SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549


                                    FORM 10-Q

[ X ]    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934

                 FOR THE QUARTERLY PERIOD ENDING SEPTEMBER 30, 1998

                                       OR

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

         For the transition period from              to
                                       -------------   ----------------


Commission file number 1-6788

                         THE UNITED ILLUMINATING COMPANY

             (Exact name of registrant as specified in its charter)

           CONNECTICUT                                    06-0571640
(State or other jurisdiction                (I.R.S. Employer Identification No.)
of incorporation or organization)

157 CHURCH STREET, NEW HAVEN, CONNECTICUT                       06506
(Address of principal executive offices)                      (Zip Code)

        REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000


                                      NONE
    (Former name,  former  address and former fiscal year, if changed since last
     report.)


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

                                                 YES  X   NO
                                                    -----   -----

     The  number of shares  outstanding  of the  issuer's  only  class of common
stock, as of September 30, 1998, was 14,334,922.

                                     - 1 -
<PAGE>


                                      INDEX

                          Part I. FINANCIAL INFORMATION

                                                                          PAGE
                                                                         NUMBER
                                                                        -------

Item 1.  Financial Statements.                                              3

         Consolidated Statement of Income for the three and nine months
           ended September 30, 1998 and 1997.                               3
         Consolidated Balance Sheet as of September 30, 1998 and
           December 31, 1997.                                               4
         Consolidated Statement of Cash Flows for the three and nine
           months ended September 30, 1998 and 1997.                        6

         Notes to Consolidated Financial Statements.                        7
           -   Statement of Accounting Policies                             7
           -   Capitalization                                               8
           -   Rate-Related Regulatory Proceedings                          9
           -   Short-term Credit Arrangements                              11
           -   Income Taxes                                                12
           -   Supplementary Information                                   13
           -   Fuel Financing Obligations and Other Lease Obligations      14
           -   Commitments and Contingencies                               14
               -  Capital Expenditure Program                              14
               -  Nuclear Insurance Contingencies                          14
               -  Other Commitments and Contingencies                      15
                  - Connecticut Yankee                                     15
                  - Hydro-Quebec                                           15
                  - Property Taxes                                         16
                  - Site Decontamination, Demolition and Remediation Costs 16
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning     16

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations.                                        18

           -   Major Influences on Financial Condition                     18
           -   Capital Expenditure Program                                 22
           -   Liquidity and Capital Resources                             23
           -   Subsidiary Operations                                       24
           -   Results of Operations                                       25
           -   Looking Forward                                             28

                           Part II. OTHER INFORMATION

Item 1.  Legal Proceedings.                                                35

Item 6.  Exhibits and Reports on Form 8-K.                                 36

         SIGNATURES                                                        37


                                     - 2 -
<PAGE>
<TABLE>
                                       PART I: FINANCIAL INFORMATION
                                        ITEM I: FINANCIAL STATEMENTS
                                      THE UNITED ILLUMINATING COMPANY
                                      CONSOLIDATED STATEMENT OF INCOME
                                    (THOUSANDS EXCEPT PER SHARE AMOUNTS)
                                                (UNAUDITED)

<CAPTION>
                                                                         Three Months Ended             Nine Months Ended
                                                                            September 30,                 September 30,
                                                                         1998           1997            1998          1997
                                                                         ----           ----            ----          ----

<S>                                                                    <C>            <C>             <C>           <C>     
OPERATING REVENUES (NOTE G)                                            $198,601       $196,563        $520,867      $540,662
                                                                   -------------  -------------   -------------  ------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                     39,701         44,024         113,654       137,965
     Capacity purchased                                                   9,124          8,359          24,324        30,198
     Other                                                               36,384         38,415         107,787       115,324
  Maintenance                                                            10,981         10,122          32,574        30,016
  Depreciation                                                           23,247         17,239          64,685        57,945
  Amortization of cancelled nuclear project and deferred return           3,440          3,440          10,319        10,319
  Income taxes (Note F)                                                  24,448         23,101          47,128        35,128
  Other taxes (Note G)                                                   13,814         13,512          39,083        40,574
                                                                   -------------  -------------   -------------  ------------
       Total                                                            161,139        158,212         439,554       457,469
                                                                   -------------  -------------   -------------  ------------
OPERATING INCOME                                                         37,462         38,351          81,313        83,193
                                                                   -------------  -------------   -------------  ------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                       (35)           (12)             35           330
  Other-net (Note G)                                                      1,798             83          (2,218)        1,589
  Non-operating income taxes                                                701          1,981           3,707         4,920
                                                                   -------------  -------------   -------------  ------------
       Total                                                              2,464          2,052           1,524         6,839
                                                                   -------------  -------------   -------------  ------------
INCOME BEFORE INTEREST CHARGES                                           39,926         40,403          82,837        90,032
                                                                   -------------  -------------   -------------  ------------
INTEREST CHARGES
  Interest on long-term debt                                             11,759         16,233          38,161        48,481
  Interest on Seabrook obligation bonds owned by the company             (1,817)        (1,691)         (5,453)       (5,073)
  Other interest (Note G)                                                 2,169            872           4,445         2,490
  Allowance for borrowed funds used during construction                    (241)          (288)           (505)       (1,127)
                                                                   -------------  -------------   -------------  ------------
                                                                         11,870         15,126          36,648        44,771
  Amortization of debt expense and redemption premiums                      617            672           1,885         1,998
                                                                   -------------  -------------   -------------  ------------
       Net Interest Charges                                              12,487         15,798          38,533        46,769
                                                                   -------------  -------------   -------------  ------------

MINORITY INTEREST IN PREFERRED SECURITIES                                 1,203          1,203           3,609         3,609
                                                                   -------------  -------------   -------------  ------------

NET INCOME                                                               26,236         23,402          40,695        39,654
Discount on preferred stock redemptions                                       0            (29)            (21)          (48)
Dividends on preferred stock                                                 50             51             151           154
                                                                   -------------  -------------   -------------  ------------
INCOME APPLICABLE TO COMMON STOCK                                       $26,186        $23,380         $40,565       $39,548
                                                                   =============  =============   =============  ============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                      14,028         13,887          14,012        14,029
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                    14,032         13,908          14,018        14,036

EARNINGS PER SHARE OF COMMON STOCK - BASIC                                $1.87          $1.68           $2.90         $2.82
EARNINGS PER SHARE OF COMMON STOCK - DILUTED                              $1.87          $1.68           $2.89         $2.82

CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK                         $0.72          $0.72           $2.16         $2.16
</TABLE>


                  The accompanying Notes to Consolidated Financial
               Statements are an integral part of the financial statements.


                                     - 3 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY
                           CONSOLIDATED BALANCE SHEET

                                     ASSETS
                             (Thousands of Dollars)

<CAPTION>
                                                           September 30,        December 31,
                                                               1998                1997*
                                                               ----                ----
                                                           (Unaudited)
<S>                                                           <C>                 <C>
Utility Plant at Original Cost
  In service                                                  $1,875,768          $1,867,145
  Less, accumulated provision for depreciation                   698,371             644,971
                                                          ---------------     ---------------
                                                               1,177,397           1,222,174

Construction work in progress                                     27,202              25,448
Nuclear fuel                                                      22,928              25,990
                                                          ---------------     ---------------
     Net Utility Plant                                         1,227,527           1,273,612
                                                          ---------------     ---------------


Other Property and Investments                                    35,561              32,451
                                                          ---------------     ---------------

Current Assets
  Cash and temporary cash investments                             13,329              32,002
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                                66,013              57,231
   Other                                                          33,000              27,914
  Accrued utility revenues                                        23,945              25,269
  Fuel, materials and supplies, at average cost                   29,029              19,147
  Prepayments                                                     31,189               3,397
  Other                                                              143                  67
                                                          ---------------     ---------------
     Total                                                       196,648             165,027
                                                          ---------------     ---------------

Deferred Charges
  Unamortized debt issuance expenses                               8,924               6,611
  Other                                                            3,443               5,727
                                                          ---------------     ---------------
     Total                                                        12,367              12,338
                                                          ---------------     ---------------

Regulatory Assets (future amounts due from customers
                   through the ratemaking process)
  Income taxes due principally to book-tax differences           216,453             228,992
  Connecticut Yankee                                              46,666              51,313
  Deferred return - Seabrook Unit 1                               15,732              25,171
  Unamortized redemption costs                                    21,994              23,027
  Unamortized cancelled nuclear projects                          11,245              12,125
  Uranium enrichment decommissioning cost                          1,211               1,312
  Other                                                            5,311               6,357
                                                          ---------------     ---------------
     Total                                                       318,612             348,297
                                                          ---------------     ---------------

                                                              $1,790,715          $1,831,725
                                                          ===============     ===============
</TABLE>
*Derived from audited financial statements

                      The accompanying Notes to Consolidated Financial
                Statements are an integral part of the financial statements.


                                     - 4 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY
                           CONSOLIDATED BALANCE SHEET

                         CAPITALIZATION AND LIABILITIES
                             (Thousands of Dollars)

<CAPTION>
                                                            September 30,        December 31,
                                                                1998                1997*
                                                                ----                ----
                                                             (Unaudited)
<S>                                                             <C>                 <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                 $292,006            $288,730
    Paid-in capital                                                 1,978               1,349
    Capital stock expense                                          (2,182)             (2,182)
    Unearned employee stock ownership plan equity                 (10,447)            (11,160)
    Retained earnings                                             172,506             162,226
                                                           ---------------     ---------------
                                                                  453,861             438,963
  Preferred stock                                                   4,299               4,351
  Minority interest in preferred securities                        50,000              50,000
  Long-term debt
    Long-term debt                                                657,501             746,058
    Investment in Seabrook obligation bonds                       (92,860)           (101,388)
                                                           ---------------     ---------------
      Net long-term debt                                          564,641             644,670
                                                           ---------------     ---------------

          Total                                                 1,072,801           1,137,984
                                                           ---------------     ---------------

Noncurrent Liabilities
  Connecticut Yankee contract obligation                           36,905              40,821
  Pensions accrued                                                 34,794              39,149
  Nuclear decommissioning obligation                               21,568              17,538
  Obligations under capital leases                                 16,596              16,853
  Other                                                             6,343               5,507
                                                           ---------------     ---------------
          Total                                                   116,206             119,868
                                                           ---------------     ---------------

Current Liabilities
  Current portion of long-term debt                                74,574             100,000
  Notes payable                                                   113,195              37,751
  Accounts payable                                                 38,750              68,699
  Dividends payable                                                10,150              10,051
  Taxes accrued                                                    20,355               4,166
  Interest accrued                                                 14,330              10,266
  Obligations under capital leases                                    345                 340
  Other accrued liabilities                                        40,313              37,471
                                                           ---------------     ---------------
          Total                                                   312,012             268,744
                                                           ---------------     ---------------

Customers' Advances for Construction                                1,866               1,878
                                                           ---------------     ---------------

Regulatory Liabilities (future amounts owed to customers
                        through the ratemaking process)
  Accumulated deferred investment tax credits                      15,814              16,385
  Other                                                             5,053               2,356
                                                           ---------------     ---------------
          Total                                                    20,867              18,741
                                                           ---------------     ---------------

Deferred Income Taxes (future tax liabilities owed                266,963             284,510
                       to taxing authorities)
Commitments and Contingencies (Note L)
                                                           ---------------     ---------------
                                                               $1,790,715          $1,831,725
                                                           ===============     ===============
</TABLE>

* Derived from audited financial statements

                      The accompanying Notes to Consolidated Financial
                Statements are an integral part of the financial statements.

                                     - 5 -
<PAGE>
<TABLE>
                                     THE UNITED ILLUMINATING COMPANY
                                  CONSOLIDATED STATEMENT OF CASH FLOWS
                                        (THOUSANDS OF DOLLARS)
                                              (UNAUDITED)

<CAPTION>
                                                                       Three Months Ended          Nine Months Ended
                                                                          September 30,              September 30,
                                                                        1998         1997          1998           1997
                                                                        ----         ----          ----           ----
<S>                                                                    <C>          <C>           <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                           $26,236      $23,402       $40,695        $39,654
                                                                   ------------  -----------  ------------  -------------
  Adjustments to reconcile net income
    to net cash provided by operating activities:
     Depreciation and amortization                                      24,419       18,405        68,167         61,460
     Deferred income taxes                                                 271        5,609        (5,009)        (5,356)
     Deferred investment tax credits - net                                (190)        (190)         (571)          (571)
     Amortization of nuclear fuel                                        1,641        1,785         4,138          4,662
     Allowance for funds used during construction                         (206)        (276)         (540)        (1,457)
     Amortization of deferred return                                     3,146        3,146         9,439          9,439
     Changes in:
             Accounts receivable - net                                 (10,342)      (6,754)      (13,868)        16,417
             Fuel, materials and supplies                                1,680        1,007        (9,882)         1,966
             Prepayments                                               (21,711)      (3,687)      (27,792)        (4,278)
             Accounts payable                                          (14,096)        (517)      (29,949)       (25,172)
             Interest accrued                                           (3,853)      (6,529)        4,064          2,608
             Taxes accrued                                              14,269        9,202        16,189         11,103
             Other assets and liabilities                                1,693          336         2,888         (1,998)
                                                                   ------------  -----------  ------------  -------------
     Total Adjustments                                                  (3,279)      21,537        17,274         68,823
                                                                   ------------  -----------  ------------  -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES                               22,957       44,939        57,969        108,477
                                                                   ------------  -----------  ------------  -------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Common stock                                                            308      (10,390)        4,618        (10,390)
   Long-term debt                                                            -       98,500        99,780         98,500
   Notes payable                                                        (5,630)       8,354        75,444         33,030
   Securities redeemed and retired:
     Preferred stock                                                         -          (70)          (52)          (110)
     Long-term debt                                                          -      (55,749)     (213,976)       (88,334)
   Discount on preferred stock redemption                                    -           29            21             48
   Expense of issue                                                          -       (1,500)         (800)        (1,500)
   Lease obligations                                                       (86)         (80)         (252)          (234)
   Dividends
     Preferred stock                                                       (50)         (51)         (152)          (155)
     Common stock                                                      (10,095)     (10,153)      (30,185)       (30,459)
                                                                   ------------  -----------  ------------  -------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                    (15,553)      28,890       (65,554)           396
                                                                   ------------  -----------  ------------  -------------

CASH FLOWS FROM INVESTING ACTIVITIES
    Plant expenditures, including nuclear fuel                          (9,047)      (4,215)      (19,616)       (28,402)
    Investment in debt securities                                            -            -         8,528              -
                                                                   ------------  -----------  ------------  -------------
NET CASH USED IN INVESTING ACTIVITIES                                   (9,047)      (4,215)      (11,088)       (28,402)
                                                                   ------------  -----------  ------------  -------------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                               (1,643)      69,614       (18,673)        80,471
BALANCE AT BEGINNING OF PERIOD                                          14,972       17,251        32,002          6,394
                                                                   ------------  -----------  ------------  -------------
BALANCE AT END OF PERIOD                                               $13,329      $86,865       $13,329        $86,865
                                                                   ============  ===========  ============  =============

CASH PAID DURING THE PERIOD FOR:
   Interest (net of amount capitalized)                                $13,895      $19,819       $33,345        $40,578
                                                                   ============  ===========  ============  =============
   Income taxes                                                        $12,100       $9,000       $35,150        $26,773
                                                                   ============  ===========  ============  =============
</TABLE>

               The accompanying Notes to Consolidated Financial Statements
                    are an integral part of the financial statements.


                                     - 6 -
<PAGE>



                         THE UNITED ILLUMINATING COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                   (UNAUDITED)

     The consolidated  financial  statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange  Commission.  The statements  reflect
all  adjustments  that are, in the opinion of  management,  necessary  to a fair
statement of the results for the periods presented.  All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial  statements prepared in accordance with generally accepted
accounting  principles have been condensed or omitted pursuant to such rules and
regulations.  The Company believes that the disclosures are adequate to make the
information  presented not misleading.  These consolidated  financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year  ended  December  31,  1997.  Such notes are  supplemented  as
follows:

(A)  STATEMENT OF ACCOUNTING POLICIES

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

     The  weighted  average  AFUDC rate applied in the first nine months of 1998
and 1997 was 7.33% and 7.83%, respectively, on a before-tax basis.

CASH AND TEMPORARY CASH INVESTMENTS

     For cash flow  purposes,  the  Company  considers  all highly  liquid  debt
instruments  with a maturity of three  months or less at the date of purchase to
be cash and temporary cash investments.  The Company records  outstanding checks
as accounts payable until the checks have been honored by the banks.

NUCLEAR DECOMMISSIONING TRUSTS

     External  trust  funds  are   maintained  to  fund  the  estimated   future
decommissioning  costs of the nuclear  generating units in which the Company has
an  ownership  interest.  These  costs are  accrued as a charge to  depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current  basis.  The Company  paid $1.9 million in the first nine months of
each of 1998 and 1997 into the  decommissioning  trust funds for Seabrook Unit 1
and Millstone Unit 3. At September 30, 1998,  the Company's  shares of the trust
fund balances,  which  included  accumulated  earnings on the funds,  were $15.4
million and $6.2 million for Seabrook Unit 1 and Millstone Unit 3, respectively.
These fund  balances are included in "Other  Property and  Investments"  and the
accrued  decommissioning  obligation is included in "Noncurrent  Liabilities" on
the Company's Consolidated Balance Sheet.

INTEREST RATE AND FUEL PRICE MANAGEMENT

     The  Company   utilizes   interest  rate  and  fuel  oil  price  management
instruments to manage interest rate and fuel oil price risk.  Interest rate swap
agreements have been entered into that effectively convert the interest rates on
$225  million of variable  rate  borrowings  to fixed rate  borrowings.  Amounts
receivable  or payable  under these swap  agreements  are accrued and charged to
interest  expense.  The  Company  enters  into basic  fuel oil price  management
instruments  to help minimize fuel oil price risk by fixing the future price for
fuel oil  used  for  generation.  Amounts  receivable  or  payable  under  these
instruments are recognized in income when realized.

     As of September  30,  1998,  the Company had swap  agreements  for 1998 for
225,000 barrels of fuel oil at a weighted average price of $15.96 per barrel.


                                     - 7 -
<PAGE>


                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(B)  CAPITALIZATION

     (A) COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding  at September  30, 1998, of which  307,345  shares were  unallocated
shares held by the  Company's  Employee  Stock  Ownership  Plan ("ESOP") and not
recognized as outstanding for accounting purposes.

     In 1990, the Company's  Board of Directors and the  shareowners  approved a
stock  option plan for  officers  and key  employees  of the  Company.  The plan
provides  for the  awarding of options to  purchase up to 750,000  shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are  granted.  The  Connecticut  Department  of Public  Utility
Control  (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan.  The  exercise  price of each  option  cannot be less than the market
value of the stock on the date of the grant. Options to purchase 3,500 shares of
stock  at an  exercise  price  of $30 per  share,  7,800  shares  of stock at an
exercise  price of $39.5625 per share,  and 5,000 shares of stock at an exercise
price of $42.375  per share  have been  granted  by the Board of  Directors  and
remained outstanding at September 30, 1998. Options to purchase 14,299 shares of
stock  at an  exercise  price of $30 per  share,  54,500  shares  of stock at an
exercise  price of $30.75 per share,  4,000 shares of stock at an exercise price
of  $35.625  per  share,  and  25,999  shares of stock at an  exercise  price of
$39.5625 per share were exercised during the first nine months of 1998.

     The Company has entered  into an  arrangement  under which it loaned  $11.5
million to The United  Illuminating  Company ESOP. The trustee for the ESOP used
the  funds to  purchase  shares of the  Company's  common  stock in open  market
transactions.  The shares will be allocated to employees' ESOP accounts,  as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated  shares of the stock held by
the ESOP. As of September 30, 1998, 307,345 shares,  with a fair market value of
$16.1  million,  had been purchased by the ESOP and had not been committed to be
released or allocated to ESOP participants.

     (B) RETAINED EARNINGS RESTRICTION

     The  indenture  under which $166.2  million  principal  amount of Notes are
issued places  limitations  on the payment of cash dividends on common stock and
on the purchase or redemption of common stock.  Retained  earnings in the amount
of $114.3 million were free from such limitations at September 30, 1998.

     (C) PREFERRED STOCK

     In April 1998, the Company purchased at a discount on the open market,  and
canceled,  524 shares of its $100 par value 4.35%, Series A preferred stock. The
shares, having a par value of $52,400 were purchased for $31,440, creating a net
gain of $20,960.

     (E) LONG-TERM DEBT

     On January 13, 1998,  the Company  issued and sold $100  million  principal
amount of 6.25% four-year and eleven-month  Notes. The yield on the Notes, which
were issued at a discount,  is 6.30%;  and the Notes will mature on December 15,
2002.  The  proceeds  from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.

     In March 1998,  the Company  repurchased  $33,798,000  principal  amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.

                                     - 8 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     On June 8, 1998,  the Company  repaid a $50 million  Term Loan prior to its
August 29, 2000 due date.  On June 8, 1998,  the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.

(C) RATE-REGULATED REGULATORY PROCEEDINGS

     In April  1998,  Connecticut  enacted  Public Act 98-28 (the  Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility  industry.  The business of  generating  and  supplying  electricity  to
consumers will be opened to competition  and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of  delivering  electricity  will remain with the incumbent  franchised  utility
companies  (including the Company).  Beginning in 2000,  each retail consumer of
electricity in Connecticut  (excluding  consumers  served by municipal  electric
systems)  will be able to choose his,  her or its supplier of  electricity  from
among competing  licensed  suppliers,  for delivery over the wires system of the
franchised  electric utility  (Distribution  Company).  Commencing no later than
mid-1999,  Distribution  Companies  will be required  to separate on  consumers'
bills the  charge  for  electricity  generation  services  from the  charge  for
delivering the  electricity  and all other  charges.  On July 29, 1998, the DPUC
issued the first of what are  expected  to be several  orders  relative  to this
"unbundling" requirement.

     A  major  component  of  the  Restructuring  Act  is  the  collection,   by
Distribution  Companies,  of a "competitive  transition  assessment," a "systems
benefits  charge," an "energy  conservation and load management  program charge"
and  a  "renewable  energy  investment   charge."  The  competitive   transition
assessment and the systems benefits charge represent costs that either have been
or will be reasonably  incurred by  Distribution  Companies to meet their public
service obligations as electric companies, and that will likely not otherwise be
recoverable in a competitive  generation and supply market.  These costs include
above-market  long-term purchased power contract  obligations,  regulatory asset
recovery  and  above-market  investments  in power  plants  (so-called  stranded
costs). The costs of conservation  programs and renewable energy investments are
new  charges  established  in the  Restructuring  Act.  Beginning  in 2000,  the
Distribution Company must collect the competitive transition assessment, systems
benefits charge,  and conservation and load management and renewable  investment
charges from all Distribution  Company customers.  The Distribution Company will
also be required to offer a  "standard  offer" rate that is,  subject to certain
adjustments,  at least  10% below its fully  bundled  price for  electricity  at
December 31, 1996, as discussed below.  The standard offer is required,  subject
to certain  adjustments,  to be the total rate charged under the standard offer,
including  transmission and distribution  services,  the competitive  transition
assessment,  the systems benefits  charge,  the conservation and load management
program charge and the renewable energy charge.  The  Restructuring Act requires
that,  in order  for a  Distribution  Company  to  recover  any  stranded  costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess  proceeds  used to mitigate  its  recoverable  stranded
costs,  and the Company  must  attempt to divest its  ownership  interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval,  an "unbundling  plan" to
separate,  on or before  October 1, 1999,  all of its power plants that will not
have been sold prior to the DPUC's  approval of the unbundling  plan or will not
be sold prior to 2000.

      In May of 1998  the  Company  announced  that it would  commence  selling,
through a two-stage bidding process,  all of its non-nuclear  generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its  operating  fossil-fueled  generating  stations,  Bridgeport
Harbor  Station and New Haven Harbor  Station,  to  Wisvest-Connecticut,  LLC, a
single-purpose  subsidiary  of Wisvest  Corporation.  Wisvest  Corporation  is a
non-utility  subsidiary of Wisconsin Energy Corporation,  Milwaukee,  Wisconsin.
The sale price is $272  million in cash,  including  payment for some  non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent  upon the receipt of  approvals  from the DPUC,  the  Federal  Energy
Regulatory Commission,  and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.



                                     - 9 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

      The Company will  realize a book gain from the sale  proceeds net of taxes
and plant  investment.  However,  this gain  will be  offset by a  writedown  of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation  costs and other costs,  such that there will be no net income effect
of the sale.  Net cash proceeds from the sale are expected to be in the range of
$160-$165 million.  The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special  dividend or stock buyback,  and for
growth opportunities.

      The October 2, 1998 sale agreement for  Bridgeport  Harbor Station and New
Haven Harbor Station resulted from a bidding  process.  The Company's only other
fossil-fueled  generating station is its small deactivated  English Station,  in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from  refuse-to-energy  facilities  located in Bridgeport  and
Shelton,  Connecticut,  one long-term  contract for the purchase of power from a
small hydroelectric  generating station located in Derby,  Connecticut,  and the
Company's 5.45%  participating share in the Hydro-Quebec  transmission  intertie
facility  linking  New  England  and  Quebec,  Canada.  None of these  contracts
attracted an acceptable bid.

      On October 1, 1998,  in its  "unbundling  plan" filing with the DPUC under
the  Restructuring  Act,  the Company  stated that its  unbundling  plan for the
Company's nuclear generation ownership interests,  17.5% of Seabrook Station, in
New Hampshire,  and 3.685% of Millstone  Station Unit No. 3, in Connecticut,  is
divestiture  by the end of 2003 in accordance  with the  Restructuring  Act. The
divestiture  method has not yet been  determined.  In  anticipation  of ultimate
divestiture,  the Company  proposed  to  satisfy,  on a  functional  basis,  the
Restructuring Act's requirement that nuclear generating assets be separated from
its  transmission  and  distribution  assets.  This  would  be  accomplished  by
transferring  the nuclear  generating  assets into separate new divisions of the
Company,  using divisional  financial statements and accounting to segregate all
revenues,   expenses,  assets  and  liabilities  associated  with  each  nuclear
ownership interest.

      The  Company's  unbundling  plan also  proposes  to  facilitate  the clear
functional  separation  of the  Company's  ongoing  regulated  transmission  and
distribution operations and functions from all of its unregulated operations and
activities  by  undergoing  a  corporate  restructuring  into a holding  company
structure.  In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company  will be  converted  into a share of common  stock of the holding
company. In connection with the formation of the holding company structure,  all
of the Company's interests in all of its operating unregulated subsidiaries will
be  transferred  to the  holding  company  and,  to the extent  new  unregulated
businesses are  subsequently  acquired or commenced,  they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.

      Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power  supply  providers  after June 30, 2000.  The Company
will be required to offer  fully-bundled  service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power  adjustment  clause be added to its regulated  rates,  effective
July 1, 2000. This clause,  similar to and based on the purchased gas adjustment
clauses used by Connecticut's  natural gas local distribution  companies,  would
work in tandem with the Company's  procurement  of power supplies to assure that
standard offer  customers pay competitive  market rates for generation  services
even  though  they  do  not  choose  an  alternate  electricity  supplier.   The
Distribution  Company is also required  under the  Restructuring  Act to provide
back-up service to customers whose electric  supplier fails to provide  electric
generation  services for reasons  other than the  customers'  failure to pay for
such services.  The Restructuring  Act provides for the Distribution  Company to
recover its reasonable costs of providing this back-up service.



                                     - 10 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

      In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.

     On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible  for  providing a standard  offer  service to  customers  who do not
choose an alternate electricity supplier.  The standard offer prices,  including
the fully-bundled price of generation,  transmission and distribution  services,
the  competitive  transition  assessment,  the systems  benefits  charge and the
energy  conservation  and renewable  energy  assessments,  must be 10% below the
average  fully-bundled  prices in effect on December 31,  1996.  The Company has
already  delivered about 4.6% of this decrease  through rate reductions in 1997.
The 1997  through  2001 rate plan  agreed to between the DPUC and the Company in
1996  anticipated  sufficient  income  in 2000  to  accelerate  amortization  of
regulatory  assets  of about  $50  million,  equivalent  to  about 8% of  retail
revenues.  Substantially  all of this  accelerated  amortization  may have to be
eliminated  to  provide  for  the  additional  standard  offer  price  reduction
requirement and added costs imposed by the restructuring  legislation,  although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.

     The 1996  five-year  rate plan includes a provision that it may be reopened
and modified upon the enactment of electric industry  restructuring  legislation
in Connecticut. However, the Company is unable to predict, at this time, whether
or when or in what respects the 1996  five-year plan will be modified on account
of the enactment of the 1998 Restructuring Act.

(E)  SHORT-TERM CREDIT ARRANGEMENTS

     The Company has a revolving credit  agreement with a group of banks,  which
currently  extends to December 9, 1998. The Company  expects that this agreement
will be extended to December 1999.  The borrowing  limit of this facility is $75
million.  The  facility  permits  the Company to borrow  funds at a  fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
September  30,  1998,  the Company had $29.3  million of  short-term  borrowings
outstanding under this facility.

     On June 8, 1998,  the Company  borrowed $80 million  under a new  revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates.  The borrowing  limit of this  facility,
which extends to June 7, 1999, is $80 million.  The facility permits the Company
to borrow funds at a fluctuating  interest rate  determined by the prime lending
market in New York,  and also  permits  the  Company  to borrow  money for fixed
periods of time specified by the Company at fixed  interest rates  determined by
the Eurodollar  interbank market in London.  If a material adverse change in the
business,  operations,  affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries,  on a consolidated  basis, should
occur,  the banks may decline to lend additional money to the Company under this
revolving credit agreement,  although borrowings outstanding at the time of such
an occurrence  would not then become due and payable.  As of September 30, 1998,
the Company  had $80 million of  short-term  borrowings  outstanding  under this
facility.

     In  addition,  as of  September  30, 1998,  one of the  Company's  indirect
subsidiaries,  American  Payment  Systems,  Inc., had borrowings of $3.8 million
outstanding under a bank line of credit agreement.



                                     - 11 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<CAPTION>
                                                               Three Months Ended             Nine Months Ended
(F) INCOME  TAXES                                                 September 30,                 September 30,
                                                               1998          1997            1998          1997
                                                               ----          ----            ----          ----
                                                                     (000's)                       (000's)
<S>                                                           <C>           <C>             <C>           <C>    
Income tax expense consists of:

Income tax provisions:
  Current
             Federal                                          $18,331       $11,899         $37,957       $27,346
             State                                              5,335         3,802          11,044         8,789
                                                          ------------  ------------    ------------  ------------
                Total current                                  23,666        15,701          49,001        36,135
                                                          ------------  ------------    ------------  ------------
  Deferred
             Federal                                              184         4,602          (3,510)       (3,397)
             State                                                 87         1,007          (1,499)       (1,959)
                                                          ------------  ------------    ------------  ------------
                Total deferred                                    271         5,609          (5,009)       (5,356)
                                                          ------------  ------------    ------------  ------------

  Investment tax credits                                         (190)         (190)           (571)         (571)
                                                          ------------  ------------    ------------  ------------

     Total income tax expense                                 $23,747       $21,120         $43,421       $30,208
                                                          ============  ============    ============  ============

Income tax components charged as follows:
  Operating expenses                                          $24,448       $23,101         $47,128       $35,128
  Other income and deductions - net                              (701)       (1,981)         (3,707)       (4,920)
                                                          ------------  ------------    ------------  ------------

     Total income tax expense                                 $23,747       $21,120         $43,421       $30,208
                                                          ============  ============    ============  ============

The following table details the components
 of the deferred income taxes:
     Conservation and load management                         ($2,922)        ($931)        ($6,935)      ($5,022)
     Accelerated depreciation                                   1,535         1,459           4,603         4,378
     Tax depreciation on unrecoverable plant investment         1,212         1,232           3,636         3,695
     Seabrook sale/leaseback transaction                          808         1,486          (3,553)       (3,686)
     Pension benefits                                           1,020         1,983           2,003         2,092
     Postretirement benefits                                      (94)          187            (302)         (105)
     Fossil fuel decommissioning reserve                          (82)         (142)           (247)       (7,144)
     Unit overhaul and replacement power costs                   (361)         (287)            101         1,099
     Other - net                                                 (845)          622          (4,315)         (663)
                                                          ------------  ------------    ------------  ------------

Deferred income taxes - net                                      $271        $5,609         ($5,009)      ($5,356)
                                                          ============  ============    ============  ============
</TABLE>


                                     - 12 -
<PAGE>
<TABLE>
                                        THE UNITED ILLUMINATING COMPANY

                                NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION


<CAPTION>
                                                                Three Months Ended               Nine Months Ended
                                                                  September 30,                    September 30,
                                                                1998            1997            1998           1997
                                                                ----            ----            ----           ----
                                                                      (000's)                          (000's)

<S>                                                          <C>            <C>              <C>             <C> 
Operating Revenues
------------------

    Retail                                                    $185,982       $177,323         $481,749        $473,848
    Wholesale - capacity                                         2,661          2,483            8,974           7,265
              - energy                                           6,575         15,510           23,523          56,783
    Other                                                        3,383          1,247            6,621           2,766
                                                         --------------  -------------    -------------  --------------
         Total Operating Revenues                             $198,601       $196,563         $520,867        $540,662
                                                         ==============  =============    =============  ==============

Sales by Class(MWH's)
--------------------

    Retail
    Residential                                                553,475        505,070        1,462,288       1,415,844
    Commercial                                                 639,637        613,924        1,771,401       1,697,625
    Industrial                                                 312,088        305,492          870,705         867,082
    Other                                                       11,874         12,008           35,895          36,256
                                                         --------------  -------------    -------------  --------------
                                                             1,517,074      1,436,494        4,140,289       4,016,807
    Wholesale                                                  279,868        608,754        1,043,657       2,104,892
                                                         --------------  -------------    -------------  --------------
         Total Sales by Class                                1,796,942      2,045,248        5,183,946       6,121,699
                                                         ==============  =============    =============  ==============

Other Taxes
-----------

    Charged to:
    Operating:
       State gross earnings                                     $7,154         $6,777          $18,325         $18,005
       Local real estate and personal property                   5,316          5,451           16,217          17,742
       Payroll taxes                                             1,338          1,284            4,535           4,827
       Other                                                         6              0                6               0
                                                         --------------  -------------    -------------  --------------
                                                                13,814         13,512           39,083          40,574
    Nonoperating and other accounts                                105            111              398             343
                                                         --------------  -------------    -------------  --------------
         Total Other Taxes                                     $13,919        $13,623          $39,481         $40,917
                                                         ==============  =============    =============  ==============

Other Income and (Deductions) - net
-----------------------------------

    Interest income                                             $2,134           $458           $2,794          $1,384
    Equity earnings from Connecticut Yankee                        168            312              693           1,000
    Earnings (Loss) from subsidiary companies                      (85)           (75)          (4,613)           (970)
    Miscellaneous other income and (deductions) - net             (419)          (612)          (1,092)            175
                                                         --------------  -------------    -------------  --------------
         Total Other Income and (Deductions) - net              $1,798            $83          ($2,218)         $1,589
                                                         ==============  =============    =============  ==============

Other Interest Charges
----------------------

    Notes Payable                                                 $527           $749           $1,842          $1,949
    Other                                                        1,642            123            2,603             541
                                                         --------------  -------------    -------------  --------------
         Total Other Interest Charges                           $2,169           $872           $4,445          $2,490
                                                         ==============  =============    =============  ==============
</TABLE>

                                     - 13 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(K)  FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS

     The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for financing up to $37.5 million of fossil fuel purchases. Under this
agreement,  the financing  entity may acquire and/or store natural gas, coal and
fuel oil for sale to the  Company,  and the Company may  purchase  these  fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the  financing  entity for the direct  costs it has incurred in  purchasing  and
storing  the  fuel,  plus a charge  for  maintaining  an  inventory  of the fuel
determined  by  reference  to  the  fluctuating  interest  rate  on  thirty-day,
dealer-placed  commercial  paper in New York. The Company is obligated to insure
the  fuel  inventories  and  to  indemnify  the  financing  entity  against  all
liabilities,  taxes and other  expenses  incurred as a result of its  ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to November  1999. At September 30, 1998,  no fossil fuel  purchases  were being
financed under this agreement.

(L)  COMMITMENTS AND CONTINGENCIES

CAPITAL EXPENDITURE PROGRAM

     The Company's continuing capital expenditure program is presently estimated
at $149.6 million, excluding AFUDC, for 1998 through 2002.

NUCLEAR INSURANCE CONTINGENCIES

     The  Price-Anderson  Act, currently extended through August 1, 2002, limits
public liability  resulting from a single incident at a nuclear power plant. The
first $200 million of liability  coverage is provided by purchasing  the maximum
amount of commercially  available insurance.  Additional liability coverage will
be provided by an assessment of up to $75.5 million per incident, levied on each
of the  nuclear  units  licensed to operate in the United  States,  subject to a
maximum  assessment of $10 million per incident per nuclear unit in any year. In
addition,  if the sum of all public  liability  claims and legal costs resulting
from any nuclear  incident  exceeds the maximum amount of financial  protection,
each reactor  operator can be assessed an  additional  5% of $75.5  million,  or
$3.775 million.  The maximum assessment is adjusted at least every five years to
reflect  the impact of  inflation.  With  respect  to each of the three  nuclear
generating  units in which the Company  has an  interest,  the  Company  will be
obligated  to  pay  its  ownership  and/or  leasehold  share  of  any  statutory
assessment  resulting from a nuclear  incident at any nuclear  generating  unit.
Based on its interests in these nuclear  generating units, the Company estimates
its  maximum  liability  would be  $23.2  million  per  incident.  However,  any
assessment would be limited to $3.1 million per incident per year.

     The NRC requires each nuclear  generating unit to obtain property insurance
coverage  in a minimum  amount of $1.06  billion  and to  establish  a system of
prioritized  use of the insurance  proceeds in the event of a nuclear  incident.
The system  requires that the first $1.06 billion of insurance  proceeds be used
to  stabilize  the  nuclear  reactor to prevent any  significant  risk to public
health and safety and then for  decontamination  and  cleanup  operations.  Only
following completion of these tasks would the balance, if any, of the segregated
insurance  proceeds become available to the unit's owners. For each of the three
nuclear  generating  units in which the Company has an interest,  the Company is
required to pay its ownership  and/or  leasehold share of the cost of purchasing
such  insurance.  Although  each of these units has  purchased  $2.75 billion of
property  insurance  coverage,  representing  the limits of  coverage  currently
available  from  conventional  nuclear  insurance  pools,  the cost of a nuclear
incident could exceed available insurance proceeds.  Under those  circumstances,
the nuclear  insurance  pools that  provide this  coverage may levy  assessments
against the insured owner companies if pool losses exceed the accumulated  funds
available to the pool.  The maximum  potential  assessments  against the Company
with respect to losses occurring  during current policy years are  approximately
$5.0 million.



                                     - 14 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

OTHER COMMITMENTS AND CONTINGENCIES

                               CONNECTICUT YANKEE

     On December  4, 1996,  the Board of  Directors  of the  Connecticut  Yankee
Atomic  Power  Company  (Connecticut  Yankee)  voted  unanimously  to retire the
Connecticut  Yankee nuclear plant (the Connecticut  Yankee Unit) from commercial
operation.  The Company has a 9.5% stock ownership  share in Connecticut  Yankee
and had relied on the  Connecticut  Yankee  Unit for  approximately  3.7% of the
Company's 1995 total  generating  resources.  The power purchase  contract under
which the Company has purchased its 9.5%  entitlement to the Connecticut  Yankee
Unit's power  output  permits  Connecticut  Yankee to recover 9.5% of all of its
costs from UI. In December of 1996,  Connecticut  Yankee  filed  decommissioning
cost  estimates and  amendments to the power  contracts with its owners with the
Federal Energy Regulatory Commission (FERC). Based on regulatory precedent, this
filing seeks  confirmation that Connecticut Yankee will continue to collect from
its  owners  its  decommissioning  costs,  the  unrecovered  investment  in  the
Connecticut  Yankee Unit and other costs associated with the permanent  shutdown
of the  Connecticut  Yankee Unit. UI expects that it will continue to be allowed
to  recover  its share of all  FERC-approved  costs from its  customers  through
retail rates. The Company's estimate of its remaining share of costs,  including
decommissioning,  less return of  investment  (approximately  $9.8  million) and
return on  investment  (approximately  $5.6  million) at September  30, 1998, is
approximately $36.9 million.  This estimate,  which is subject to ongoing review
and  revision,  has been  recorded by the Company as a  regulatory  asset and an
obligation on the Consolidated Balance Sheet.

     On August 31,  1998,  a FERC  Administrative  Law Judge  (ALJ)  released an
initial  decision  regarding  Connecticut  Yankee's  December  1996 filing.  The
initial  decision  contains  provisions that would allow  Connecticut  Yankee to
recover,  through the power  contracts  with its owners,  the balance of its net
unamortized  investment  in the  Connecticut  Yankee  Unit,  but would  disallow
recovery of a portion of the return on  Connecticut  Yankee's  investment in the
unit. The ALJ's decision also states that  decommissioning  cost  collections by
Connecticut Yankee, through the power contracts,  should continue to be based on
a  previously-approved  estimate  until a new, more  reliable  estimate has been
prepared and tested.  During October of 1998,  Connecticut Yankee and its owners
filed briefs  setting forth  exceptions to the ALJ's initial  decision.  If this
initial decision is upheld by the FERC,  Connecticut Yankee could be required to
write off a portion of the regulatory asset on its Balance Sheet associated with
the  retirement  of the  Connecticut  Yankee Unit. In this event,  however,  the
Company  would not be  required to record any  write-off  on account of its 9.5%
ownership  share in  Connecticut  Yankee,  because the Company has  recorded its
regulatory asset  associated with the retirement of the Connecticut  Yankee Unit
net of any return on investment.  The Company cannot predict,  at this time, the
outcome of the FERC  proceeding.  However,  the Company will continue to support
Connecticut Yankee's efforts to contest the ALJ's initial decision.

                                  HYDRO-QUEBEC

     The Company is a  participant  in the  Hydro-Quebec  transmission  intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became  operational  in 1986 and in which the Company has a 5.45%  participating
share, has a 690 megawatt  equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie  from 690  megawatts  to a maximum of 2000  megawatts in 1991. A
ten-year  Firm  Energy  Contract,  which  provides  for the  sale  of 7  million
megawatt-hours  per year by Hydro-Quebec to the New England  participants in the
Phase II facility,  became effective on July 1, 1991. Additionally,  the Company
is  obligated  to furnish a guarantee  for its  participating  share of the debt
financing  for the Phase II facility.  As of September  30, 1998,  the Company's
guarantee liability for this debt was approximately $7.0 million.



                                     - 15 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

                                 PROPERTY TAXES

     The City of New Haven (the City) and the Company are  involved in a dispute
over the  amount  of  personal  property  taxes  owed to the City for tax  years
beginning with  1991-1992.  On May 8, 1998,  the City and the Company  reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992  through 1997-1998 and the
Company's  personal  property tax  assessments  for the tax year  1998-1999  and
subsequent years.  Under the terms of this settlement,  the Company will pay the
City $14.025  million,  subject to Superior Court approval of the settlement and
conditioned on the Company receiving  authorization from the DPUC to recover the
settlement  amount  from its retail  customers.  The DPUC  denied the  Company's
initial  application for such authorization and the City has agreed to extend to
November  30,  1998  the  time  period  for  satisfying  this  condition  of the
settlement in return for a payment by the Company of $6 million,  which has been
recognized  as a  prepayment  of  property  taxes.  The  Company  filed a second
application  with the DPUC on July 9,  1998.  If the DPUC  authorization  is not
forthcoming, the $6 million payment will be applied to future tax bills.

             SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS

     The  Company  has  estimated  that the total  cost of  decontaminating  and
demolishing  its Steel Point  Station  and  completing  requisite  environmental
remediation  of  the  site  will  be  approximately   $11.3  million,  of  which
approximately  $8.3 million had been incurred as of September 30, 1998, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate  decision,  beginning  January 1, 1993,  the
Company  has  been  recovering  through  retail  rates  $1.075  million  of  the
remediation costs per year. The remediation  costs,  property value and recovery
from  customers  will be subject to true-up in the  Company's  next  retail rate
proceeding  based on actual  remediation  costs and actual gain on the Company's
disposition of the property.

     The Company is  presently  remediating  an area of PCB  contamination  at a
site,  bordering  the  Mill  River  in New  Haven,  that  contains  transmission
facilities  and  the   deactivated   English  Station   generation   facilities.
Remediation costs,  including the repair and/or replacement of approximately 560
linear  feet of sheet  piling,  are  currently  estimated  at $7.5  million.  In
addition,  the  Company is  planning  to repair  and/or  replace  the  remaining
deteriorated  sheet  piling  bordering  the  English  Station  property,  at  an
additional estimated cost of $10 million.

     As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company  has  contracted  to sell its  Bridgeport  Harbor  Station and New Haven
Harbor  Station  generating  plants in compliance  with  Connecticut's  electric
utility industry restructuring legislation.  Environmental assessments performed
in  connection  with the  marketing of these plants  indicate  that  substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable  Connecticut  minimum standards following their sale.
The proposed  purchaser  of the plants has agreed to  undertake  and pay for the
major portion of this remediation.  However, the Company will be responsible for
remediation of the portions of the plant sites that will be retained by it.

(M)  NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING

     New   Hampshire   has   enacted  a  law   requiring   the   creation  of  a
government-managed  fund to finance the  decommissioning  of nuclear  generating
units  in  that  state.  The New  Hampshire  Nuclear  Decommissioning  Financing
Committee  (NDFC)  has  established  $473  million  (in  1998  dollars)  as  the
decommissioning  cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $83 million. This estimate assumes the prompt removal and
dismantling  of the unit at the end of its estimated  36-year  energy  producing
life.  Monthly  decommissioning  payments  are being  made to the  state-managed
decommissioning  trust fund.  UI's share of the  decommissioning  payments  made
during the first nine months of 1998 was  $1,570,000.  UI's share of the fund at
September 30, 1998 was approximately $15.4 million.


                                     - 16 -
<PAGE>
 
                        THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     Connecticut has enacted a law requiring the operators of nuclear generating
units  to file  periodically  with  the  DPUC  their  plans  for  financing  the
decommissioning  of the units in that state.  The current  decommissioning  cost
estimate for Millstone  Unit 3 is $557 million (in 1998  dollars),  of which the
Company's share would be  approximately  $21 million.  This estimate assumes the
prompt removal and  dismantling of the unit at the end of its estimated  40-year
energy producing life.  Monthly  decommissioning  payments,  based on these cost
estimates,  are being made to a decommissioning  trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during the first  nine  months of 1998 was  $365,000.  UI's share of the fund at
September 30, 1998 was approximately $6.2 million.  The current  decommissioning
cost estimate for the Connecticut  Yankee Unit,  assuming the prompt removal and
dismantling of the unit commencing in 1997, is $456 million, of which UI's share
would be $43  million.  Through  September  30,  1998,  $53.8  million  has been
expended for  decommissioning.  The projected remaining  decommissioning cost is
$402.2 million, of which UI's share would be $38.2 million.  The decommissioning
trust  fund for the  Connecticut  Yankee  Unit is also  managed  by NU.  For the
Company's 9.5% equity ownership in Connecticut Yankee,  decommissioning costs of
$1,767,000  were  funded by UI during  the first nine  months of 1998,  and UI's
share of the fund at September 30, 1998 was $24.0 million.



                                     - 17 -
<PAGE>


ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS.


                     MAJOR INFLUENCES ON FINANCIAL CONDITION

     The  Company's  financial  condition  will  continue to be dependent on the
level of its retail and  wholesale  sales and the  Company's  ability to control
expenses.  The two  primary  factors  that  affect  sales  volume  are  economic
conditions  and  weather.  Annual  growth  in total  operation  and  maintenance
expense,  excluding  one-time items and  cogeneration  capacity  purchases,  has
averaged  less than 1.5% during the past 5 years.  The Company hopes to continue
to restrict this average to less than the rate of inflation in future years (see
"Looking Forward").

     The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions,  interest rates, the level of the Company's income and cash
flow,  and  legislative  and  regulatory  developments,  including  the  cost of
compliance with increasingly stringent environmental legislation and regulations
and competition within the electric utility industry.

      On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) completed a financial and operational review of the Company and ordered a
five-year  incentive  regulation  plan for the years 1997 through 2001. The DPUC
did not change the  existing  retail base rates  charged to  customers;  but its
order increased  amortization of the Company's  conservation and load management
program   investments   during  1997-1998,   and  accelerated  the  recovery  of
unspecified  regulatory  assets during  1999-2001 if the Company's  common stock
equity return on utility  investment exceeds 10.5% after recording the increased
conservation and load management amortization.  The order also reduced the level
of  conservation  adjustment  mechanism  revenues in retail  prices,  provided a
reduction in customer prices through a surcredit in each of the five plan years,
and accepted the  Company's  proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%.  Earnings above 11.5%, on an annual basis, are to be
utilized  one-third  for  customer  price  reductions,   one-third  to  increase
amortization  of regulatory  assets,  and one-third  retained as earnings.  As a
result of the DPUC's  order,  customer  prices were  required to be reduced,  on
average,  by 3% in 1997 compared to 1996. Retail revenues actually  decreased by
approximately  $30 million,  or 4.6%, in 1997 due to customer price  reductions.
Also as a result of the order,  customer prices are required to be reduced by an
additional  1% in 2000,  and another 1% in 2001,  compared  to 1996.  The DPUC's
order has been reopened in 1998, in accordance  with its terms, to determine the
regulatory  assets to be subjected  to  accelerated  recovery in 1999,  2000 and
2001.  The DPUC has not yet determined the assets to be subjected to accelerated
recovery in 1999;  but a decision in this regard is expected to be issued before
the end of 1998.  The DPUC has decided  that it will not  determine  in 1998 the
assets to be  subjected  to  recovery  after  1999.  The DPUC's  1996 order also
includes a provision  that it may be reopened and modified upon the enactment of
electric utility restructuring  legislation in Connecticut and, as a consequence
of the restructuring legislation described below, the 1996 order may be reopened
and modified.  However,  the Company is unable to predict, at this time, whether
or when or in what  respects  the 1996 order will be modified on account of this
legislation.

     In April  1998,  Connecticut  enacted  Public Act 98-28 (the  Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility  industry.  The business of  generating  and  supplying  electricity  to
consumers will be opened to competition  and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of  delivering  electricity  will remain with the incumbent  franchised  utility
companies  (including the Company).  Beginning in 2000,  each retail consumer of
electricity in Connecticut  (excluding  consumers  served by municipal  electric
systems)  will be able to choose his,  her or its supplier of  electricity  from
among competing  licensed  suppliers,  for delivery over the wires system of the
franchised  electric utility  (Distribution  Company).  Commencing no later than
mid-1999,  Distribution  Companies  will be required  to separate on  consumers'
bills the  charge  for  electricity  generation  services  from the  charge  for
delivering the  electricity  and all other  charges.  On July 29, 1998, the DPUC
issued the first of what are  expected  to be several  orders  relative  to this
"unbundling" requirement.

     A  major  component  of  the  Restructuring  Act  is  the  collection,   by
Distribution  Companies,  of a "competitive  transition  assessment," a "systems
benefits  charge," an "energy  conservation and load management  program charge"


                                     - 18 -
<PAGE>

and  a  "renewable  energy  investment   charge."  The  competitive   transition
assessment and the systems benefits charge represent costs that either have been
or will be reasonably  incurred by  Distribution  Companies to meet their public
service obligations as electric companies, and that will likely not otherwise be
recoverable in a competitive  generation and supply market.  These costs include
above-market  long-term purchased power contract  obligations,  regulatory asset
recovery  and  above-market  investments  in power  plants  (so-called  stranded
costs). The costs of conservation  programs and renewable energy investments are
new  charges  established  in the  Restructuring  Act.  Beginning  in 2000,  the
Distribution Company must collect the competitive transition assessment, systems
benefits charge,  and conservation and load management and renewable  investment
charges from all Distribution  Company customers.  The Distribution Company will
also be required to offer a  "standard  offer" rate that is,  subject to certain
adjustments,  at least  10% below its fully  bundled  price for  electricity  at
December 31, 1996, as discussed below.  The standard offer is required,  subject
to certain  adjustments,  to be the total rate charged under the standard offer,
including  transmission and distribution  services,  the competitive  transition
assessment,  the systems benefits  charge,  the conservation and load management
program charge and the renewable energy charge.  The  Restructuring Act requires
that,  in order  for a  Distribution  Company  to  recover  any  stranded  costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess  proceeds  used to mitigate  its  recoverable  stranded
costs,  and the Company  must  attempt to divest its  ownership  interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval,  an "unbundling  plan" to
separate,  on or before  October 1, 1999,  all of its power plants that will not
have been sold prior to the DPUC's  approval of the unbundling  plan or will not
be sold prior to 2000.

      In May of 1998  the  Company  announced  that it would  commence  selling,
through a two-stage bidding process,  all of its non-nuclear  generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its  operating  fossil-fueled  generating  stations,  Bridgeport
Harbor  Station and New Haven Harbor  Station,  to  Wisvest-Connecticut,  LLC, a
single-purpose  subsidiary  of Wisvest  Corporation.  Wisvest  Corporation  is a
non-utility  subsidiary of Wisconsin Energy Corporation,  Milwaukee,  Wisconsin.
The sale price is $272  million in cash,  including  payment for some  non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent  upon the receipt of  approvals  from the DPUC,  the  Federal  Energy
Regulatory Commission,  and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.

      The Company will  realize a book gain from the sale  proceeds net of taxes
and plant  investment.  However,  this gain  will be  offset by a  writedown  of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation  costs and other costs,  such that there will be no net income effect
of the sale.  Net cash proceeds from the sale are expected to be in the range of
$160-$165 million.  The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special  dividend or stock buyback,  and for
growth opportunities.

      The October 2, 1998 sale agreement for  Bridgeport  Harbor Station and New
Haven Harbor Station resulted from a bidding  process.  The Company's only other
fossil-fueled  generating station is its small deactivated  English Station,  in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from  refuse-to-energy  facilities  located in Bridgeport  and
Shelton,  Connecticut,  one long-term  contract for the purchase of power from a
small hydroelectric  generating station located in Derby,  Connecticut,  and the
Company's 5.45%  participating share in the Hydro-Quebec  transmission  intertie
facility  linking  New  England  and  Quebec,  Canada.  None of these  contracts
attracted an acceptable bid.

      On October 1, 1998,  in its  "unbundling  plan" filing with the DPUC under
the  Restructuring  Act,  the Company  stated that its  unbundling  plan for the
Company's nuclear generation ownership interests,  17.5% of Seabrook Station, in
New Hampshire,  and 3.685% of Millstone  Station Unit No. 3, in Connecticut,  is
divestiture  by the end of 2003 in accordance  with the  Restructuring  Act. The
divestiture  method has not yet been  determined.  In  anticipation  of ultimate
divestiture,  the Company  proposed  to  satisfy,  on a  functional  basis,  the
Restructuring Act's requirement that nuclear generating assets be separated from
its  transmission  and  distribution  assets.  This  would  be  accomplished  by
transferring  the nuclear  generating  assets into separate new divisions of the
Company,  using divisional  financial statements and accounting to segregate all
revenues,   expenses,  assets  and  liabilities  associated  with  each  nuclear
ownership interest.



                                     - 19 -
<PAGE>

      The  Company's  unbundling  plan also  proposes  to  facilitate  the clear
functional  separation  of the  Company's  ongoing  regulated  transmission  and
distribution operations and functions from all of its unregulated operations and
activities  by  undergoing  a  corporate  restructuring  into a holding  company
structure.  In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company  will be  converted  into a share of common  stock of the holding
company. In connection with the formation of the holding company structure,  all
of the Company's interests in all of its operating unregulated subsidiaries will
be  transferred  to the  holding  company  and,  to the extent  new  unregulated
businesses are  subsequently  acquired or commenced,  they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.

      Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power  supply  providers  after June 30, 2000.  The Company
will be required to offer  fully-bundled  service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power  adjustment  clause be added to its regulated  rates,  effective
July 1, 2000. This clause,  similar to and based on the purchased gas adjustment
clauses used by Connecticut's  natural gas local distribution  companies,  would
work in tandem with the Company's  procurement  of power supplies to assure that
standard offer  customers pay competitive  market rates for generation  services
even  though  they  do  not  choose  an  alternate  electricity  supplier.   The
Distribution  Company is also required  under the  Restructuring  Act to provide
back-up service to customers whose electric  supplier fails to provide  electric
generation  services for reasons  other than the  customers'  failure to pay for
such services.  The Restructuring  Act provides for the Distribution  Company to
recover its reasonable costs of providing this back-up service.

      In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.

     On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible  for  providing a standard  offer  service to  customers  who do not
choose an alternate electricity supplier.  The standard offer prices,  including
the fully-bundled price of generation,  transmission and distribution  services,
the  competitive  transition  assessment,  the systems  benefits  charge and the
energy  conservation  and renewable  energy  assessments,  must be 10% below the
average  fully-bundled  prices in effect on December 31,  1996.  The Company has
already  delivered about 4.6% of this decrease  through rate reductions in 1997.
The  DPUC's  1996  order  anticipated  sufficient  income in 2000 to  accelerate
amortization of regulatory  assets of about $50 million,  equivalent to about 8%
of retail revenues.  Substantially all of this accelerated amortization may have
to be eliminated to provide for the additional  standard  offer price  reduction
requirement and added costs imposed by the restructuring  legislation,  although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.

     Currently,  the Company's  electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities,  are subject to certain accounting  standards (Statement of Financial
Accounting  Standards  No. 71,  "Accounting  for the Effects of Certain Types of
Regulation"  (SFAS  No.  71)) that are not  applicable  to other  businesses  in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income  statement  impact of certain  costs  that are  expected  to be
recovered in future regulated  service rates and to establish  regulatory assets
on its balance sheet for such costs.  The effects of  competition or a change in
the cost-based  regulatory  structure could cause the operations of the Company,
or a portion of its assets or  operations,  to cease  meeting the  criteria  for
application of these accounting rules.  While the Company expects to continue to
meet these criteria in the foreseeable  future, if the Company,  or a portion of
its assets or  operations,  were to cease  meeting  these  criteria,  accounting
standards  for  businesses  in general  would become  applicable  and  immediate
recognition of any previously  deferred  costs,  or a portion of deferred costs,
would be required in the year in which the  criteria  are no longer met, if such
deferred  costs  are  not  recoverable  in that  portion  of the  business  that
continues  to meet the  criteria  for the  application  of SFAS No.  71. If this
change in accounting were to occur, it would have a


                                     - 20 -
<PAGE>

material adverse effect on the Company's  earnings and retained earnings in that
year and could have a material adverse effect on the Company's ongoing financial
condition as well.



                                     - 21 -
<PAGE>



                           CAPITAL EXPENDITURE PROGRAM

     The Company's  1998-2002 capital expenditure  program,  excluding allowance
for  funds  used  during   construction   (AFUDC)  and  its  effect  on  certain
capital-related items, is presently budgeted as follows:

<TABLE>
<CAPTION>
                                         1998          1999         2000        2001         2002         TOTAL
                                         ----          ----         ----        ----         ----         -----
                                                                         (000's)
<S>                                   <C>            <C>          <C>         <C>          <C>          <C>    
Generation (1)                           $7,169       $5,553       $4,675      $1,752       $2,771       $21,920
Distribution and Transmission            13,184       16,434       18,557      14,441       14,371        76,987
Other                                     9,640        8,036        2,410       2,009        2,655        24,750
                                         ------       ------       ------      ------       ------       -------
Subtotal                                 29,993       30,023       25,642      18,202       19,797       123,657

Nuclear Fuel                              5,947        2,397        8,569       6,160        2,892        25,965
                                         ------       ------       ------      ------       ------       -------

  Total Expenditures                    $35,940      $32,420      $34,211     $24,362      $22,689      $149,622
                                        =======      =======      =======     =======      =======      ========

Rate Base and Other Selected Data:
---------------------------------
Depreciation
  Book Plant (1)                         57,442       48,803       46,815      47,403       47,797
  Conservation Assets                    10,309        5,390            0           0            0
  Decommissioning                         2,778        2,781        2,892       3,007        3,128
Additional Required
 Amortization (pre-tax)(2)
  Conservation Assets                    13,000            0            0           0            0
  Other Regulatory Assets                     0       20,300            0           0            0
Amortization of Deferred
 Return on Seabrook Unit 1
 Phase-In (after-tax)                    12,586       12,586            0           0            0

Estimated Rate Base
 (end of period)                      1,102,455
</TABLE>

(1)  Recently enacted legislation to restructure  Connecticut's electric utility
     industry  requires  the  Company  to  divest  itself  of its  fossil-fueled
     generating  plants prior to January 1, 2000 and to attempt to divest itself
     of its  ownership  interests in  nuclear-fueled  generating  units prior to
     January  1,  2004.  This  forecast  reflects  a  proposed   divestiture  of
     fossil-fueled  generation plants on April 1, 1999.  Remaining Generation is
     projected capital  expenditures for nuclear  generation,  excluding nuclear
     fuel.

(2)  Additional   amortization   of  pre-1997   conservation   costs  and  other
     unspecified  regulatory  assets, as ordered by the DPUC in its December 31,
     1996 Order,  provided  that,  as expected,  common equity return on utility
     investment exceeds 10.5% after recording the additional amortization.

                                     - 22 -
<PAGE>

                         LIQUIDITY AND CAPITAL RESOURCES

     At September 30, 1998,  the Company had $13.3 million of cash and temporary
cash  investments,  a decrease of $18.7 million from the balance at December 31,
1997. The components of this  decrease,  which are detailed in the  Consolidated
Statement of Cash Flows, are summarized as follows:

                                                                    (Millions)
                                                                     --------

       Balance, December 31, 1997                                     $ 32.0
                                                                       -----

       Net cash provided by operating activities                        57.9

       Net cash provided by (used in) financing activities:
       -   Financing activities, excluding dividend payments           (35.2)
       -   Dividend payments                                           (30.3)

       Net cash provided by investing activities, excludin
         investment in plant                                             8.5

       Cash invested in plant, including nuclear fuel                  (19.6)
                                                                       ----- 

             Net Change in Cash                                        (18.7)
                                                                       -----

       Balance,  September 30, 1998                                    $13.3
                                                                       =====


     The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>

                                                                 1998       1999       2000       2001       2002
                                                                 ----       ----       ----       ----       ----
                                                                                     (millions)
<S>                                                              <C>         <C>       <C>        <C>        <C>
Cash on Hand - Beginning of Year                                 $ 32.0      $ -       $ -        $ -        $ -
Internally Generated Funds less Dividends                         112.0      144.0      67.0       67.0       69.0
Net Proceeds from Sale of Fossil Generation Plant                   -        160.0        -          -         -
                                                                  -----      -----      ----       ----      -----
         Subtotal                                                 144.0      304.0      67.0       67.0       69.0

Less:
Capital Expenditures                                               35.9       32.4      34.2       24.4       22.7
                                                                  -----      -----      ----       ----      -----

Cash Available to pay Debt Maturities and Redemptions             108.1      271.6      32.8       42.6       46.3

Less:
Maturities and Mandatory Redemptions                              104.2       69.6       0.4        0.3      100.3
Optional Redemptions                                              113.8      145.0      50.0         -         -
                                                                  -----      -----      ----       ----      ----- 

External Financing Requirements (Surplus)                        $109.9     $(57.0)    $17.6     $(42.3)     $54.0
                                                                  =====      =====      ====      =====       ====
</TABLE>

Note:Internally  Generated  Funds  less  Dividends,   Capital  Expenditures  and
     External Financing Requirements are estimates based on current earnings and
     cash flow  projections,  including the  implementation  of the  legislative
     mandate to achieve a 10% price  reduction from 1996 average price levels by
     the year 2000.  Recently enacted  legislation to restructure  Connecticut's
     electric  utility industry will require the Company to divest itself of its
     fossil-fueled  generating plants prior to January 1, 2000 and to attempt to
     divest itself of its ownership interests in nuclear-fueled generating units
     prior to  January  1,  2004.  This  forecast  reflects  the  estimated  net
     after-tax proceeds (approximately $160 million) from a proposed divestiture
     of fossil-fueled generation plants on April 1, 1999. All of these estimates
     are  subject to change  due to future  events  and  conditions  that may be
     substantially different from those used in developing the projections.

                                     - 23 -
<PAGE>

     All of the Company's  capital  requirements that exceed available cash will
have  to be  provided  by  external  financing.  Although  the  Company  has  no
commitment to provide such financing from any source of funds,  other than a $75
million   revolving  credit  agreement  and  an  $80  million  revolving  credit
agreement,  described  below,  the  Company  expects to be able to  satisfy  its
external  financing needs by issuing  additional  short-term and long-term debt,
and by issuing  preferred  stock or common stock,  if  necessary.  The continued
availability  of these  methods of financing  will be dependent on many factors,
including  conditions in the securities markets,  economic  conditions,  and the
level of the Company's  income and cash flow.  On October 19, 1998,  the Company
filed with the  Connecticut  Department of Public Utility Control an application
for  approval  of the  issuance  and  sale  of a  maximum  of  $100  million  of
medium-term Notes. The Company proposes to use the net proceeds of this proposed
financing  to repay Notes in the  principal  amount of $66.2  million  that will
mature in January of 1999, to repay short-term bank borrowings,  and for general
corporate purposes.

     The Company has a revolving credit  agreement with a group of banks,  which
currently  extends to December 9, 1998. The Company  expects that this agreement
will be extended to December 1999.  The borrowing  limit of this facility is $75
million.  The  facility  permits  the Company to borrow  funds at a  fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
September  30,  1998,  the Company had $29.3  million of  short-term  borrowings
outstanding under this facility.

     On June 8, 1998,  the Company  borrowed $80 million  under a new  revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates.  The borrowing  limit of this  facility,
which extends to June 7, 1999, is $80 million.  The facility permits the Company
to borrow funds at a fluctuating  interest rate  determined by the prime lending
market in New York,  and also  permits  the  Company  to borrow  money for fixed
periods of time specified by the Company at fixed  interest rates  determined by
the Eurodollar  interbank market in London.  If a material adverse change in the
business,  operations,  affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries,  on a consolidated  basis, should
occur,  the banks may decline to lend additional money to the Company under this
revolving credit agreement,  although borrowings outstanding at the time of such
an occurrence  would not then become due and payable.  As of September 30, 1998,
the Company  had $80 million of  short-term  borrowings  outstanding  under this
facility.

                              SUBSIDIARY OPERATIONS

     UI has one wholly-owned  subsidiary,  United  Resources,  Inc. (URI),  that
serves as the parent  corporation for several  unregulated  businesses,  each of
which is incorporated  separately to participate in business  ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers.

     URI  has  four  wholly-owned  subsidiaries.  The  largest  URI  subsidiary,
American  Payment  Systems,  Inc.,  manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional  buildings,  and is participating
in the  development of district  heating and cooling  facilities in the downtown
New  Haven  area,   including   the  energy  center  for  an  office  tower  and
participation  as a 52% partner in the energy  center for a city hall and office
tower  complex.  A  third  URI  subsidiary,   Precision  Power,  Inc.,  provides
power-related  equipment  and  services to the owners of  commercial  buildings,
government buildings and industrial facilities. URI's fourth subsidiary,  United
Bridgeport  Energy,  Inc., is  participating  in a merchant  wholesale  electric
generating  facility being  constructed on land leased from UI at its Bridgeport
Harbor Station generating plant.



                                     - 24 -
<PAGE>

                              RESULTS OF OPERATIONS

THIRD QUARTER OF 1998 VS. THIRD QUARTER OF 1997
-----------------------------------------------

     Earnings  for the third  quarter of 1998 were $26.2  million,  or $1.87 per
share (on both a basic and diluted basis),  up $2.8 million,  or $.19 per share,
from the  third  quarter  of  1997.  Excluding  one-time  items,  earnings  from
operations  were $24.9 million,  or $1.78 per share,  up $.15 per share from the
third quarter of 1997. The one-time items were:

                    One-time Items                                     EPS
--------------------------------------------------------------------------------
   1997 Quarter 3   Gain from subleasing office space                $ .05
--------------------------------------------------------------------------------
   1998 Quarter 3   Refund of prior period transmission charges,
                    with interest                                    $ .09
--------------------------------------------------------------------------------

     Retail  operating  revenues  increased  by about $8.7  million in the third
quarter of 1998 compared to the third quarter of 1997,  offset by a $4.8 million
increase in cost of  production  (retail  fuel and energy  expense)  and a small
increase in  revenue-based  taxes,  for a retail sales  margin  increase of $3.5
million. The principal components of the retail sales margin change include:

                                                                    $ millions
--------------------------------------------------------------------------------
     Revenues from:
--------------------------------------------------------------------------------
        Sharing: year-to-date estimate for 1998 (see Note A)            (3.0)
--------------------------------------------------------------------------------
        Other price changes                                              1.6
--------------------------------------------------------------------------------
        Estimate of "real" retail sales growth, up 4.0%                  6.0
--------------------------------------------------------------------------------
        Estimate of weather effect on retail sales, up 2.8%              4.9
--------------------------------------------------------------------------------
        Sales decrease from Yale University cogeneration, (1.1)%        (0.9)
--------------------------------------------------------------------------------
     Fuel expense from:
--------------------------------------------------------------------------------
        Sales increase                                                  (2.1)
--------------------------------------------------------------------------------
        Unscheduled outage at Bridgeport Unit 3 (see Note B)            (2.5)
--------------------------------------------------------------------------------
        Fossil fuel price and other                                     (0.1)
--------------------------------------------------------------------------------
     Revenue-based taxes                                                (0.4)
--------------------------------------------------------------------------------

         Note A: On December  31, 1996,  the  Connecticut  Department  of Public
         Utility  Control (DPUC) issued an order (the Order) that  implemented a
         five-year  regulatory  framework that would reduce the Company's retail
         prices and  accelerate  the  recovery of certain  "regulatory  assets,"
         beginning with deferred  conservation  costs.  The Company is operating
         under the terms of this order in 1998.  The Order  requires a "sharing"
         of income if regulated return on equity exceeds 11.5 percent.  (See the
         discussion on the "Five-year  rate plan" in the Looking Forward section
         for information  regarding the sharing mechanism.) The Company's latest
         estimate  for 1998 results  indicates  that it will be likely that some
         sharing  will be  required in 1998,  and the Company  accrued a revenue
         reduction of $3.0 million ($1.7 million after-tax) in the third quarter
         of 1998.

         Note B:  Saltwater  contamination  caused a shutdown of the  Bridgeport
         Harbor Unit 3  generating  unit on May 22, 1998.  The unit  returned to
         full service on August 23, 1998.

     Net wholesale  margin  (wholesale  revenue less wholesale  expense) changed
only  slightly in the third  quarter of 1998  compared  to the third  quarter of
1997.  Other  operating  revenues,  which include  NEPOOL  related  transmission
revenues, increased by $2.2 million.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  increased by $0.1 million in the third  quarter of 1998 compared to the
third  quarter  of 1997.  The  principal  components  of these  expense  changes
include:

                                     - 25 -
<PAGE>

                                                                     $ millions
 -------------------------------------------------------------------------------
     Capacity:
--------------------------------------------------------------------------------
        Connecticut Yankee Unit, cogeneration and other purchases        0.8
--------------------------------------------------------------------------------
     Other O&M:
--------------------------------------------------------------------------------
        Seabrook Unit                                                   (1.0)
--------------------------------------------------------------------------------
        Millstone Unit 3                                                (1.6)
--------------------------------------------------------------------------------
        Fossil generation unit overhauls and outage costs                2.7
--------------------------------------------------------------------------------
        Pension investment performance and changes to actuarial
           assumptions and methodologies                                (1.2)
--------------------------------------------------------------------------------
        Personnel reductions                                            (1.5)
--------------------------------------------------------------------------------
        Environmental remediation costs                                  2.9
--------------------------------------------------------------------------------
        Other                                                           (1.0)
--------------------------------------------------------------------------------

     Depreciation  expense  increased  slightly  in the  third  quarter  of 1998
compared to the third quarter of 1997.

     The Company expects that all of the required  accelerated  amortization for
1998 will be recorded against earnings from operations and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings  from  utility  operations.  Therefore,  $3.3  million  of  accelerated
amortization,  reflecting  one  quarter  of the  1998  accelerated  amortization
requirement of the five-year rate plan  implemented in 1997, was recorded in the
third  quarter of 1998.  In  addition,  as part of the  sharing  mechanism,  the
Company  accrued  an  additional  amortization  of $2.6  million  ($1.7  million
after-tax) in the third quarter of 1998. The sharing  amounts,  both revenue and
amortization,  that were recorded in the third quarter,  represent roughly three
quarters of the current  sharing  estimate for the year 1998.  The final sharing
amount for the year will be subject to change, upward or downward, in the fourth
quarter based on final actual results for the year.

     Other net income  increased  slightly in the third quarter of 1998 compared
to the third quarter of 1997.

     Interest  charges  continued on their  downward  trend,  decreasing by $3.4
million in the third quarter of 1998 compared to the third quarter of 1997, as a
result of the Company's refinancing program and strong cash flow.

NINE MONTHS OF 1998 VS. NINE MONTHS OF 1997
-------------------------------------------

     Earnings for the first nine months of 1998 were $40.6 million, or $2.90 per
share ($2.89 per share on a diluted basis...the difference being about $.003 per
share), up $1.0 million,  or $.08 per share, from the first nine months of 1997.
Excluding  one-time items and  accelerated  amortization  due to one-time items,
earnings from  operations  were $42.1 million,  or $3.02 per share,  up $.44 per
share from the first nine months of 1997. The one-time items were:

                           One-time Items                                   EPS
--------------------------------------------------------------------------------
1997 Quarter 2  Cumulative deferred tax benefits associated with future
                Decommissioning of fossil fuel generating plants           $.48
--------------------------------------------------------------------------------
1997 Quarter 2  Accelerated amortization associated with one-time item    $(.29)
--------------------------------------------------------------------------------
1997 Quarter 3  Gain from subleasing office space                         $ .05
--------------------------------------------------------------------------------
1998 Quarter 2  Subsidiary reserve for agent collection shortfalls
                and other potentially uncollectible receivables           $(.21)
--------------------------------------------------------------------------------
1998 Quarter 3  Refund of prior period transmission charges,
                with interest                                             $ .09
--------------------------------------------------------------------------------

     Retail operating revenues increased by about $7.9 million in the first nine
months of 1998  compared  to the first  nine  months of 1997,  offset by an $8.0
million  increase in cost of production  (retail fuel and energy  expense) and a
small increase in  revenue-based  taxes,  for a retail sales margin  decrease of
$0.4  million.  The  principal  components  of the retail  sales  margin  change
include:

                                     - 26 -
<PAGE>
                                                                     $ millions
--------------------------------------------------------------------------------
     Revenues from:
--------------------------------------------------------------------------------
        DPUC rate order, excluding sharing                              (2.7)
--------------------------------------------------------------------------------
        Sharing: year-to-date estimate for 1998 (see Note A)            (3.0)
--------------------------------------------------------------------------------
        Other price changes                                             (1.3)
--------------------------------------------------------------------------------
        Estimate of "real" retail sales growth, up 3.1%                 14.8
--------------------------------------------------------------------------------
        Estimate of weather effect on retail sales, up 0.5 %             2.9
--------------------------------------------------------------------------------
        Sales decrease from Yale University cogeneration, (0.6) %       (2.8)
--------------------------------------------------------------------------------
     Fuel expense from:
--------------------------------------------------------------------------------
        Sales increase                                                  (3.3)
--------------------------------------------------------------------------------
        Reduced nuclear unit availability                               (1.1)
--------------------------------------------------------------------------------
        Unscheduled outage at Bridgeport Unit 3 (see Note B)            (3.7)
--------------------------------------------------------------------------------
        Fossil fuel price and other                                      0.1
--------------------------------------------------------------------------------
     Revenue-based taxes                                                (0.3)
--------------------------------------------------------------------------------

         Note A: On December  31, 1996,  the  Connecticut  Department  of Public
         Utility  Control (DPUC) issued an order (the Order) that  implemented a
         five-year  regulatory  framework that would reduce the Company's retail
         prices and  accelerate  the  recovery of certain  "regulatory  assets,"
         beginning with deferred  conservation  costs.  The Company is operating
         under the terms of this order in 1998.  The Order  requires a "sharing"
         of income if regulated return on equity exceeds 11.5 percent.  (See the
         discussion on the "Five-year  rate plan" in the Looking Forward section
         for information  regarding the sharing mechanism.) The Company's latest
         estimate  for 1998 results  indicates  that it will be likely that some
         sharing  will be  required in 1998,  and the Company  accrued a revenue
         reduction of $3.0 million ($1.7 million after-tax) in the third quarter
         of 1998.

         Note B:  Saltwater  contamination  caused a shutdown of the  Bridgeport
         Harbor Unit 3  generating  unit on May 22, 1998.  The unit  returned to
         full service on August 23, 1998.

     Net wholesale margin (wholesale  revenue less wholesale  expense) increased
slightly in the first nine  months of 1998  compared to the first nine months of
1997.  Other  operating  revenues,  which include  NEPOOL  related  transmission
revenues, increased by $3.9 million.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $10.3 million in the first nine months of 1998 compared to
the first nine months of 1997. The principal components of these expense changes
include:

                                                                    $ millions
--------------------------------------------------------------------------------
     Capacity:
--------------------------------------------------------------------------------
        Connecticut Yankee Unit, preparing for decommissioning          (3.4)
--------------------------------------------------------------------------------
        Cogeneration and other purchases                                (2.5)
--------------------------------------------------------------------------------
     Other O&M:
--------------------------------------------------------------------------------
        Seabrook Unit                                                   (5.0)
--------------------------------------------------------------------------------
        Millstone Unit 3                                                (2.3)
--------------------------------------------------------------------------------
        Fossil generation unit overhauls and outage costs                9.0
--------------------------------------------------------------------------------
        Pension investment performance and changes to actuarial
          assumptions and methodologies                                 (4.1)
--------------------------------------------------------------------------------
        Personnel reductions                                            (4.5)
--------------------------------------------------------------------------------
        Other                                                            2.5
--------------------------------------------------------------------------------

     Depreciation  expense increased by $0.7 million in the first nine months of
1998 compared to the first nine months of 1997.

                                     - 27 -
<PAGE>

     All of the  accelerated  amortization  in 1997 was  recorded  in the second
quarter of that year as a result of a one-time  gain  recorded in that  quarter.
The Company expects that all of the required  accelerated  amortization for 1998
will be recorded  against  earnings  from  operations  and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings  from  utility  operations.  Therefore,  $9.8  million  of  accelerated
amortization,  reflecting  three quarters of the 1998  accelerated  amortization
requirements of the five-year rate plan implemented in 1997, was recorded in the
first nine months of 1998. In addition,  as part of the sharing  mechanism,  the
Company  accrued  an  additional  amortization  of $2.6  million  ($1.7  million
after-tax) in the third quarter of 1998. The sharing  amounts,  both revenue and
amortization,  that were recorded in the third quarter  represent  roughly three
quarters of the current  sharing  estimate for the year 1998.  The final sharing
amount for the year will be subject to change, upward or downward, in the fourth
quarter based on final actual results for the year.

     Other net income  decreased  by about $0.5 million in the first nine months
of 1998  compared  to the first  nine  months  of 1997.  The  Company's  largest
unregulated  subsidiary,  American  Payment  Systems  (APS),  earned  about $0.5
million  (after-tax) in the first nine months of 1998,  before one-time charges,
compared to a loss of $0.2 million (after-tax) in the first nine months of 1997.
This was more than offset by the absence of other  non-utility  income  accruals
made in 1997, and a reduction in interest income.

     Interest  charges  continued on their  downward  trend,  decreasing by $8.9
million in the first nine  months of 1998  compared  to the first nine months of
1997, as a result of the Company's refinancing program and strong cash flow.


                                 LOOKING FORWARD

(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY  EXPECTED.  READERS ARE CAUTIONED  THAT THE COMPANY  REGARDS  SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)

Five-year rate plan and restructuring legislation
-------------------------------------------------

     On December 31, 1996, the Connecticut  Department of Public Utility Control
(DPUC)  issued an order (the Order)  that  implemented  a  five-year  regulatory
framework  that would reduce the  Company's  retail  prices and  accelerate  the
recovery of certain  "regulatory  assets," beginning with deferred  conservation
costs.  The  Company is  operating  under the terms of this  order in 1998.  The
Order's schedule of price reductions and accelerated  amortizations was based on
a DPUC pro-forma  financial  analysis that anticipated the Company would be able
to  implement  such  changes and earn an allowed  return on common  stock equity
invested in utility assets of 11.5% over the period 1997 through 2001. The Order
established  a set formula to share any income that would produce a return above
the 11.5%  level:  one-third  would be  applied  to  customer  bill  reductions,
one-third would be applied to additional  amortization of regulatory assets, and
one-third would be retained by shareowners.  The Order includes a provision that
it may  be  reopened  and  modified  upon  the  enactment  of  electric  utility
restructuring  legislation  in  Connecticut  and, as a  consequence  of the 1998
restructuring  legislation  described  below,  the  Order  may be  reopened  and
modified.  However,  the Company is unable to predict,  at this time, whether or
when or in  what  respects  the  Order  will  be  modified  on  account  of this
legislation.

     In April  1998,  Connecticut  enacted  Public Act 98-28 (the  Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility  industry.  The business of  generating  and  supplying  electricity  to
consumers will be opened to competition  and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of  delivering  electricity  will remain with the incumbent  franchised  utility
companies  (including the Company).  Beginning in 2000,  each retail consumer of
electricity in Connecticut  (excluding  consumers  served by municipal  electric
systems)  will be able to choose his,  her or its supplier of  electricity  from
among competing  licensed  suppliers,  for delivery over the wires system of the
franchised  electric utility  (Distribution  Company).  Commencing no later than
mid-1999,  Distribution  Companies  will be required  to separate on  consumers'
bills the  charge  for  electricity  generation  services  from the  charge  for
delivering the  electricity  and all other  charges.  On July 29, 1998, the DPUC
issued the first of what are  expected  to be several  orders  relative  to this
"unbundling" requirement.



                                     - 28 -
<PAGE>

     A  major  component  of  the  Restructuring  Act  is  the  collection,   by
Distribution  Companies,  of a "competitive  transition  assessment," a "systems
benefits  charge," an "energy  conservation and load management  program charge"
and  a  "renewable  energy  investment   charge."  The  competitive   transition
assessment and the systems benefits charge represent costs that either have been
or will be reasonably  incurred by  Distribution  Companies to meet their public
service obligations as electric companies, and that will likely not otherwise be
recoverable in a competitive  generation and supply market.  These costs include
above-market  long-term purchased power contract  obligations,  regulatory asset
recovery  and  above-market  investments  in power  plants  (so-called  stranded
costs). The costs of conservation  programs and renewable energy investments are
new  charges  established  in the  Restructuring  Act.  Beginning  in 2000,  the
Distribution Company must collect the competitive transition assessment, systems
benefits charge,  and conservation and load management and renewable  investment
charges from all Distribution  Company customers.  The Distribution Company will
also be required to offer a  "standard  offer" rate that is,  subject to certain
adjustments,  at least  10% below its fully  bundled  price for  electricity  at
December 31, 1996, as discussed below.  The standard offer is required,  subject
to certain  adjustments,  to be the total rate charged under the standard offer,
including  transmission and distribution  services,  the competitive  transition
assessment,  the systems benefits  charge,  the conservation and load management
program charge and the renewable energy charge.  The  Restructuring Act requires
that,  in order  for a  Distribution  Company  to  recover  any  stranded  costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess  proceeds  used to mitigate  its  recoverable  stranded
costs,  and the Company  must  attempt to divest its  ownership  interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval,  an "unbundling  plan" to
separate,  on or before  October 1, 1999,  all of its power plants that will not
have been sold prior to the DPUC's  approval of the unbundling  plan or will not
be sold prior to 2000.

      In May of 1998  the  Company  announced  that it would  commence  selling,
through a two-stage bidding process,  all of its non-nuclear  generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its  operating  fossil-fueled  generating  stations,  Bridgeport
Harbor  Station and New Haven Harbor  Station,  to  Wisvest-Connecticut,  LLC, a
single-purpose  subsidiary  of Wisvest  Corporation.  Wisvest  Corporation  is a
non-utility  subsidiary of Wisconsin Energy Corporation,  Milwaukee,  Wisconsin.
The sale price is $272  million in cash,  including  payment for some  non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent  upon the receipt of  approvals  from the DPUC,  the  Federal  Energy
Regulatory Commission,  and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.

      The Company will  realize a book gain from the sale  proceeds net of taxes
and plant  investment.  However,  this gain  will be  offset by a  writedown  of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation  costs and other costs,  such that there will be no net income effect
of the sale.  Net cash proceeds from the sale are expected to be in the range of
$160-$165 million.  The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special  dividend or stock buyback,  and for
growth opportunities.

      The October 2, 1998 sale agreement for  Bridgeport  Harbor Station and New
Haven Harbor Station resulted from a bidding  process.  The Company's only other
fossil-fueled  generating station is its small deactivated  English Station,  in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from  refuse-to-energy  facilities  located in Bridgeport  and
Shelton,  Connecticut,  one long-term  contract for the purchase of power from a
small hydroelectric  generating station located in Derby,  Connecticut,  and the
Company's 5.45%  participating share in the Hydro-Quebec  transmission  intertie
facility  linking  New  England  and  Quebec,  Canada.  None of these  contracts
attracted an acceptable bid.

      On October 1, 1998,  in its  "unbundling  plan" filing with the DPUC under
the  Restructuring  Act,  the Company  stated that its  unbundling  plan for the
Company's nuclear generation ownership interests,  17.5% of Seabrook Station, in
New Hampshire,  and 3.685% of Millstone  Station Unit No. 3, in Connecticut,  is
divestiture  by the end of 2003 in accordance  with the  Restructuring  Act. The
divestiture  method has not yet been  determined.  In  anticipation  of ultimate
divestiture,  the Company  proposed  to  satisfy,  on a  functional  basis,  the
Restructuring Act's requirement that nuclear generating assets be separated from
its  transmission  and  distribution  assets.  This  would  be


                                     - 29 -
<PAGE>

accomplished by  transferring  the nuclear  generating  assets into separate new
divisions of the Company,  using divisional  financial statements and accounting
to segregate all revenues, expenses, assets and liabilities associated with each
nuclear ownership interest.

      The  Company's  unbundling  plan also  proposes  to  facilitate  the clear
functional  separation  of the  Company's  ongoing  regulated  transmission  and
distribution operations and functions from all of its unregulated operations and
activities  by  undergoing  a  corporate  restructuring  into a holding  company
structure.  In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company  will be  converted  into a share of common  stock of the holding
company. In connection with the formation of the holding company structure,  all
of the Company's interests in all of its operating unregulated subsidiaries will
be  transferred  to the  holding  company  and,  to the extent  new  unregulated
businesses are  subsequently  acquired or commenced,  they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.

      Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power  supply  providers  after June 30, 2000.  The Company
will be required to offer  fully-bundled  service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power  adjustment  clause be added to its regulated  rates,  effective
July 1, 2000. This clause,  similar to and based on the purchased gas adjustment
clauses used by Connecticut's  natural gas local distribution  companies,  would
work in tandem with the Company's  procurement  of power supplies to assure that
standard offer  customers pay competitive  market rates for generation  services
even  though  they  do  not  choose  an  alternate  electricity  supplier.   The
Distribution  Company is also required  under the  Restructuring  Act to provide
back-up service to customers whose electric  supplier fails to provide  electric
generation  services for reasons  other than the  customers'  failure to pay for
such services.  The Restructuring  Act provides for the Distribution  Company to
recover its reasonable costs of providing this back-up service.

      In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.

     On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible  for  providing a standard  offer  service to  customers  who do not
choose an alternate electricity supplier.  The standard offer prices,  including
the fully-bundled price of generation,  transmission and distribution  services,
the  competitive  transition  assessment,  the systems  benefits  charge and the
energy  conservation  and renewable  energy  assessments,  must be 10% below the
average  fully-bundled  prices in effect on December 31,  1996.  The Company has
already  delivered about 4.6% of this decrease  through rate reductions in 1997.
The 1997  through  2001 rate plan  agreed to between the DPUC and the Company in
1996  anticipated  sufficient  income  in 2000  to  accelerate  amortization  of
regulatory  assets  of about  $50  million,  equivalent  to  about 8% of  retail
revenues.  Substantially  all of this  accelerated  amortization  may have to be
eliminated  to  provide  for  the  additional  standard  offer  price  reduction
requirement and added costs imposed by the restructuring  legislation,  although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.

1998 Earnings
-------------

     The Company's  earnings from its utility  business are greatly affected by:
retail sales that  fluctuate  with  weather  conditions  and economic  activity,
fossil fuel prices,  nuclear  generating unit  availability and operating costs,
and  interest  rates.  These are all items  over  which the  Company  has little
control,  although the Company  engages in economic  development  activities  to
increase sales, and hedges its exposure to volatility in fuel costs and interest
rates.

     The  Company's  revenues are  principally  dependent on the level of retail
sales.  The two primary  factors  that affect  retail  sales volume are economic
conditions and weather.  The Company  estimates  that mild 1997 weather 


                                     - 30 -
<PAGE>

reduced retail  kilowatt-hour  sales by about 0.5 percent for the year.  Because
much of the mild 1997  weather  occurred  in the summer  months  when prices are
higher than average,  the revenue impact was  exacerbated.  It is estimated that
mild weather may have reduced  revenues by as much as $5.2 million for the year,
and sales margin (revenue less fuel expense and revenue-based  taxes) by as much
as $4.2 million.  Weather  corrected  retail sales for 1997 were probably in the
5,375-5,425  gigawatthour  range. On this basis, the Company  experienced  about
1.0-1.5  percent of "real" sales  growth in 1997 (i.e.  exclusive of weather and
leap year  factors)  over  "normal"  1996  sales,  with almost all of the growth
occurring in the last half of the year. Growth in "real" sales in the first nine
months of 1998  compared  to the first nine  months of 1997 was  probably in the
2.0-2.5  percent range,  which  increased  revenues by $10-$12 million and sales
margin by $8-$10  million.  This indicates the potential for further real growth
in the fourth  quarter,  although  perhaps at a lower rate  reflecting  the high
growth in the fourth quarter of 1997.  Such 1998 growth may be tempered by other
factors, however, some of which are noted below.

     Reductions in revenues  could occur for several other  reasons.  A contract
has been signed with Yale University,  the Company's largest customer, which has
constructed a cogeneration unit that will produce  approximately one half of its
annual electricity  requirements  (about 1.5 percent of the Company's total 1997
retail sales).  This unit commenced  operations in mid-1998,  and it has reduced
the Company's retail  kilowatthour  sales by about 0.6 percent in the first nine
months of 1998  compared  to the first nine months of 1997.  Real  retail  sales
growth  more than  offset  this  reduction.  Other  potential  causes of revenue
reductions, e.g. special contracts,  customer rate migration, and termination of
the fossil fuel  adjustment  clause,  all appear to be having  minor  effects on
revenue.

     Under the current DPUC Order,  retail  revenues will be reduced,  from what
they would otherwise be, if the Company is in the "sharing" range above an 11.5%
return on common stock  equity.  Currently,  the Company  anticipates  a revenue
reduction  of about  $3.7  million  in 1998 under the  sharing  mechanism,  $3.0
million of which was accrued in the third  quarter.  The overall  average retail
price anticipated for 1998 is about 11.5 cents per kilowatt-hour, slightly below
the average 1997 price but almost 5 percent below the average 1996 price.

     Improvements  in wholesale sales margin  (wholesale  revenue less wholesale
fuel and energy  expense)  will be dependent on the capacity and energy needs of
the region,  on the  availability  of generating  units,  on the addition of new
generation sources, and on how the capacity and energy markets perform under the
new New England Power Pool (NEPOOL) open  competition  system,  designed to meet
Federal  Energy  Regulatory  Commission  (FERC) open access  orders,  when it is
implemented.  Implementation  of this system is  currently  expected on or about
December  1,  1998,  but this  date is  subject  to  NEPOOL  information  system
development  and  testing  and  further  orders  from the FERC.  No  significant
wholesale  sales margin  improvement  is expected by the Company from  wholesale
capacity, transmission and energy sales during 1998.

     Another  major factor  affecting  the  Company's  1998 earnings will be the
Company's ability to control operating  expenses.  The Company offered voluntary
early retirement programs and a voluntary  severance program to union,  nonunion
and  management  employees in 1996. A portion of the  resulting  personnel  cost
savings  occurred in 1996 and 1997, but the largest  increment in annual savings
will be  realized in 1998.  Annual  savings of about $6 million  from  personnel
reductions are estimated,  and this amount was validated by results of the first
nine months.

     The  Company  is  expecting  other  significant  expense  declines  in 1998
compared to 1997 from a number of sources. From the nuclear generating units, it
is expected that operation and maintenance expenses associated with the Seabrook
and Connecticut Yankee units should decline by a total of about $9 million. They
have  decreased  by $8 million in the first nine months of 1998  compared to the
first nine months of 1997.

     Millstone   Unit  3  was  taken  out  of  service  on  March  30,  1996.  A
comprehensive Nuclear Regulatory Commission (NRC) inquiry into the conformity of
the unit and its operations  with all applicable NRC  regulations  and standards
was completed and the unit was allowed to resume operation  beginning on July 4,
1998.  It  achieved  full  power  production  on  July  15,  1998.  The  Company
anticipates  that operating  costs should ramp down to more normal levels for an
efficient and safe nuclear unit of this class,  and expects a reduction of about
$3 million in these  costs in 1998  compared  to 1997.  Also,  net fuel  expense
should  decline by $350,000 per month for every month of  operation,  net of the
replacement  fuel provision of about $130,000 per  month...for a total reduction
of about $1.7

                                     - 31 -
<PAGE>

million for 1998 compared to 1997.  Operation and maintenance  expense decreased
by $2.3  million in the first  nine  months of 1998  compared  to the first nine
months of 1997, and fuel expense decreased by $0.7 million.

     Pension and health benefit expenses, excluding one-time items, are expected
to decrease by about $2.5 million in 1998 compared to 1997.  NEPOOL expenses are
expected to increase by about $1.0  million,  and expenses  associated  with the
"Year 2000 Issue" could reach as much as $5.0-$6.0 million in the 1998-99 period
(see "Year 2000 Issue").  The latter is the result of receiving more current and
detailed  information  from embedded  technology  vendors.  Other  operation and
maintenance  expenses  may  increase  or  decrease  by  amounts  that  cannot be
predicted at this time.

     Interest  costs  are  expected  to  decline  by about $10  million  in 1998
compared  to 1997 to about $52  million,  a level that was last  experienced  in
1984. This interest cost reduction is largely a result of debt  refinancings and
debt paydown. Interest charges for the first nine months of 1998 compared to the
first nine months of 1997 decreased by $8.9 million.

     Other factors  should  increase  costs.  Other  operation  and  maintenance
expense should  increase by about $9 million in 1998 compared to 1997 reflecting
increased  fossil-fueled  generating unit scheduled  maintenance.  Environmental
remediation  added $2.9 million of other  operation and  maintenance  costs,  as
recorded in the third quarter of 1998.  Such costs cannot be  anticipated.  Base
depreciation,  excluding  accelerated  amortization,  should increase about $2.0
million in 1998.  Accelerated  amortization,  per the Order,  but  excluding any
sharing  amortization,  will  increase  by about $7 million  (reflecting  a $3.3
million per quarter  increase,  except for a $3.1 million decrease in the second
quarter  compared to 1997, as all of the $6.4 million  amortization for 1997 was
recorded as an offset to a one-time gain in the second quarter.) Other operating
expenses will have some  increases and some  decreases  that should more or less
offset one another.

     In summary,  the Company expects  substantial  net expense  reductions that
should more than compensate for the loss of one-time items realized in 1997 (all
of them utility  related),  cover the increase in accelerated  conservation  and
load management  amortization,  and allow utility  earnings to increase above an
11.5% return on common stock equity into the "sharing"  range of the Order.  The
11.5% return  level would  produce  utility  earnings of about  $3.40-$3.45  per
share,  while  "shared"  earnings  could add an additional  $.05-$.10 per share.
Non-utility earnings,  before one-time items, should increase approximately $.05
per share in 1998 compared to 1997, due principally to the anticipated breakeven
operation  of the  non-regulated  subsidiaries.  The Company  expects  that 1998
quarterly earnings from operations will follow a pattern similar to that of 1997
on a weather-normalized basis.

Other
-----

     The City of New Haven (the City) and the Company are  involved in a dispute
over the  amount  of  personal  property  taxes  owed to the City for tax  years
beginning with  1991-1992.  On May 8, 1998,  the City and the Company  reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992  through 1997-1998 and the
Company's  personal  property tax  assessments  for the tax year  1998-1999  and
subsequent years.  Under the terms of this settlement,  the Company will pay the
City $14.025  million,  subject to Superior Court approval of the settlement and
conditioned on the Company receiving  authorization from the DPUC to recover the
settlement  amount  from its retail  customers.  The DPUC  denied the  Company's
initial  application for such authorization and the City has agreed to extend to
November  30,  1998  the  time  period  for  satisfying  this  condition  of the
settlement in return for a payment by the Company of $6 million,  which has been
recognized  as a  prepayment  of  property  taxes.  The  Company  filed a second
application  with the DPUC on July 9,  1998.  If the DPUC  authorization  is not
forthcoming, the $6 million payment will be applied to future tax bills.

1999 and on
-----------

     Looking  forward to 1999,  the Company  expects to maintain  earnings  from
utility  operations in the "sharing range" of the Order,  just as it expects for
1998. The sharing mechanism is in effect if utility earnings exceed 11.5 percent
on common stock equity  invested in utility  assets,  equivalent  to an earnings
level of about  $3.45  per  share in


                                     - 32 -
<PAGE>

1999. Earnings levels in 1999 may also be affected by how the Company decides to
deploy the net cash  proceeds of  approximately  $160  million from its recently
proposed fossil plant sale.

     The  Company's  sales margin  should  continue to improve from modest sales
growth,  offset by the full effect of the Yale University  cogeneration unit for
the entire year of 1999. The Company does not forecast  significant sales growth
for 1999.  Although sales growth has been  exceptional in 1998 compared to 1997,
there is no basis for  believing  that such growth will continue into next year.
Utility related operating expenses are expected to decrease slightly,  offset by
the additional $7 million of accelerated  amortization expense required for 1999
under the Order.  The Company  does not expect any  significant  operating  cost
reductions in 1999 from the proposed sale of its fossil plants.

     In summary,  the Company  expects modest  improvements in pre-tax income in
1999 from utility operations, which, under the sharing arrangement, only affects
net income by  one-third  of the total  improvement.  The  subsidiary,  American
Payment  Systems  (APS),   should  continue  to  show   improvement   over  1998
performance.  APS  should  earn  between  $.08-$.12  per share  from  operations
compared to $.05 per share expected in 1998.  Precision Power,  Inc. is expected
to continue losses equivalent to $.05-$.15 per share,  depending on its level of
business  expansion and pursuit of new ventures;  comparable to an expected loss
of $.05 per share in 1998.

Year 2000 Issue
---------------

     The Company's  planning and  operations  functions,  and its cash flow, are
dependent  on the  timely  flow of  electronic  data to and from its  customers,
suppliers and other electric utility system managers and operators.  In order to
assure that this data flow will not be disturbed by the problems  emanating from
the fact that many existing computer programs were designed without  considering
the impact of the year 2000 and use only two digits to identify  the year in the
date field of the  programs  (the Year 2000  Issue),  the Company  initiated  in
mid-1997,  and is  pursuing,  an  aggressive  program to  identify  and  correct
deficiencies  in its  computer  systems.  Critical  systems have been defined as
those business processes, including embedded technology, which if not remediated
may have a  significant  impact on  safety,  customers,  revenue  or  regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged  and is asking for assurance of their Year 2000
compliance.

     An inventory and assessment of the Company's computer system  applications,
hardware, software and embedded technologies has been completed, and recommended
solutions to all identified risks and exposures have been generated.  A testing,
remediation, renovation, replacement and retirement program has been in progress
since early 1998. A total of 362 business processes have been identified and 174
of them have been verified as Year 2000 compliant through testing,  remediation,
replacement or retirement.  The remediation  methodology utilized has been Fixed
Windowing and totally independent  platforms have been installed for testing all
of the applications.  Necessary  upgrades to mainframe hardware and software are
expected to be completed  and tested by the end of 1998. A parallel  program for
desktop  hardware  and  application  software  on  all  platforms  is  currently
projected to be completed  and tested,  for all critical  systems,  by March 31,
1999.  Requests  for  documented  compliance  information  have been sent to all
critical suppliers,  data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed.

     The Company  believes that the  successful  implementation  of this program
should ultimately cost no more than $6 million for existing  information systems
and embedded technology.  Approximately $2.2 million will be spent by the end of
1998. As systems testing progresses and more embedded  technology vendor product
information  is  forthcoming,   business  decisions  made  and  testing  results
verified, the need for increased expenditures, if necessary, will be determined.
The Company  believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.

     While  failure to achieve  Year 2000  compliance  by any one of a number of
critical  suppliers  and data  sharers  could  have some  adverse  effect on the
success of the Company's  implementation  program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications   providers,  the  other  participants  in  NEPOOL,  and  the
Independent  System  Operator  (ISO) that  operates the NEPOOL bulk power supply
system.  Year 2000  compliance  failures by any of these  entities  could have a
material


                                     - 33 -
<PAGE>

effect  on  electricity  delivery  and  telemetering.  UI has  communicated  its
concerns to its principal  telecommunications  provider,  in an effort to design
and plan  appropriate  testing to insure  that all  critical  telecommunications
functions  will be  operational.  This  issue  is also  being  addressed  at the
regional level by NEPOOL and the ISO. The Company is also actively involved with
NEPOOL/ISO  in the  planning  effort for  integrated  contingency  planning,  as
directed by the North American Electric Reliability Council.

     Aside from  telecommunications  and  NEPOOL/ISO  concerns,  vendor  patches
releases and/or  replacement  equipment or software  availability  pose the most
significant  risks  to  the  success  of  the  Company's  Year  2000  compliance
implementation  program.  In order to minimize these risks,  the Company will be
actively  involved in contingency  planning.  While the Company's  knowledge and
experience  in  electric  system  recovery   planning  and  execution  has  been
demonstrated  in the past,  the Company  recognizes the need for, and importance
of, Year 2000-specific contingency planning,  because the complex interaction of
today's  computing  and  communications  systems  precludes  certainty  that all
critical  system  remediation  will be  successful.  At this  time,  contingency
planning for essential business functions is under  investigation in most areas,
but specific needs have not been fully identified. These plans will be developed
in the first  quarter of 1999,  after the  majority  of business  processes  are
scheduled to be tested and within the timeframe when the  ISO/NEPOOL  process is
due to develop  region-wide  contingency plans for operations.  As a part of the
contingency planning process, consideration will be given to potential frequency
and duration of  interruptions in the generating,  financial and  communications
infrastructures.  Since  contingency  planning  is,  by  nature,  a  speculative
process,  there can be no assurance that this planning will completely eliminate
the  risk of  material  impacts  to the  Company's  business  due to  Year  2000
problems.  However,  the Company recognizes the importance to its customers of a
reliable supply of electricity,  and it intends to devote whatever resources are
necessary to assure that both the program and its implementation are successful.



                                     - 34 -
<PAGE>

                           PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

     On November 2, 1993, the Company received  "updated"  personal property tax
bills  from  the  City of New  Haven  (the  City)  for the tax  year  1991-1992,
aggregating $6.6 million,  based on an audit by the City's tax assessor.  On May
7, 1994,  the Company  received a  "Certificate  of  Correction....to  correct a
clerical  omission  or  mistake"  from the City's tax  assessor  relative to the
assessed value of the Company's  personal  property for the tax year  1994-1995,
which certificate  purports to increase said assessed value by approximately 53%
above the tax assessor's  valuation at February 28, 1994,  generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment  changes  relative to the assessed  value of the  Company's  personal
property for the tax year  1995-1996,  which  notices  purport to increase  said
assessed value by approximately 48% over the valuation  declared by the Company,
generating  tax claims of  approximately  $3.5  million.  On May 11,  1995,  the
Company received  notices of assessment  changes relative to the assessed values
of the Company's  personal  property for the tax years  1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately  45% and
49%, respectively,  over the valuations declared by the Company,  generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996,  the  Company  received  notices of  assessment  changes  relative  to the
assessed value of the Company's  personal  property for the tax year  1996-1997,
which notices purport to increase said assessed value by approximately  57% over
the  valuations  declared by the Company and are expected to generate tax claims
of approximately $3.8 million. On March 7, 1997, the Company received notices of
assessment  changes  relative to the assessed  value of the  Company's  personal
property for the tax year  1997-1998,  which  notices  purport to increase  said
assessed value by approximately 54% over the valuations  declared by the Company
and are  expected to generate  tax claims of  approximately  $3.7  million.  The
Company  has  vigorously  contested  each of these  actions  by the  City's  tax
assessor.  In January 1996, the Connecticut Superior Court granted the Company's
motion for summary  judgment  against the City relative to the earliest tax year
at issue,  1991-1992,  ruling that, after January 31, 1992, the tax assessor had
no statutory  authority to revalue  personal  property  listed and valued on the
Company's tax list for the tax year  1991-1992.  This Superior  Court  decision,
which would also have been  applicable to and defeated the assessor's  valuation
increases  for the two  subsequent  tax  years,  1992-1993  and  1993-1994,  was
appealed by the City. On April 11, 1997, the Connecticut  Supreme Court reversed
the Superior  Court's  decisions in this and two other companion cases involving
other taxpayers,  ruling that the tax assessor had a three-year  period in which
to audit and revalue  personal  property  listed and valued on the Company's tax
list for the tax  year  1991-1992.  On May 8,  1998,  the  City and the  Company
reached a comprehensive  settlement of all of the Company's  contested  personal
property  tax  assessments  and tax bills for the tax  years  1991-1992  through
1997-1998 and the Company's  personal  property tax assessments for the tax year
1998-1999 and subsequent years. Under the terms of this settlement,  the Company
will pay the City $14.025  million,  subject to Superior  Court  approval of the
settlement and conditioned on the Company receiving  authorization from the DPUC
to recover the settlement amount from its retail customers.  The DPUC denied the
Company's initial  application for such authorization and the City has agreed to
extend to November 30, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million,  which has been
recognized  as a  prepayment  of  property  taxes.  The  Company  filed a second
application  with the DPUC on July 9,  1998.  If the DPUC  authorization  is not
forthcoming, the $6 million payment will be applied to future tax bills.


                                     - 35 -
<PAGE>

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K.

     (a) Exhibits.

<TABLE>
<CAPTION>
 Exhibit
Table Item            Exhibit
  Number               Number                                 Description
----------            -------                                 -----------

<S>                     <C>          <C>                                                                              
(12), (99)              12           Statement  Showing  Computation  of Ratios of  Earnings  to Fixed
                                     Charges  and Ratios of Earnings  to  Combined  Fixed  Charges and
                                     Preferred  Stock  Dividend   Requirements  (Twelve  Months  Ended
                                     September 30,  1998 and Twelve  Months Ended  December 31,  1997,
                                     1996, 1995, 1994 and 1993).

(27)                    27           Financial Data Schedule
</TABLE>


     (b) Reports on Form 8-K.

         None



                                     - 36 -
<PAGE>



                                   SIGNATURES

     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.

                         THE UNITED ILLUMINATING COMPANY




Date    11/13/98               Signature       /s/ Robert L. Fiscus
    -----------------                   ---------------------------------------
                                                   Robert L. Fiscus
                                        Vice Chairman of the Board of Directors
                                                 and Chief Financial Officer



                                     - 37 -
<PAGE>

                                  EXHIBIT INDEX
<TABLE>
<CAPTION>
  Exhibit
Table Item            Exhibit
  Number               Number                                Description
----------            -------                                -----------

<S>                     <C>       <C>
(12), (99)              12        Statement  Showing  Computation  of Ratios of  Earnings  to Fixed
                                  Charges  and Ratios of Earnings  to  Combined  Fixed  Charges and
                                  Preferred  Stock  Dividend   Requirements  (Twelve  Months  Ended
                                  September 30,  1998 and Twelve  Months Ended  December 31,  1997,
                                  1996, 1995, 1994 and 1993).

(27)                    27        Financial Data Schedule
</TABLE>