        6,500
8.09% First Mortgage Bonds, due 2022 ....       12,500       12,500
8.46% First Mortgage Bonds, due 2022 ....       12,500       12,500
7.50% First Mortgage Bonds, due 2025 ....       15,000       15,000
7.99% First Mortgage Bonds, due 2026 ....        7,000        7,000
7.24% First Mortgage Bonds, due 2027 ....        6,000        6,000
6.50% First Mortgage Bonds, due 2029 ....       13,933       14,333
7.70% Debentures, due 2022 ..............        6,776        6,806
Capital lease and other, due 2003 to 2007       23,234       28,408
                                            ----------   ----------
Total debt and capital lease ............    1,190,413    1,335,544
    Less current portion ................      108,203        5,913
                                            ----------   ----------
Total long-term debt and capital lease ..   $1,082,210   $1,329,631
                                            ==========   ==========

The maturities of long-term debt and capital lease payments for each of the next
five years ending June 30 are: 2003 -- $108,203,000; 2004 -- $62,361,000; 2005
-- $61,264,000; 2006 -- $177,283,000; 2007 -- $1,820,000 and thereafter
$779,482,000.

Senior Notes On November 3, 1999, the Company completed the sale of $300,000,000
of 8.25% Senior Notes (8.25% Notes) due 2029. The net proceeds from the sale of
these 8.25% Notes were used to: (i) fund the acquisition of Pennsylvania
Enterprises, Inc.; (ii) repay approximately $109,900,000 of borrowings under the
revolving credit facility, and (iii) repay approximately $136,000,000 of long-
and short-term debt assumed in the acquisition. Debt issuance costs and premiums
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 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 $1,007 and $951 (per $1,000
note), respectively on June 30, 2002, as quoted by a major brokerage firm. The
carrying amount of long-term debt at June 30, 2002 and 2001 was $1,190,413,000
and $1,335,544,000, respectively. The fair value of long-term debt at June 30,
2002 and 2001 was $1,174,647,000 and $1,317,667,000, respectively.

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 the 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 mergers, and (iv) all related
acquisition costs. As of June 30, 2002, a balance of $350,000,000 was
outstanding under this Term Note. The Term Note, which initially expired on
August 27, 2001, was extended through August 26, 2002 for a fee. 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 the Company's lines of credit. The 2002 Term Note requires semi-annual
principal repayments on February 15th and August 15th of each year, with
payments of $25,000,000 each being due February 15, 2003, August 15, 2003,
February 15, 2004, and August 15, 2004 and payments of $35,000,000 each being
due February 15, 2005 and August 15, 2005. The remaining principal amount of
$141,087,000 is due August 26, 2005. No additional draws can be made on the Term
Note.

                                      F-19

<PAGE>

                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumed Debt In connection with the acquisition of the Pennsylvania Operations,
the Company assumed $45,000,000 of First Mortgage Bonds bearing interest between
8.375% and 9.34%. In connection with the acquisition of ProvEnergy, the Company
assumed $86,916,000 of First Mortgage Bonds bearing interest between 5.62% and
10.25%. In connection with the acquisition of Fall River Gas, the Company
assumed $19,500,000 of First Mortgage Bonds bearing interest between 7.24% and
9.44%. In connection with the acquisition of Valley Resources, the Company
assumed $6,905,000 of 7.70% Debentures.

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, 2002, the capital lease obligation outstanding was $21,177,000
with a fixed rate of 5.79%. 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 June 10, 2002, the Company entered into an amended
short-term credit facility in the amount of $150,000,000 (the Short-Term
Facility), that matures on June 9, 2003. Also on June 10, 2002, the Company
amended the terms and conditions of its $225,000,000 long-term credit facility
(the Long-Term Facility), which expires on May 29, 2004. The Company has
additional availability under uncommitted line of credit facilities (Uncommitted
Facilities) with various banks. Borrowings under the facilities are available
for Southern Union's working capital, letter of credit requirements and other
general corporate purposes. The Short-Term Facility and the Long-Term Facility
(together, the Facilities) are subject to a commitment fee based on the rating
of the Senior Notes. As of June 30, 2002, the commitment fees were an annualized
0.14% on the Facilities. The interest rate on borrowings on the Facilities is
calculated based upon a formula using the LIBOR or prime interest rates. The
average interest rate under the Facilities was 3.2% for the year ended June 30,
2002 and 6.4% for the year ended June 30, 2001. A $131,800,000 and $190,600,000
balance was outstanding under the Facilities at June 30, 2002 and 2001,
respectively. A balance of $227,500,000 was outstanding under the Facilities at
August 31, 2002.

                              XIV Employee Benefits

Pension and Other Post-Retirement Benefits The Company adopted in 1999,
Employers Disclosures About Pensions and Other Post-Retirement Benefits, a FASB
Standard which changed the Company's reporting requirements for its pension and
post-retirement benefit plans.

The Company maintains eight trusteed non-contributory defined benefit retirement
plans (Plans) which cover substantially all employees. 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.

                                      F-20
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2002 and 2001.

                                                         2002         2001
                                                       ---------    ---------
Change in Benefit Obligation
     Benefit obligation at beginning of year .......   $ 372,515    $ 202,378
     Acquisitions ..................................        --        150,764
     Service cost ..................................       6,843        4,499
     Interest cost .................................      27,932       21,858
     Benefits paid .................................     (28,498)     (23,770)
     Actuarial loss ................................       4,406       15,558
     Plan amendments ...............................      (1,340)       2,133
     Curtailments ..................................       1,495         --
     Special termination benefits ..................      10,266         --
     Settlement recognition ........................         (11)        (905)
                                                       ---------    ---------
     Benefit obligation at end of year .............   $ 393,608    $ 372,515
                                                       =========    =========

Change in Plan Assets
     Fair value of plan assets at beginning of year    $ 324,888    $ 177,909
     Acquisitions ..................................        --        172,019
     Return on plan assets .........................       2,050      (13,813)
     Employer contributions ........................       8,879       12,544
     Benefits paid .................................     (28,498)     (23,771)
                                                       ---------    ---------
     Fair value of plan assets at end of year ......   $ 307,319    $ 324,888
                                                       =========    =========

Funded Status
     Funded status at end of year ..................   $ (86,289)   $ (47,627)
     Unrecognized net actuarial loss ...............      62,154       29,137
     Unrecognized prior service cost ...............       6,630       17,558
                                                       ---------    ---------
     Accrued benefit cost ..........................   $ (17,505)   $    (932)
                                                       =========    =========

Amounts Recognized in the Consolidated Balance Sheet
     Prepaid benefit cost ..........................   $  38,439    $  56,330
     Accrued benefit liability .....................     (75,687)     (70,990)
     Intangible asset ..............................       2,779       12,681
     Accumulated other comprehensive loss ..........      16,964        1,047
                                                       ---------    ---------
     Net liability recognized ......................   $ (17,505)   $    (932)
                                                       =========    =========

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, 2002 were $196,333,000, $179,915,000, and
$151,403,000, respectively, and for those same plans were $39,572,000,
$36,901,000, and $14,780,000 as of June 30, 2001.

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, 2002 were
$76,596,000 and $22,408,000 respectively, and for those same plans were
$70,061,000 and $20,309,000 respectively as of June 30, 2001.

An additional minimum pension liability of $6,851,000 was recorded as of June
30, 2002, as a result of the combination of decreases in the fair value of plan
assets due to volatility in the stock markets and increases in liabilities due
to early retirement programs.

                                      F-21
<PAGE>

                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used for the year ended June 30, 2002, 2001 and
2000 were:
<TABLE>
<CAPTION>

                                                                                 2002             2001            2000
                                                                             -----------     -------------    ------------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Discount rate
     Beginning of year...................................................          7.50%            8.00%           7.00%
     End of year.........................................................          7.50%            7.50%           8.00%
Expected return on assets - tax exempt accounts..........................          9.00%            9.00%           8.00%
Expected return on assets - taxable accounts.............................          5.50%            5.40%           5.25%
Rate of compensation increase (average)..................................          4.95%            4.95%           5.32%
Health care cost trend rate..............................................         12.00%           12.00%           9.00%

Net periodic benefit cost for the year ended June 30, 2002, 2001 and 2000
includes the following components:

                                                                                 2002             2001             2000
                                                                             ------------     ------------    ------------
Service cost  ...........................................................    $      6,843     $      4,499    $      2,053
Interest cost ...........................................................          27,932           21,863          12,754
Expected return on plan assets...........................................         (27,568)         (22,966)        (11,115)
Amortization of prior service cost.......................................             883            1,655             932
Recognized actuarial gain................................................            (543)          (3,464)         (2,671)
Curtailment   ...........................................................          10,105               --              --
Special termination benefits.............................................          10,266               --              --
Settlement recognition...................................................            (457)            (179)             --
                                                                             ------------     ------------    ------------
Net periodic pension cost................................................    $     27,461     $      1,408    $      1,953
                                                                             ============     ============    ============

Curtailment and special termination benefit charges were recognized during 2002
in connection with the Company's corporate reorganization and restructuring
initiatives (see Corporate Restructuring). The Company has deferred, as a
regulatory asset, certain of these charges that have historically been
recoverable in rates.

The assumed rate of compensation increase of 4.95% (average) used in measuring
the accumulated post-retirement benefit obligation during 2002 consisted of a
rate of 5.0% for the plans of Missouri Gas Energy, PG Energy and ProvEnergy, and
rates of 5.50% and 4.25%, respectively, for the plans of Valley Resources, and
Fall River Gas.

The assumed health care cost trend rate used in measuring the accumulated
post-retirement benefit obligation was 12.00% during 2002. This rate was assumed
to decrease gradually each year to a rate of 6.0% for 2006 and remain at that
level thereafter.

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 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.

Effect of assumed health care trend rate changes on health care plans:

                                                                        One Percentage Point        One Percentage Point
                                                                       Increase in Health Care    Decrease in Health Care
                                                                            Trend Rate                      Trend Rate
                                                                       -----------------------    -----------------------
Effect on total service and interest cost components..............         $         282             $         (225)
Effect on post-retirement benefit obligation......................                 2,505                     (1,996)
</TABLE>

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

                                      F-22

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 50% 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 2002, 2001 and 2000 were $2,722,000, $2,673,000
and $1,472,000, 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 2002, 2001 and
2000 were $826,000, $983,000 and $1,190,000, respectively.

Corporate Restructuring In August 2001, the Company implemented a corporate
reorganization and restructuring which was initially announced in July 2001 as
part of a Cash Flow Improvement Plan designed to increase annualized pre-tax
cash flow from operations by at least $50 million by the end of fiscal year
2002. 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. As a result
of actions associated with the business reorganization and restructuring, the
Company expects an annual cost savings in a range of $30 million to $35 million.

In connection with the corporate reorganization and restructuring efforts, the
Company recorded a one-time 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 have been completed as of
June 30, 2002.

                                      F-23

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended June 30, 2002, the Company paid approximately $5.0 million
and $3.2 million in employee separation and other restructuring costs,
respectively. The balance sheet carries a remaining liability of approximately
$4.6 million for various long-term leases 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, 2002 and 2001, 989,143 and 933,191
shares, respectively, of common stock were held by various rabbi trusts for
certain of those Company's benefit plans. Effective March 22, 2001, the Company
amended a benefit plan holding common stock in a rabbi trust eliminating the
non-cash income and expense volatility associated with the accounting treatment
for such plan. During 2002 and 2001 certain employees deferred receipt of
Company shares for stock options exercised. At June 30, 2002, 149,678 shares
were held in a rabbi trust for these employees.

                               XV Taxes on Income

                                              Year Ended June 30,
                                        --------------------------------
                                          2002        2001       2000
                                        --------    --------   ---------

Current:
     Federal ........................   $ (8,848)   $ 15,936    $ (4,009)
     State ..........................     (1,391)        545        (208)
                                        --------    --------    --------
                                         (10,239)     16,481      (4,217)
                                        --------    --------    --------
Deferred:
     Federal ........................     13,050      13,249       1,501
     State ..........................        600         369         604
                                        --------    --------    --------
                                          13,650      13,618       2,105
                                        --------    --------    --------
Total continuing operations provision   $  3,411    $ 30,099    $ (2,112)
                                        ========    ========    ========

Deferred credits and other liabilities from continuing operations also include
$6,212,000 and $6,819,000 of unamortized deferred investment tax credit as of
June 30, 2002 and 2001.

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,
                                                                                                ---------------------------
                                                                                                     2002           2001
                                                                                                ------------   ------------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Deferred tax assets:
     Estimated alternative minimum tax credit................................................   $      3,764   $     12,606
     Insurance accruals......................................................................          1,995            663
     Bad debt reserves.......................................................................          4,229          5,045
     Post-retirement benefits................................................................          1,506          6,941
     Restructuring charges...................................................................          8,287             --
     Other...................................................................................         17,454         19,412
                                                                                                ------------   ------------
         Total deferred tax assets...........................................................         37,235         44,667
                                                                                                ------------   ------------
Deferred tax liabilities:
     Property, plant and equipment...........................................................       (178,089)      (183,361)
     Unamortized debt expense................................................................         (5,489)        (4,906)
     Regulatory liability....................................................................        (14,746)        (9,006)
     Unrealized holding gain on securities...................................................           (325)        (5,638)
     Other...................................................................................        (51,009)       (40,002)
                                                                                                ------------   ------------
         Total deferred tax liabilities......................................................       (249,658)      (242,913)
                                                                                                ------------   ------------
Net deferred tax liability...................................................................       (212,423)      (198,246)
Less current tax assets......................................................................          4,229          5,045
                                                                                                ------------   ------------
Accumulated deferred income taxes............................................................   $   (216,652)  $   (203,291)
                                                                                                ============   ============
                                                          F-24
<PAGE>
</TABLE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company accounts for income taxes utilizing the liability method which bases
the amounts of current and future 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,
                                                                                       ------------------------------------
                                                                                            2002       2001         2000
                                                                                       -----------  ----------    ---------

<S>                                                          <C>                       <C>          <C>           <C>
Computed statutory tax expense from continuing operations at 35%................       $     1,726  $   24,590    $  (4,327)
Changes in taxes resulting from:
     State income taxes, net of federal income tax benefit......................               695         670          530
     Amortization/write-down of goodwill........................................             3,113       4,770        1,563
     Internal Revenue Service audit settlement..................................            (1,570)         --           --
     Investment Tax Credit amortization.........................................              (608)         --           --
     Other......................................................................                55          69          122
                                                                                       -----------  ----------    ---------
Actual tax expense from continuing operations...................................       $     3,411  $   30,099    $  (2,112)
                                                                                       ===========  ==========    =========
</TABLE>

                        XVI Utility Regulation and Rates

Missouri On July 5, 2001, the Missouri Public Service Commission (MPSC) issued
an order approving a unanimous settlement of Missouri Gas Energy's rate request.
The settlement provides for an annual $9,892,000 base rate increase, as well as
$1,081,000 in added revenue from new and revised service charges. The majority
of the rate increase will be recovered through increased customer service
charges to gas sales service customers. New rates became effective August 6,
2001, two months before the statutory deadline for resolving the case. The
approved settlement resulted in the dismissal of all pending judicial reviews of
prior rate cases. The settlement also provides for the development of a two-year
experimental low-income program that will help certain customers in the Joplin
area pay their natural gas bills.

The approval of the January 31, 1994 acquisition of the Missouri properties by
the MPSC was subject to the terms of a stipulation and settlement agreement,
which, among other things, requires Missouri Gas Energy to reduce rate base by
$30,000,000 (amortized over a ten-year period on a straight-line basis) to
compensate rate payers for rate base reductions that were eliminated as a result
of the acquisition.

Rhode Island On May 24, 2002, the Rhode Island Public Utilities Commission
(RIPUC) approved a settlement agreement between the New England Gas Company and
the RIPUC. 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.

Pursuant to the RIPUC's Written Order issued April 30, 2001, Providence Gas'
Price Stabilization Plan was extended through June 2002. The related settlement
agreement provided for additional gas distribution margin of $12,030,000 over
the 21-month period, October 2000 through June 2002, or approximately $6,240,000
for the twelve months ended September 2001. The settlement agreement also
contained a weather mitigation clause and a non-firm margin incentive mechanism.
The weather mitigation clause allowed Providence Gas to defer the margin impact
of weather that was greater than 2% colder-than-normal and to recover the margin
impact of weather that was greater than 3% warmer-than-normal by making the
corresponding adjustment to the deferred

                                      F-25

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

revenue account (DRA). The non-firm margin incentive mechanism allowed
Providence Gas to retain 25% of all non-firm margins earned in excess of
$1,200,000. Under the settlement agreement, Providence Gas was able earn up to
10.7%, but not less than 7.0%, using the average return on equity for the two
12-month periods of October 2000 through September 2001 and July 2001 through
June 2002.

Effective October 1, 2000, the RIPUC approved a settlement agreement between
Providence Gas, the RIPUC, the Energy Council of Rhode Island, and The George
Wiley Center. The settlement agreement recognized the need for an increase in
distribution system revenues of $4,500,000, recovered through an adjustment to
the throughput portion of the gas charge, and provided for a 21-month base rate
freeze.

Pennsylvania In December 2000, the Pennsylvania Public Utility Commission
approved a settlement agreement that provided for a rate increase designed to
produce $10,800,000 of additional annual revenue. The new rates became effective
on January 1, 2001.

                                   XVII Leases

The Company leases certain facilities, equipment and office space under
cancelable and noncancelable operating leases. The minimum annual rentals from
continuing operations under operating leases for the next five years ending June
30 are as follows: 2003-- $3,003,000; 2004-- $2,645,000; 2005-- $2,283,000;
2006-- $2,206,000; 2007-- $2,539,000 and thereafter $4,737,000. Rental expense
from continuing operations was $5,759,000, $7,652,000 and $7,332,000 for the
years ended June 30, 2002, 2001 and 2000, respectively.

                       XVIII Commitments and Contingencies

Environmental The Company is subject to federal, state and local laws and
regulations relating to the protection of the environment. These evolving laws
and regulations may require expenditures over a long period of time to control
environmental impacts. The Company has established procedures for the on-going
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 service territories, principally in Texas, Arizona and New Mexico,
and present 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 service territories
certain MGP sites are currently the subject of governmental actions. These sites
are as follows:

Kansas City, Missouri MGP Sites 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
Manufactured Gas Plant (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 sent applications to MDNR submitting the two sites to the agency's
Voluntary Cleanup Program (VCP). The sites were accepted into the VCP, and MGE
subsequently performed environmental assessments of Stations A and B and
submitted the results of these assessments to MDNR. On September 6, 2002, MGE
submitted a work plan for the remediation of Station A to MDNR. Following the
approval of the Station A work plan by MDNR, the Company will select a qualified
contractor in a competitive bidding process. The Company anticipates beginning
remediation of Station A in the first calendar quarter of 2003.

In August 2001, MGE received a demand from the Port Authority for MGE to assume
responsibility for remediation of soil and groundwater at property owned by the
Port Authority adjacent to MGE's Stations A and B. The Port Authority intends to
develop its property adjacent to MGE as a commercial and residential area (the

                                      F-26

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Riverfront Redevelopment Site), and seeks to have MGE and other parties who may
be responsible remediate contamination on the Port Authority property allegedly
resulting from the historic manufactured gas plant operations. Honeywell
International Inc. has also been identified as a potentially responsible party,
as the alleged successor to a tar manufacturing operation formerly located on a
portion of the Port Authority property known as the Riverfront Development. MGE
and other parties owning property in the area have performed assessments in 2001
and early 2002 of their own and of the alleged contaminated portions of the Port
Authority property.

In a letter dated July 24, 2002, the Port Authority demanded that the Company
assume full financial responsibility for the design and implementation of a
remedial action plan on the Riverfront Redevelopment Site allowing the Port
Authority to obtain an "unrestricted" clearance for redevelopment of the site.
The Port Authority provided MGE with several proposed remedial options and
preliminary cost estimates for those options. The worst-case and most expensive
proposed remedial option is currently estimated by the Port Authority to cost
$48.9 million. MGE currently disputes the Port Authority's estimates and
proposals, and believes that the cost of remediation of the Port Authority
property could be significantly lower, pending further investigation, analysis
and determination of appropriate soil and groundwater remedial standards.
Accordingly, the Company sent the Port Authority a letter dated August 27, 2002,
containing an alternative proposal for the remediation of a portion of the Port
Authority's property. MGE's own estimate of the cost to perform its alternative
proposal and obtain a "no further action" letter from MDNR for the portion of
the Riverfront Redevelopment Site for which it is potentially responsible is $4
million. MGE continues to work with the Port Authority and MDNR toward
resolution of the appropriate scope of investigation and remediation at the
Riverfront Redevelopment Site.

Providence, Rhode Island Sites During 1995, Providence Gas began an
environmental evaluation at its primary gas distribution facility located at 642
Allens Avenue in Providence, Rhode Island. Environmental studies and a
subsequent remediation work plan were completed at an approximate cost of $4.5
million. Providence Gas also began a soil remediation project on a portion of
the site in July 1999. As of June 30, 2001, approximately $8.9 million had been
expended on soil remediation under the remediation work plan. Based on the
results of the environmental investigation and the site information learned
during the performance of work under the remediation work plan, on January 15,
2002, the Company requested and subsequently received authorization from RIDEM
to make certain specific modifications to the 1999 Remedial Action Work Plan. On
April 17, 2002, RIDEM issued a Temporary Remedial Action Permit for Phase 1
remediation at the site. At the completion of a competitive bidding process, a
contractor was selected by the Company, and work on Phase 1 of the site
remediation was initiated on April 17, 2002. The Company has reserved $5.8
million for completion of this phase of the site remediation. 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 the
RIDEM relating to possible contamination on previously owned property at 170
Allens Avenue in Providence. The operator of the property at that time, Cargill,
Inc., also received a letter of responsibility. A work plan had been created and
approved by RIDEM. An investigation was then 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 the current operator of the
property, under which Providence Gas was responsible for approximately twenty
percent (20%) of the costs related to the investigation. Costs of testing at
this site as of June 30, 2002 were approximately $300,000. Until RIDEM provides
its final response to the investigation, and the Company knows it's 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.

Tiverton, Rhode Island Site Fall River Gas Company was a defendant in a civil
action seeking to recover anticipated remediation costs associated with
contamination found at property owned by the plaintiffs. 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 site sufficient to obtain a final letter of compliance from the Rhode
Island Department of Environmental Management.

Valley Gas Company Sites Valley Gas 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 manufacturing waste was transported from a former MGP site in

                                      F-27
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 EPA (Commonwealth of Massachusetts
v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). In January 2001, the
EPA issued a Preliminary Administrative Decision on this issue and announced
that it was soliciting comments on the Decision. While the public comment period
has now closed, the EPA has yet to reissue its decision. While this suit has
been stayed, Valley Gas Company and Blackstone (merged with Narragansett
Electric Company in May 2000) 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.

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 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 10-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.

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 for MGP sites will have a material adverse effect on
the Company's financial position, results of operations or cash flows.

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.

Regulatory In August 1998, the City of Edinburg obtained a jury verdict totaling
approximately $13,000,000 jointly and severally against PG&E Gas
Transmission-Texas Corporation (formerly Valero Energy Corporation (Valero)),
and a number of its subsidiaries, as well as former Valero subsidiary Rio Grande
Valley Gas Company (RGV) and RGV's successor company, Southern Union Company for
the alleged underpayment of franchise fees. (Southern Union purchased RGV from
Valero in 1993.) The trial court reduced the jury award to approximately
$8,500,000. Subsequently, the Texas (13th District) Court of Appeals further
reduced the award to $4,085,000. The Court of Appeals also remanded a portion of
the case to the trial court with instructions to retry certain issues. The
Company continues to pursue reversal on appeal. In August 2002, the Supreme
Court of Texas granted the Company's petition for review. Oral arguments have
been scheduled for November 20, 2002. Effective January 1, 2003, all potential
remaining liability for this case was assigned to ONEOK as part of the sale of
the Company's Texas Operations to ONEOK.

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. As of September 20, 2002, the Commission had not yet adopted a
procedural schedule or set the matter for hearing.

                                      F-28

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. As
of September 20, 2002, the Commission had not yet adopted a procedural schedule
or set the matter for hearing.

Southwest Gas Litigation On February 1, 1999, Southern Union submitted a
proposal to the Board of Directors of Southwest Gas Corporation (Southwest) to
acquire all of Southwest's outstanding common stock for $32.00 per share.
Southwest at that time had a pending merger agreement with ONEOK, Inc. (ONEOK)
at $28.50 per share, executed on December 14, 1998. On February 22, 1999,
Southern Union and Southwest both publicly announced Southern Union's proposal,
after the Southwest Board of Directors determined that Southern Union's proposal
was a Superior Proposal (as defined in the Southwest merger agreement with
ONEOK). At that time Southern Union entered into a Confidentiality and
Standstill Agreement with Southwest at Southwest's insistence. On April 25,
1999, Southwest's Board of Directors rejected Southern Union's $32.00 per share
offer and accepted an amended offer of $30.00 per share from ONEOK. On April 27,
1999, Southern Union increased its offer to $33.50 per share and agreed to pay
interest which, together with dividends, would provide Southwest shareholders
with a 6% annual rate of return on its $33.50 offer, commencing February 15,
2000, until closing. Southwest's Board of Directors rejected Southern Union's
revised proposal. On January 21, 2000, ONEOK announced that it was withdrawing
from the Southwest merger agreement.

There were several actions commenced by parties involved in efforts to acquire
Southwest. All of these actions eventually were transferred to the District of
Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of
summary judgments granted, there are no claims remaining against Southern Union.
On August 6, 2002, Southwest and Southern Union settled their claims against
each other in consideration of a payment to be made to Southern Union by
Southwest Gas of $17,500,000. On August 9, 2002, ONEOK and Southwest settled all
claims asserted against each other in consideration of a $3,000,000 payment to
be made to Southwest by ONEOK.

The remaining issues to be resolved at trial involve claims by the Company
against ONEOK and certain individuals. Southern Union's damage claims have been
limited to its out-of-pocket costs and punitive damages. Trial is scheduled to
commence October 15, 2002.

With the exception of ongoing legal fees associated with the aforementioned
litigation, 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.

Other 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, 2002, the Company has
purchase commitments under continuing operations for certain quantities of gas
at variable, market-based prices that have an annual value of $73,885,000. The
Company's purchase commitments may extend over a period of 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.

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

                                      F-29

<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 in January 2002. The TIF Debt
bears interest at a floating rate with a floor of 6.0% and a ceiling of 7.75%
and matures on June 30, 2011. The loan requires interest-only payments until
June 30, 2003, and semi-annual interest and principal payments thereafter. As of
June 30, 2002, the interest rate on the TIF Debt is 6.0% and estimated
incremental tax revenues are expected to cover approximately 45% of the fiscal
year 2003 annual debt service. The balance outstanding on the TIF Debt was
$9,710,000 as of June 30, 2002.

During fiscal year 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 (formerly Valley Resources), effective May 2002;
a four-year contract with one bargaining unit representing employees of New
England Gas Company's Fall River operations (formerly Fall River Gas), effective
April 2002; and a one year extension of a contract with one bargaining unit
representing employees of New England Gas Company's Cumberland operations, which
was effective May 2002.

During fiscal 2001, the Company agreed to three-year contracts with two
bargaining units representing Pennsylvania employees, which were effective in
April 2001 and August of 2000, respectively. In December 1998, the Company
agreed to five-year contracts with each bargaining-unit representing Missouri
employees, which were effective in May 1999.

Of the Company's employees represented by unions, 44% are employed by Missouri
Gas Energy, 40% are employed by the New England Division and 16% are employed by
PG Energy.

The Company had standby letters of credit outstanding of $30,541,000 at June 30,
2002 and $2,716,000 at June 30, 2001, which guarantee payment of natural gas
purchases, insurance claims and other various commitments.

                                      F-30
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

              XIX Discontinued Operations and Assets Held for Sale

Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. for
approximately $420,000,000 in cash. 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 distributes 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 markets natural
gas to commercial and industrial customers. SUPro provides 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
owns and operates 118.8 miles of intrastate pipeline that serves commercial,
industrial and utility customers in central, south and coastal Texas. SUEI and
Investments participate in energy-related projects internationally. Energia
Estrella del Sur, S. A. de C. V., a wholly-owned Mexican subsidiary of SUEI and
Investments, has a 43% equity ownership in a natural gas distribution company,
along with other related operations, which currently serves 23,000 customers in
Piedras Negras, Mexico, across the border from Southern Union Gas' Eagle Pass,
Texas service area. Norteno owns and operates interstate pipelines that serve
the gas distribution properties of Southern Union Gas and the Public Service
Company of New Mexico. Norteno also transports gas through its interstate
network to the country of Mexico for Pemex Gas y Petroquimica Basica.

The following table summarizes the major classes of the Texas Operations' assets
and liabilities that have been segregated and reported as "held for sale" in the
Company's consolidated balance sheet:
<TABLE>
<CAPTION>

                                                                    June 30,
                                                             ----------------------
ASSETS:                                                        2002          2001
                                                             ---------    ---------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Property, plant and equipment:
     Utility plant, at cost ..............................   $ 504,015    $ 480,462
     Accumulated depreciation and amortization ...........    (217,425)    (201,496)
                                                             ---------    ---------
         Net property, plant and equipment ...............     286,590      278,966
Current assets ...........................................      29,677       50,116
Goodwill, net ............................................      70,469       72,572
Deferred charges and other assets ........................       8,710        9,470
                                                             ---------    ---------
         Total assets held for sale ......................   $ 395,446    $ 411,124
                                                             =========    =========

LIABILITIES:
Current liabilities ......................................   $  43,762    $  38,521
Deferred credits and other liabilities ...................      23,956       19,473
                                                             ---------    ---------
         Total liabilities related to assets held for sale   $  67,718    $  57,994
                                                             =========    =========

</TABLE>

The following table summarizes the Texas Operations' results of operations that
have been segregated and reported as "discontinued operations" in the Company's
consolidated statement of operations:
<TABLE>
<CAPTION>
                                                                                         Year Ended June 30,
                                                                           ------------------------------------------------
                                                                                2002              2001             2000
                                                                           -------------     -------------    -------------

<S>                                                                        <C>               <C>              <C>
Operating revenues.....................................................    $     309,936     $     471,002    $     264,871
                                                                           =============     =============    =============
Net operating margin (a)...............................................    $     105,730     $     109,016    $     102,792
                                                                           =============     =============    =============
Net earnings from discontinued operations (b)..........................    $      18,104     $      16,524    $      20,096
                                                                           =============     =============    =============
</TABLE>
---------------------------------
(a)  Net operating margin consists 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.

                                      F-31
<PAGE>
                    SOUTHERN UNION COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>

                                              XX Quarterly Operations (Unaudited)

                 Year Ended                                                  Quarter Ended
                                                  --------------------------------------------------------------
               June 30, 2002                      September 30(1)   December 31        March 31        June 30         Total
               -------------                      --------------   ---------------    -----------   ------------    ------------

<S>                                               <C>              <C>                <C>           <C>             <C>
Total operating revenues....................      $      120,676   $      286,622     $   419,599   $    153,717    $    980,614
Operating margin............................              55,576          104,455         143,630         70,467         374,128
Net earnings (loss) from continuing operations           (29,906)           7,554          38,899        (15,027)          1,520
Net earnings (loss) from discontinued operations            (497)          12,196           4,889          1,516          18,104
Net earnings (loss) available for common stock           (30,403)          19,750          43,788        (13,511)         19,624
Diluted net earnings (loss) per share:(2)
   Continuing operations....................                (.54)             .13             .69           (.28)            .03
   Discontinued operations..................                (.01)             .22             .09            .03             .32
   Available for common stock...............                (.55)             .35             .78           (.25)            .35



                 Year Ended                                                  Quarter Ended
                                                  ----------------------------------------------------------------
               June 30, 2001                      September 30      December 31(3)     March 31(4)     June 30(4)      Total
               -------------                      ------------      -------------     ------------  --------------  -----------

Total operating revenues....................      $     86,638      $     457,024     $   718,595   $     199,554   $  1,461,811
Operating margin............................            33,700            116,245         161,973          68,328        380,246
Net earnings (loss) from continuing operations         (15,692)            14,478          33,768           7,605         40,159
Net earnings from discontinued operations                1,117              4,840           7,038           3,529         16,524
Net earnings (loss) available for common stock         (13,973)            19,318          40,806          11,134         57,285
Diluted net earnings (loss) per share:(2)
   Continuing operations....................              (.29)               .25             .58             .13            .70
   Discontinued operations..................               .02                .08             .12             .06            .29
   Available for common stock...............              (.26)               .33             .70             .19            .99
</TABLE>

(1)  Net loss from continuing operations for the three-month period ended
     September 30, 2001, was impacted by a $30,553,000 business restructuring
     charge, which was partially offset by $17,166,000 in gains generated
     through the settlement of several interest rate swaps. Excluding the effect
     of these items, net loss from continuing operations for the three-month
     period ended September 30, 2001 was $21,187,000 or $.38 per share.
(2)  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.
(3)  Net earnings from continuing operations for the three-month period ended
     December 31, 2000, were positively impacted by both the sale of non-core
     real estate and a portion of Southern Union's holdings in Capstone Turbine
     Corporation, realizing after-tax gains of $11,292,000 or $.19 per share.
     Excluding the effect of these items, net loss from continuing operations
     for the three-month period ended December 31, 2000 was $3,186,000 or $.05
     per share.
(4)  Net earnings from continuing operations during the third and fourth quarter
     of 2001 benefited from the sale of a portion of Southern Union's holdings
     in Capstone Turbine Corporation realizing after-tax gains of $41,802,000.
     Excluding the effect of this item, net earnings from continuing operations
     for the quarter ended March 31, 2001 were $26,543,000 or $.46 per share,
     and the net loss for the quarter ended June 30, 2001 was $26,971,000 or
     $.46 per share.

                                      F-32

<PAGE>




                        REPORT OF INDEPENDENT ACCOUNTANTS



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 at June 30, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended June 30, 2002, 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 auditing standards
generally accepted in the United States of America, which 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

Philadelphia, Pennsylvania
September 17, 2002, except for the information in Note XIX as to which the date
is January 1, 2003


                                      F-33

<PAGE>






                                                                   Exhibit 99.2


                       CONSENT OF INDEPENDENT ACCOUNTANTS



We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (File Nos. 333-74696, 333-71988, 333-02965, 333-10585,
and 333-102388) 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, and 333-47144)
of Southern Union Company of our report dated September 17, 2002, except for the
information in Note XIX as to which the date is January 1, 2003, relating to the
consolidated financial statements, which appears in this Current Report on Form
8-K of Southern Union Company dated March 10, 2003.




PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania
March 10, 2003