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 JUNE 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 June 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 six months
           ended June 30, 1998 and 1997.                                    3
         Consolidated Balance Sheet as of June 30, 1998 and
           December 31, 1997.                                               4
         Consolidated Statement of Cash Flows for the three and six 
           months ended June 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                              10
           -   Income Taxes                                                11
           -   Supplementary Information                                   12
           -   Fuel Financing Obligations and Other Lease Obligations      13
           -   Commitments and Contingencies                               13
               -  Capital Expenditure Program                              13
               -  Nuclear Insurance Contingencies                          13
               -  Other Commitments and Contingencies                      14
                  - Connecticut Yankee                                     14
                  - Hydro-Quebec                                           14
                  - Property Taxes                                         14
                  - Site Decontamination, Demolition and Remediation Costs 15
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning     15

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations.                                        16

           -   Major Influences on Financial Condition                     16
           -   Capital Expenditure Program                                 18
           -   Liquidity and Capital Resources                             19
           -   Subsidiary Operations                                       20
           -   Results of Operations                                       20
           -   Looking Forward                                             23

                           Part II. OTHER INFORMATION

Item 1.  Legal Proceedings.                                                29

Item 4.  Submission of Matters to a Vote of Security Holders.              29

Item 5.  Other Information.                                                30

Item 6.  Exhibits and Reports on Form 8-K.                                 31

         SIGNATURES                                                        32




                                     - 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              Six Months Ended
                                                                                 June 30,                       June 30,
                                                                            1998           1997            1998          1997
                                                                            ----           ----            ----          ----
<S>                                                                       <C>            <C>             <C>           <C>     
OPERATING REVENUES (NOTE G)                                               $159,792       $163,774        $322,266      $344,099
                                                                      -------------  -------------   -------------  ------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                        33,412         39,020          73,953        93,941
     Capacity purchased                                                      8,978         10,922          15,200        21,839
     Other                                                                  38,094         39,619          71,403        76,909
  Maintenance                                                               10,560         10,659          21,593        19,894
  Depreciation                                                              20,632         23,614          41,438        40,706
  Amortization of cancelled nuclear project and deferred return              3,439          3,439           6,879         6,879
  Income taxes (Note F)                                                     11,193            712          22,680        12,027
  Other taxes (Note G)                                                      12,310         13,097          25,269        27,062
                                                                      -------------  -------------   -------------  ------------
       Total                                                               138,618        141,082         278,415       299,257
                                                                      -------------  -------------   -------------  ------------
OPERATING INCOME                                                            21,174         22,692          43,851        44,842
                                                                      -------------  -------------   -------------  ------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                           40            138              70           342
  Other-net (Note G)                                                        (4,461)           725          (4,016)        1,506
  Non-operating income taxes                                                 2,923          1,522           3,006         2,939
                                                                      -------------  -------------   -------------  ------------
       Total                                                                (1,498)         2,385            (940)        4,787
                                                                      -------------  -------------   -------------  ------------
INCOME BEFORE INTEREST CHARGES                                              19,676         25,077          42,911        49,629
                                                                      -------------  -------------   -------------  ------------
INTEREST CHARGES
  Interest on long-term debt                                                12,879         15,876          26,402        32,248
  Interest on Seabrook obligation bonds owned by the company                (1,818)        (1,691)         (3,636)       (3,382)
  Other interest (Note G)                                                    1,432            852           2,276         1,618
  Allowance for borrowed funds used during construction                       (135)          (353)           (264)         (839)
                                                                      -------------  -------------   -------------  ------------
                                                                            12,358         14,684          24,778        29,645
  Amortization of debt expense and redemption premiums                         618            648           1,268         1,326
                                                                      -------------  -------------   -------------  ------------
       Net Interest Charges                                                 12,976         15,332          26,046        30,971
                                                                      -------------  -------------   -------------  ------------

MINORITY INTEREST IN PREFERRED SECURITIES                                    1,203          1,203           2,406         2,406
                                                                      -------------  -------------   -------------  ------------

NET INCOME                                                                   5,497          8,542          14,459        16,252
Discount on preferred stock redemptions                                        (21)             -             (21)          (19)
Dividends on preferred stock                                                    50             52             101           103
                                                                      -------------  -------------   -------------  ------------
INCOME APPLICABLE TO COMMON STOCK                                           $5,468         $8,490         $14,379       $16,168
                                                                      =============  =============   =============  ============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                         14,021         14,101          14,004        14,101
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                       14,024         14,101          14,011        14,101

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                       $0.39          $0.61           $1.03         $1.15

CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK                            $0.72          $0.72           $1.44         $1.44
</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>
                                                             June 30,          December 31,
                                                               1998               1997*
                                                               ----               ----
                                                           (Unaudited)
<S>                                                           <C>                 <C>
Utility Plant at Original Cost
  In service                                                  $1,874,934          $1,867,145
  Less, accumulated provision for depreciation                   676,595             644,971
                                                          ---------------     ---------------
                                                               1,198,339           1,222,174

Construction work in progress                                     19,496              25,448
Nuclear fuel                                                      24,536              25,990
                                                          ---------------     ---------------
     Net Utility Plant                                         1,242,371           1,273,612
                                                          ---------------     ---------------


Other Property and Investments                                    34,350              32,451
                                                          ---------------     ---------------

Current Assets
  Cash and temporary cash investments                             14,972              32,002
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                                57,724              57,231
   Other                                                          30,947              27,914
  Accrued utility revenues                                        27,007              25,269
  Fuel, materials and supplies, at average cost                   30,709              19,147
  Prepayments                                                      9,478               3,397
  Other                                                              136                  67
                                                          ---------------     ---------------
     Total                                                       170,973             165,027
                                                          ---------------     ---------------

Deferred Charges
  Unamortized debt issuance expenses                               9,221               6,611
  Other                                                            3,766               5,727
                                                          ---------------     ---------------
     Total                                                        12,987              12,338
                                                          ---------------     ---------------

Regulatory Assets (future amounts due from customers
                   through the ratemaking process)
  Income taxes due principally to book-tax differences           220,401             228,992
  Connecticut Yankee                                              48,223              51,313
  Deferred return - Seabrook Unit 1                               18,878              25,171
  Unamortized redemption costs                                    22,321              23,027
  Unamortized cancelled nuclear projects                          11,538              12,125
  Uranium enrichment decommissioning cost                          1,245               1,312
  Other                                                            5,661               6,357
                                                          ---------------     ---------------
     Total                                                       328,267             348,297
                                                          ---------------     ---------------

                                                              $1,788,948          $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>
                                                                June 30,          December 31,
                                                                  1998               1997*
                                                                  ----               ---- 
                                                              (Unaudited)
<S>                                                             <C>                 <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                 $292,006            $288,730
    Paid-in capital                                                 1,908               1,349
    Capital stock expense                                          (2,182)             (2,182)
    Unearned employee stock ownership plan equity                 (10,685)            (11,160)
    Retained earnings                                             156,420             162,226
                                                           ---------------     ---------------
                                                                  437,467             438,963
  Preferred stock                                                   4,299               4,351
  Minority interest in preferred securities                        50,000              50,000
  Long-term debt
    Long-term debt                                                657,490             746,058
    Investment in Seabrook obligation bonds                       (92,860)           (101,388)
                                                           ---------------     ---------------
      Net long-term debt                                          564,630             644,670
                                                           ---------------     ---------------

          Total                                                 1,056,396           1,137,984
                                                           ---------------     ---------------

Noncurrent Liabilities
  Connecticut Yankee contract obligation                           38,631              40,821
  Pensions accrued                                                 37,305              39,149
  Nuclear decommissioning obligation                               20,206              17,538
  Obligations under capital leases                                 16,683              16,853
  Other                                                             6,037               5,507
                                                           ---------------     ---------------
          Total                                                   118,862             119,868
                                                           ---------------     ---------------

Current Liabilities
  Current portion of long-term debt                                74,574             100,000
  Notes payable                                                   118,825              37,751
  Accounts payable                                                 52,846              68,699
  Dividends payable                                                10,145              10,051
  Taxes accrued                                                     6,086               4,166
  Interest accrued                                                 18,183              10,266
  Obligations under capital leases                                    344                 340
  Other accrued liabilities                                        42,123              37,471
                                                           ---------------     ---------------
          Total                                                   323,126             268,744
                                                           ---------------     ---------------

Customers' Advances for Construction                                1,864               1,878
                                                           ---------------     ---------------

Regulatory Liabilities  (future amounts owed to customers
                         through the ratemaking process)
  Accumulated deferred investment tax credits                      16,004              16,385
  Other                                                             2,057               2,356
                                                           ---------------     ---------------
          Total                                                    18,061              18,741
                                                           ---------------     ---------------

Deferred Income Taxes  (future tax liabilities owed               270,639             284,510
                        to taxing authorities)
Commitments and Contingencies (Note L)
                                                           ---------------     ---------------
                                                               $1,788,948          $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          Six Months Ended
                                                                    June 30,                   June 30,
                                                              1998          1997         1998           1997
                                                              ----          ----         ----           ----
<S>                                                          <C>          <C>           <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                  $5,497       $8,542       $14,459        $16,252
                                                         ------------  -----------  ------------  -------------
  Adjustments to reconcile net income to net cash
    provided by operating activities:
     Depreciation and amortization                            21,897       24,701        43,748         43,055
     Deferred income taxes                                    (3,029)      (7,737)       (5,280)       (10,965)
     Deferred investment tax credits - net                      (191)        (191)         (381)          (381)
     Amortization of nuclear fuel                              1,232        1,309         2,497          2,877
     Allowance for funds used during construction               (175)        (491)         (334)        (1,181)
     Amortization of deferred return                           3,146        3,146         6,293          6,293
     Changes in:
             Accounts receivable - net                        (9,865)      10,494        (3,526)        23,171
             Fuel, materials and supplies                     (7,794)       1,034       (11,562)           959
             Prepayments                                      (3,113)      (2,623)       (6,081)           591
             Accounts payable                                 10,198       (5,512)      (15,853)       (24,655)
             Interest accrued                                  5,389        6,743         7,917          9,137
             Taxes accrued                                    (9,999)      (8,628)        1,920          1,901
             Other assets and liabilities                      3,987       (4,258)        1,195         (3,516)
                                                         ------------  -----------  ------------  -------------
     Total Adjustments                                        11,683       17,987        20,553         47,286
                                                         ------------  -----------  ------------  -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES                     17,180       26,529        35,012         63,538
                                                         ------------  -----------  ------------  -------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Common stock                                                  295            -         4,310              -
   Long-term debt                                                  -            -        99,780              -
   Notes payable                                              73,705      (18,948)       81,074         24,676
   Securities redeemed and retired:
     Preferred stock                                             (52)           -           (52)           (40)
     Long-term debt                                          (80,000)           -      (213,976)       (32,585)
   Discount on preferred stock redemption                         21            -            21             19
   Expense of issue                                                -            -          (800)             -
   Lease obligations                                             (84)         (78)         (166)          (154)
   Dividends
     Preferred stock                                             (51)         (52)         (102)          (104)
     Common stock                                            (10,090)     (10,153)      (20,090)       (20,306)
                                                         ------------  -----------  ------------  -------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES          (16,256)     (29,231)      (50,001)       (28,494)
                                                         ------------  -----------  ------------  -------------

CASH FLOWS FROM INVESTING ACTIVITIES
    Plant expenditures, including nuclear fuel                (2,213)      (9,735)      (10,569)       (24,187)
    Investment in debt securities                                  -            -         8,528              -
                                                         ------------  -----------  ------------  -------------
NET CASH USED IN INVESTING ACTIVITIES                         (2,213)      (9,735)       (2,041)       (24,187)
                                                         ------------  -----------  ------------  -------------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                     (1,289)     (12,437)      (17,030)        10,857
BALANCE AT BEGINNING OF PERIOD                                16,261       29,688        32,002          6,394
                                                         ------------  -----------  ------------  -------------
BALANCE AT END OF PERIOD                                     $14,972      $17,251       $14,972        $17,251
                                                         ============  ===========  ============  =============

CASH PAID DURING THE PERIOD FOR:
   Interest (net of amount capitalized)                       $8,824       $9,754       $19,450        $20,759
                                                         ============  ===========  ============  =============
   Income taxes                                              $20,150      $14,073       $23,050        $17,773
                                                         ============  ===========  ============  =============
</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 six months of 1998 and
1997 was 8.0% 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 $1,290,000 and $1,285,000 in the first six
months of 1998 and 1997, respectively,  into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 1998, the Company's  shares of
the trust fund balances,  which included accumulated earnings on the funds, were
$14.3  million  and $5.9  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 June 30, 1998,  the Company had swap  agreements for 1998 for 650,000
barrels  of fuel oil at a  weighted  average  price of $15.88 per barrel and had
call  options for  200,000  barrels of fuel oil at a weighted  average  price of
$18.52 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 June 30, 1998, of which 314,330 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 June 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 six 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 June 30, 1998, 314,330 shares, with a fair market value of $15.9
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 $98.3 million were free from such limitations at June 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, 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  suppliers,
for  delivery  over  the  wire  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  Connecticut's  restructuring  legislation  is  the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems  benefits"  charge,  an  "energy  conservation  and load  management"
assessment and a "renewable energy"  assessment,  representing 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 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,  above-market  investments in power plants (stranded  costs),  and the
costs of  conservation  programs.  They will be  recovered  by the  Distribution
Companies from all consumers of electricity on a going-forward basis, commencing
in 2000.  Because it is expected that many  fossil-fueled  power plants may have
market  values  in  excess  of  their  net  historic  costs,  the  restructuring
legislation  requires that, in order for a  Distribution  Company to recover the
stranded costs associated with its power plants,  its fossil-fueled  plants must
be sold prior to 2000 and the 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.

     On May 20, 1998,  the Company  announced that it would commence the process
of  selling,  through  a  two-stage  bidding  process,  all  of  its  nonnuclear
generation  assets in compliance  with the statute.  The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven,  Connecticut,  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  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. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective  purchasers of the
assets. The Company has commenced the second stage of the process,  during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare  final,  binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.

     Another requirement of the restructuring legislation is that, by October 1,
1998,  each  Distribution  Company  must  file,  for  the  DPUC's  approval,  an
"unbundling  plan" to  transfer  into  one or more  legally  separate  corporate
affiliates,  on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.



                                     - 9 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     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  Company  expects  that,  for  all  intents  and  purposes,   the  1998
restructuring  legislation  will take  precedence  over the 1996  five-year rate
plan, beginning in the year 2000.

(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 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
June 30, 1998, the Company had $35 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 June 30, 1998,  the
Company  had  $80  million  of  short-term  borrowings  outstanding  under  this
facility.

     In  addition,   as  of  June  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.



                                     - 10 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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

Income tax provisions:
  Current
             Federal                                                    $8,907        $5,381         $19,626       $15,447
             State                                                       2,583         1,737           5,709         4,987
                                                                   ------------  ------------    ------------  ------------
                Total current                                           11,490         7,118          25,335        20,434
                                                                   ------------  ------------    ------------  ------------
  Deferred
             Federal                                                    (2,143)       (5,945)         (3,694)       (7,999)
             State                                                        (886)       (1,792)         (1,586)       (2,966)
                                                                   ------------  ------------    ------------  ------------
                Total deferred                                          (3,029)       (7,737)         (5,280)      (10,965)
                                                                   ------------  ------------    ------------  ------------

  Investment tax credits                                                  (191)         (191)           (381)         (381)
                                                                   ------------  ------------    ------------  ------------

     Total income tax expense                                           $8,270         ($810)        $19,674        $9,088
                                                                   ============  ============    ============  ============

Income tax components charged as follows:
  Operating expenses                                                   $11,193          $712         $22,680       $12,027
  Other income and deductions - net                                     (2,923)       (1,522)         (3,006)       (2,939)
                                                                   ------------  ------------    ------------  ------------

     Total income tax expense                                           $8,270         ($810)        $19,674        $9,088
                                                                   ============  ============    ============  ============


The following table details the components
 of the deferred income taxes:
     Seabrook sale/leaseback transaction                               ($2,180)      ($2,586)        ($4,361)      ($5,172)
     Conservation and load management                                   (2,006)       (3,161)         (4,013)       (4,091)
     Accelerated depreciation                                            1,534         1,460           3,068         2,919
     Tax depreciation on unrecoverable plant investment                  1,212         1,231           2,424         2,463
     Pension benefits                                                      383            52             983           109
     Unit overhaul and replacement power costs                             860         2,589             462         1,386
     Postretirement benefits                                              (106)         (148)           (208)         (292)
     Fossil fuel decommissioning reserve                                   (83)       (7,002)           (165)       (7,002)
     Other - net                                                        (2,643)         (172)         (3,470)       (1,285)
                                                                   ------------  ------------    ------------  ------------

Deferred income taxes - net                                            ($3,029)      ($7,737)        ($5,280)     ($10,965)
                                                                   ============  ============    ============  ============
</TABLE>

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

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION


<CAPTION>
                                                                       Three Months Ended                  Six Months Ended
                                                                            June 30,                           June 30,
                                                                     1998             1997              1998             1997
                                                                     ----             ----              ----             ----
                                                                            (000's)                            (000's)
<S>                                                               <C>              <C>               <C>              <C>
Operating Revenues
------------------

     Retail                                                        $149,222         $146,044          $295,767         $296,525
     Wholesale - capacity                                             2,887            2,525             6,313            4,782
               - energy                                               5,559           14,195            16,948           41,273
     Other                                                            2,124            1,010             3,238            1,519
                                                             ---------------  ---------------   ---------------  ---------------
          Total Operating Revenues                                 $159,792         $163,774          $322,266         $344,099
                                                             ===============  ===============   ===============  ===============

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

    Retail
     Residential                                                    420,484          412,503           908,813          910,774
     Commercial                                                     566,975          543,243         1,131,764        1,083,701
     Industrial                                                     292,989          292,456           558,617          561,590
     Other                                                           11,848           11,971            24,021           24,248
                                                             ---------------  ---------------   ---------------  ---------------
                                                                  1,292,296        1,260,173         2,623,215        2,580,313
    Wholesale                                                       255,472          565,903           763,789        1,496,138
                                                             ---------------  ---------------   ---------------  ---------------
          Total Sales by Class                                    1,547,768        1,826,076         3,387,004        4,076,451
                                                             ===============  ===============   ===============  ===============

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

    Charged to:
     Operating:
        State gross earnings                                         $5,550           $5,496           $11,171          $11,228
        Local real estate and personal property                       5,419            6,154            10,901           12,291
        Payroll taxes                                                 1,341            1,447             3,197            3,543
                                                             ---------------  ---------------   ---------------  ---------------
                                                                     12,310           13,097            25,269           27,062
     Nonoperating and other accounts                                    145              139               293              232
                                                             ---------------  ---------------   ---------------  ---------------
          Total Other Taxes                                         $12,455          $13,236           $25,562          $27,294
                                                             ===============  ===============   ===============  ===============

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

     Interest income                                                   $340             $306              $660             $926
     Equity earnings from Connecticut Yankee                            218              242               525              688
     Earnings (Loss) from subsidiary companies                       (4,723)            (362)           (4,528)            (895)
     Miscellaneous other income and (deductions) - net                 (296)             539              (673)             787
                                                             ---------------  ---------------   ---------------  ---------------
          Total Other Income and (Deductions) - net                 ($4,461)            $725           ($4,016)          $1,506
                                                             ===============  ===============   ===============  ===============

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

     Notes Payable                                                     $797             $623            $1,315           $1,200
     Other                                                              635              229               961              418
                                                             ---------------  ---------------   ---------------  ---------------
          Total Other Interest Charges                               $1,432             $852            $2,276           $1,618
                                                             ===============  ===============   ===============  ===============
</TABLE>

                                     - 12 -
<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 August 1999.  At June 30, 1998,  approximately  $12.5  million of 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 $167.7 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.



                                     - 13 -
<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.  Connecticut  Yankee  has  filed  revised  decommissioning  cost
estimates and amendments to the power contracts with its owners with the Federal
Energy Regulatory  Commission (FERC). The estimate of the sum of future payments
for the closing, decommissioning and recovery of the remaining investment in the
Connecticut  Yankee Unit was  approximately  $606  million at December 31, 1997.
Based on regulatory  precedent,  Connecticut Yankee believes it 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 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  $9.6  million) and
return  on  investment  (approximately  $5.7  million)  at  June  30,  1998,  is
approximately $38.6 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.

                                  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 June  30,  1998,  the  Company's
guarantee liability for this debt was approximately $7.1 million.

                                 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, on June 30, 1998,  the City agreed to
extend to August 31, 1998 the time period for  satisfying  this condition of the
settlement  in return for a payment by the  Company of $5  million.  The Company
filed  a  second  application  with  the  DPUC  on July  9,  1998.  If the  DPUC
authorization  is not  forthcoming,  the $5 million  payment  will be applied to
future tax bills.



                                     - 14 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

             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 June 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 deactivated generation  facilities.  Remediation will include the
repair and/or  replacement of approximately 560 linear feet of sheet piling. The
total cost of the remediation and sheet piling repair is presently  estimated at
$15 million.

     As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company  has  commenced  the  process of selling  its  Bridgeport  and New Haven
generating  stations in compliance with Connecticut's  electric utility industry
restructuring  legislation.  It is anticipated that environmental remediation of
contaminants will be required at each of the generating  station sites following
its sale.

(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 six months of 1998 was  $1,046,000.  UI's share of the fund at
June 30, 1998 was approximately $14.3 million.

     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 six months of 1998 was $244,000. UI's share of the fund at June
30,  1998 was  approximately  $5.9  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 June 30, 1998, $38.4 million has been expended for
decommissioning. The projected remaining decommissioning cost is $417.6 million,
of which UI's share would be $39.7 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 $1,178,000 were funded
by UI during  the first six  months of 1998,  and UI's share of the fund at June
30, 1998 was $25.4 million.


                                     - 15 -
<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 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.
By its terms,  the DPUC's 1996 order should be reopened in 1998 to determine the
regulatory  assets to be subjected  to  accelerated  recovery in 1999,  2000 and
2001.

     In April 1998,  Connecticut enacted Public Act 98-28, 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  suppliers,
for  delivery  over  the  wire  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  Connecticut's  restructuring  legislation  is  the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems  benefits"  charge,  an  "energy  conservation  and load  management"
assessment and a "renewable energy"  assessment,  representing 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 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,  above-market  investments in power plants (stranded  costs),  and the
costs of systems benefits and conservation  programs.  They will be recovered by
the Distribution  Companies from all consumers of electricity on a going-forward
basis,  commencing in 2000. Because it is expected that many fossil-fueled power
plants  may have  market  values  in excess of their  net  historic  costs,  the
restructuring  legislation requires that, in order for a Distribution Company to
recover the stranded costs associated


                                     - 16 -
<PAGE>

with its power plants,  its fossil-fueled  plants must be sold prior to 2000 and
the 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.

     On May 20, 1998,  the Company  announced that it would commence the process
of  selling,  through  a  two-stage  bidding  process,  all  of  its  nonnuclear
generation  assets in compliance  with the statute.  The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven,  Connecticut,  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  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. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective  purchasers of the
assets. The Company has commenced the second stage of the process,  during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare  final,  binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.

     Another requirement of the restructuring legislation is that, by October 1,
1998,  each  Distribution  Company  must  file,  for  the  DPUC's  approval,  an
"unbundling  plan" to  transfer  into  one or more  legally  separate  corporate
affiliates,  on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.

     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.

     The  Company  expects  that,  for  all  intents  and  purposes,   the  1998
restructuring legislation will take precedence over the 1996 order, beginning in
the year 2000.

     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 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.


                                     - 17 -
<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>    
Production (1)                           $7,800      $14,000       $4,500      $2,000       $2,500       $30,800
Distribution and Transmission            26,100       23,000       21,500      15,000       15,000       100,600
Other                                     3,300        3,400        1,000       1,000        1,000         9,700
                                         ------       ------       ------      ------       ------        ------
SUBTOTAL                                 37,200       40,400       27,000      18,000       18,500       141,100

Nuclear Fuel                              8,300          800        8,500       6,000        3,000        26,600
                                         ------         ----       ------      ------       ------       -------

  Total Expenditures                    $45,500      $41,200      $35,500     $24,000      $21,500      $167,700
                                        =======      =======      =======     =======      =======      ========

Rate Base and Other Selected Data:
---------------------------------
Depreciation
  Book Plant                             57,200       58,200       45,900      46,700       47,300
  Conservation Assets                    10,309        5,390            0           0            0
  Decommissioning                         2,700        2,800        2,900       3,000        3,100
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)                      1,106,000
</TABLE>

(1)    Reflects divestiture of fossil fueled generation plant in 1999. Remaining
       Production is nuclear generation plant, 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.

Note:  Capital  Expenditures and their effect on certain  capital-related  items
       are estimates  subject to change due to future events and conditions that
       may  be  substantially  different  than  those  used  in  developing  the
       projections.   In  particular,   the  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.



                                     - 18 -
<PAGE>

                         LIQUIDITY AND CAPITAL RESOURCES

     At June 30, 1998,  the Company had $15.0 million of cash and temporary cash
investments,  a decrease of $17.0 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                     35.0

       Net cash provided by (used in) financing activities:
       -   Financing activities, excluding dividend payments        (29.8)
       -   Dividend payments                                        (20.2)

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

       Cash invested in plant, including nuclear fuel               (10.5)
                                                                    -----

             Net Change in Cash                                     (17.0)
                                                                    -----

       Balance,  June 30, 1998                                      $15.0
                                                                    =====


     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                         114.0      120.0      89.0       90.0       95.0
                                                                  -----      -----     -----       ----      -----
         Subtotal                                                 146.0      120.0      89.0       90.0       95.0

Less:
Capital Expenditures                                               45.5       41.2      35.5       24.0       21.5
                                                                  -----      -----     -----       ----      -----

Cash Available to pay Debt Maturities and Redemptions             100.5       78.8      53.5       66.0       73.5

Less:
Maturities and Mandatory Redemptions                              104.2       69.6      70.4       75.3      100.3
Optional Redemptions                                              113.8         -         -          -         -
                                                                  -----      -----      ----       ----      -----

External Financing Requirements (Surplus)                        $117.5      $(9.2)    $16.9       $9.3      $26.8
                                                                  =====      =====     =====       ====      =====
</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.  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.   In  particular,  the  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.

                                     - 19 -
<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.

     The Company has a revolving credit  agreement with a group of banks,  which
currently  extends to December 9, 1998. 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
June 30, 1998, the Company had $35 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 June 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., 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.

                              RESULTS OF OPERATIONS

SECOND QUARTER OF 1998 VS. SECOND QUARTER OF 1997
-------------------------------------------------

     Earnings  for the  second  quarter of 1998 were $5.5  million,  or $.39 per
share (on both a basic and diluted basis), down $3.0 million, or $.22 per share,
from the  second  quarter  of 1997.  Excluding  one-time  items,  earnings  from
operations  were $8.4  million,  or $.60 per  share,  up $.18 per share from the
second quarter of 1997. The one-time items were:


                                     - 20 -
<PAGE>
                                   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)
--------------------------------------------------------------------------------
 1998 Quarter 2  Subsidiary reserve for agent collection shortfalls
                 and other potentially uncollectible  receivables         $(.21)
--------------------------------------------------------------------------------

     Retail  operating  revenues  increased  by about $3.2 million in the second
quarter of 1998 compared to the second quarter of 1997, offset by a $2.6 million
increase in retail fuel expense, for a retail sales margin (retail revenues less
retail fuel  expense and  revenue-based  taxes)  increase of $0.6  million.  The
principal components of the retail margin change include:
                                                                      $ millions
--------------------------------------------------------------------------------
 Revenues from: DPUC rate order                                           0.2
--------------------------------------------------------------------------------
   Other price changes                                                   (0.6)
--------------------------------------------------------------------------------
   Sales volume-weather/workday related                                    -
--------------------------------------------------------------------------------
   Sales decrease from Yale University cogeneration (0.5)%               (0.6)
--------------------------------------------------------------------------------
   Other "real" sales changes, up 3.1%                                    4.2
--------------------------------------------------------------------------------
   Fuel expense from:  Sales increase                                    (1.0)
--------------------------------------------------------------------------------
   Reduced nuclear unit availability                                       -
--------------------------------------------------------------------------------
   Unscheduled outage at Bridgeport Unit 3 (see Note)                    (1.2)
--------------------------------------------------------------------------------
   Fossil fuel price and other                                           (0.4)
--------------------------------------------------------------------------------

     Note:  Saltwater  contamination  caused a shutdown of the Bridgeport Harbor
Unit 3 generating  unit on May 22, 1998.  The unit is undergoing  repairs and is
expected  to return  to  service  in  mid-August  1998.  The  outage is  costing
approximately  $1.0 million per month for the purchase of replacement  power, as
indicated in the table above. The total maintenance  expense associated with the
outage is $0.8 million as shown below, all of it charged in June.

     Net wholesale sales margin (wholesale  revenue less wholesale fuel expense)
changed  only  slightly  in the second  quarter of 1998  compared  to the second
quarter  of  1997.  Other  operating  revenues,  which  include  NEPOOL  related
transmission revenues, increased by $1.1 million.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $3.6 million in the second quarter of 1998 compared to the
second  quarter of 1997.  The  principal  components  of these  expense  changes
include:
                                                                      $ millions
--------------------------------------------------------------------------------
  Connecticut Yankee Unit, preparing for decommissioning                (1.5)
--------------------------------------------------------------------------------
  Cogeneration and other purchases                                      (0.4)
--------------------------------------------------------------------------------
  Unscheduled outage at Bridgeport Unit 3                                0.8
--------------------------------------------------------------------------------
  Unscheduled outage and other expenses at Seabrook                      0.4
--------------------------------------------------------------------------------
  Millstone Unit 3                                                      (1.1)
--------------------------------------------------------------------------------
  Pension investment performance and changes to actuarial
    assumptions and methodologies                                       (1.5)
--------------------------------------------------------------------------------
  Personnel reductions                                                  (1.5)
--------------------------------------------------------------------------------
  Other                                                                  1.2
--------------------------------------------------------------------------------

     Depreciation  expense,  excluding  amortization  of  conservation  and load
management costs,  increased  slightly in the second quarter of 1998 compared to
the second quarter of 1997.

     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,  $3.3  million  of

                                     - 21 -
<PAGE>

accelerated  amortization,  reflecting  one  quarter  of  the  1998  accelerated
amortization  requirement  of the five-year  rate plan  implemented in 1997, was
recorded in the second quarter of 1998.

     Other net income decreased  slightly in the second quarter of 1998 compared
to the second quarter of 1997.  The Company's  largest  unregulated  subsidiary,
American Payment Systems (APS), earned about $126,000  (after-tax) in the second
quarter  of  1998,  before  one-time  charges,  compared  to a loss of  $185,000
(after-tax)  in the  second  quarter 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 $2.6
million in the second quarter of 1998 compared to the second quarter of 1997, as
a result of the Company's refinancing program and strong cash flow.

SIX MONTHS OF 1998 VS. SIX MONTHS OF 1997
-----------------------------------------

     Earnings for the first six months of 1998 were $14.4 million,  or $1.03 per
share (on both a basic and diluted basis), down $1.8 million, or $.12 per share,
from the first six  months of 1997.  Excluding  one-time  items and  accelerated
amortization due to one-time items, earnings from operations were $17.3 million,
or $1.24 per share,  up $.28 per share  from the first six  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)
--------------------------------------------------------------------------------
 1998 Quarter 2  Subsidiary reserve for agent collection shortfalls and
                 other potentially uncollectible receivables              $(.21)
--------------------------------------------------------------------------------

     Retail operating  revenues decreased by about $0.8 million in the first six
months of 1998  compared  to the first six months of 1997,  and retail  fuel and
energy  expense  increased by $3.2  million for a retail  sales  margin  (retail
revenues  less retail fuel  expense and  revenue-based  taxes)  decrease of $4.0
million. The principal components of the retail margin change include:

                                                                     $ millions
--------------------------------------------------------------------------------
  Revenues from:  DPUC rate order                                       (3.2)
--------------------------------------------------------------------------------
    Other price changes                                                 (2.4)
--------------------------------------------------------------------------------
    Sales volume-weather related (0.7) %                                (2.0)
--------------------------------------------------------------------------------
    Sales decrease from Yale University cogeneration (0.3)%             (0.7)
--------------------------------------------------------------------------------
    Other "real" sales changes, up 2.7 %                                 7.7
--------------------------------------------------------------------------------
    Fuel expense from:  Sales increase                                  (1.0)
--------------------------------------------------------------------------------
    Reduced nuclear unit availability                                   (1.0)
--------------------------------------------------------------------------------
    Unscheduled outage at Bridgeport Unit 3 (see Note)                  (1.2)
--------------------------------------------------------------------------------
    Fossil fuel price and other                                           -
--------------------------------------------------------------------------------

     Note:  Saltwater  contamination  caused a shutdown of the Bridgeport Harbor
Unit 3 generating  unit on May 22, 1998.  The unit is undergoing  repairs and is
expected  to return  to  service  in  mid-August  1998.  The  outage is  costing
approximately  $1.0 million per month for the purchase of replacement  power, as
shown in the table above.  The total  maintenance  expense  associated  with the
outage is $0.8 million as shown below, all of it charged in June.

     Net wholesale sales margin (wholesale  revenue less wholesale fuel expense)
increased  slightly  in the first six months of 1998  compared  to the first six
months  of  1997.  Other  operating  revenues,   which  include  NEPOOL  related
transmission revenues, increased by $1.7 million.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $10.4  million in the first six months of 1998 compared to
the first six months of 1997. The principal  components of these expense changes
include:

                                     - 22 -
<PAGE>
                                                                    $ millions
--------------------------------------------------------------------------------
  Connecticut Yankee Unit, preparing for decommissioning               (3.7)
--------------------------------------------------------------------------------
  Cogeneration and other purchases                                     (2.9)
--------------------------------------------------------------------------------
  Unscheduled outage at Bridgeport Unit 3                               0.8
--------------------------------------------------------------------------------
  Unscheduled outage and other expenses at Seabrook                     0.6
--------------------------------------------------------------------------------
  Millstone Unit 3                                                     (0.7)
--------------------------------------------------------------------------------
  Pension investment performance and changes to actuarial
    assumptions and methodologies                                      (2.9)
--------------------------------------------------------------------------------
  Personnel reductions                                                 (3.0)
--------------------------------------------------------------------------------
  Other                                                                 1.4
--------------------------------------------------------------------------------

     Depreciation  expense  increased by $0.6 million in the first six months of
1998 compared to the first six months of 1997.

     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,  $6.5  million  of  accelerated
amortization,   reflecting  one  half  of  the  1998  accelerated   amortization
requirements of the five-year rate plan implemented in 1997, was recorded in the
first six months of 1998.

     Other net income decreased by about $0.6 million in the first six months of
1998 compared to the first six months of 1997. The Company's largest unregulated
subsidiary, American Payment Systems (APS), earned about $287,000 (after-tax) in
the first six months of 1998,  before  one-time  charges,  compared to a loss of
$426,000  (after-tax) in the first six 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 $5.5
million  in the first six  months of 1998  compared  to the first six  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
-------------------

     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 DPUC, in the Order,  acknowledged  that the Order could be revisited in
the light of any new legislation.  In April 1998, Connecticut enacted Public Act
98-28,  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


                                     - 23 -
<PAGE>

the Company), each to be called an "electric distribution company" (Distribution
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  the  competing
suppliers,  for  delivery  over the wire  system  of the  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  Connecticut's  restructuring  legislation  is  the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems  benefits"  charge,  an  "energy  conservation  and load  management"
assessment and a "renewable energy"  assessment,  representing 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 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,  above-market  investments in power plants (stranded  costs),  and the
costs of systems benefits and conservation  programs.  They will be recovered by
the Distribution  Companies from all consumers of electricity on a going-forward
basis,  commencing in 2000. Because it is expected that many fossil-fueled power
plants  may have  market  values  in excess of their  net  historic  costs,  the
restructuring  legislation requires that, in order for a Distribution Company to
recover the stranded costs associated with its power plants,  its  fossil-fueled
plants must be sold prior to 2000, and the 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.

     Another requirement of the restructuring legislation is that, by October 1,
1998,  each  Distribution  Company  must  file,  for  the  DPUC's  approval,  an
"unbundling  plan" to  transfer  into  one or more  legally  separate  corporate
affiliates,  on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.

     On May 20, 1998,  the Company  announced that it would commence the process
of  selling,  through  a  two-stage  bidding  process,  all  of  its  nonnuclear
generation  assets in compliance  with the statute.  The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven,  Connecticut,  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  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. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective  purchasers of the
assets. The Company has commenced the second stage of the process,  during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare  final,  binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.

     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 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.

     The  Company  expects  that,  for  all  intents  and  purposes,   the  1998
restructuring  legislation will take precedence over the Order's  five-year rate
plan, beginning in the year 2000.

                                     - 24 -
<PAGE>

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  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 retail
sales margin (retail revenue less retail 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  gigawatt-hour  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. A similar level of growth in
1998 compared to 1997 from all customer  groups would add about $6-$8 million to
sales margin. Growth in "real" sales in the first six months of 1998 compared to
the first six months of 1997 was more than 2.0 percent, indicating the potential
for further real growth in future quarters. Such growth may be tempered by other
factors, however, some of which are noted below.

     Reductions in revenues could occur for several other  reasons.  The Company
has dealt with the potential  loss of customers as a result of  self-generation,
relocation  or  discontinuation   of  operations  by  successfully   negotiating
multi-year contracts with major customers.  Such 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),  commencing  in  mid-1998.  While  providing  cost  reduction  and price
stability for  customers and helping the Company  maintain its customer base for
the long term, these contracts are expected to cause future reductions in retail
revenues.  They reduced retail  revenues by about $3 million in 1997 compared to
1996,  but  are  not  expected  to  approach  that  level  of  change  in  1998.
Additionally,  rate  migration  (customers  switching  to  rates  that  are more
favorable because of usage patterns) reduced retail revenues by about $3 million
in 1997 compared to 1996;  but the impact of rate  migration on revenues in 1998
compared to 1997 is expected  to be less than $1 million.  Also,  as part of the
Order,  the  operation of the  Company's  long-standing  fossil fuel  adjustment
clause (FAC)  mechanism  that allowed for recovery in retail rates of changes in
fossil  fuel  costs  was  suspended  within a broad  range of fuel  prices.  FAC
revenues decreased by about $1.9 million,  to zero, in the first quarter of 1998
compared to the first quarter of 1997, due to this suspension of the FAC.

     To summarize, assuming that rates of "real" growth experienced in the first
six months of 1998  continue in the second half,  and assuming the expected loss
of sales due to Yale  University  cogeneration,  and more normal weather for the
last six months of 1998, some growth in retail  kilowatt-hour sales, perhaps 0.5
percent,  could occur in 1998 compared to 1997. 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 $2.5 million in 1998 under the sharing  mechanism.
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  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 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


                                     - 25 -
<PAGE>

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  prospects 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 first half
results.

     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 $8 million.  The
Seabrook unit went out of service on June 11, 1998 for unscheduled  repairs, but
resumed  generation  on July 11, 1998.  This outage should have little impact on
anticipated  operation and maintenance expense. The Seabrook unit should have no
refueling  outage during the remainder of 1998 and, if it operates at an assumed
95% availability  for the rest of the year (its  availability was virtually 100%
between  refueling outages in 1997), net fuel expense should decline by about $1
million.

     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 $400,000 per month for every month of  operation,  net of the
replacement  fuel provision of about $100,000 per  month...for a total reduction
of about $2.0 million for 1998 compared to 1997.

     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  increase  by as much as  $2.0-$3.0  million  over the
1998-99  period,  above the  original  $2.6  million  estimate  for  information
technology  systems.  This  increased  estimate  is  based on more  current  and
detailed information received 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 six months of 1998 compared to the
first six months of 1997 decreased by $5.5 million.

     Other factors  should  increase  costs.  Other  operation  and  maintenance
expense should  increase by about $7 million in 1998 compared to 1997 reflecting
increased fossil-fueled generating unit scheduled maintenance and provisions for
future outages. Base depreciation,  excluding accelerated  amortization,  should
increase  about $2.0  million.  Accelerated  amortization,  per the Order,  will
increase by about $7 million  (reflecting  a $3.3 million per quarter  increase,
except for a $3.1 million  decrease in the 1998 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  recognized 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


                                     - 26 -
<PAGE>

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.

     As  reported  in its  recent  filing  (Form  8-K) with the  Securities  and
Exchange Commission, an investigation of the accounting records of the Company's
largest  subsidiary,  American  Payment  Systems,  Inc.  (APS)  has  led  to the
creation,  in the second  quarter of 1998,  of  additional  reserves by APS, for
shortfalls in agent collections and other potentially  uncollectible receivables
that were incurred  prior to 1998, in the amount of $4.9 million.  This resulted
in a one-time  charge to the Company's  second quarter  earnings of $2.9 million
after-tax,  or $.21 per share of the  Company's  common  stock.  APS  accounting
procedures,  which  failed to  detect  the cash  flow  discrepancies,  have been
rectified.

Longer Term
-----------

     In addition to the effects of Connecticut's  1998 electric utility industry
restructuring  legislation  (see the  "Five-year  rate plan"  discussion  at the
beginning of the Looking Forward section),  there are several other matters that
will affect the longer-term outlook.

     The Connecticut  Yankee nuclear unit's expenses are expected to continue to
decline by substantial  amounts before leveling out at about $6 million per year
after  1998,  compared  to $11.8  million  in  1997,  until  decommissioning  is
complete.  However,  the  ability of the Company to recover  its  investment  in
Connecticut  Yankee and its ownership share of future costs  associated with the
retirement of the Connecticut  Yankee unit will be dependent upon the outcome of
pending regulatory filings with the Federal Energy Regulatory Commission.

     On August 7, 1997,  the Company and the other nine minority joint owners of
Millstone  Unit 3 that are not  subsidiaries  of Northeast  Utilities (NU) filed
lawsuits  against  NU and its  trustees,  as well as a  demand  for  arbitration
against  The  Connecticut  Light and Power  Company  and  Western  Massachusetts
Electric Company, the operating electric utility subsidiaries of NU that are the
majority  joint owners of the unit and have  contracted  with the minority joint
owners to operate it. The ten non-NU joint owners,  who together own about 19.5%
of the unit,  claim  that NU and its  subsidiaries  failed  to  comply  with NRC
regulations, failed to operate Millstone Station in accordance with good utility
operating  practice and concealed  their failures from the  non-operating  joint
owners and the NRC.  The  arbitration  and  lawsuits  seek to  recover  costs of
purchasing  replacement  power and  increased  operation and  maintenance  costs
resulting from the shutdown of Millstone Unit 3.

     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.  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 remediation,  retirement,  renovation
and testing program has commenced.  Necessary upgrades to mainframe hardware and
software  are expected to be completed  and tested  during 1998,  and a parallel
program  with  respect to  desktop  hardware  and  application  software  on all
platforms is currently  projected to be completed  and tested,  for all critical
systems,   by  March  31,  1999.  The  Company   believes  that  the  successful
implementation  of this  program,  currently  estimated to cost $2.6 million for
existing information systems,  will preclude any adverse impact of the Year 2000
Issue on its operations and financial  condition.  However,  embedded technology
remediation  may  increase  the  cost of this  program  by as much as  $2.0-$3.0
million over the 1998-99  period.  As more embedded  technology  vendor  product
information is received and  evaluated,  the extent of any such increase will be
determined. The Company is also identifying critical suppliers and other persons
with whom data must be exchanged  and is asking for assurance of their Year 2000
readiness.  Requests for documented readiness  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  external  risks  of  the  Year  2000  Issue  are  significantly
complicated  by  the  interdependence  of  the  utility  system  infrastructure,
particularly in the power grid and telecommunications  areas. UI has joined with
the other New England Power Pool participants


                                     - 27 -
<PAGE>

and with the regional Independent System Operator (ISO-New England) in a program
to ensure that the Year 2000 Issue in these areas is being adequately addressed.
Contingency  plans will be developed  for  replacing  critical  operational  and
information  systems,  if any,  for  which  Year  2000  readiness  has not  been
demonstrated  in a timely manner.  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  these   programs  and  their
implementation will succeed.

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, on June 30,  1998,  the City
agreed  to extend  to  August  31,  1998 the time  period  for  satisfying  this
condition  of the  settlement  in return  for a  payment  by the  Company  of $5
million.  The Company filed a second  application with the DPUC on July 9, 1998.
If the DPUC  authorization  is not  forthcoming,  the $5 million payment will be
applied to future tax bills.

                                     - 28 -
<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, on June 30, 1998, the
City  agreed to extend to August 31, 1998 the time  period for  satisfying  this
condition  of the  settlement  in return  for a  payment  by the  Company  of $5
million.  The Company filed a second  application with the DPUC on July 9, 1998.
If the DPUC  authorization  is not  forthcoming,  the $5 million payment will be
applied to future tax bills.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     The Annual Meeting of the Shareowners of the Registrant was held on May 20,
1998,  for the purpose of electing a Board of  Directors  for the ensuing  year,
voting on the employment,  by the Board of Directors, of Price Waterhouse LLP as
the firm of independent public accountants to audit the books and affairs of the
Registrant for the fiscal year 1998, and considering and acting on a proposal to
amend the Registrant's  Certificate of  Incorporation  relative to the number of
members of the Board of Directors.

                                     - 29 -
<PAGE>

     All of the nominees for  election as Directors  listed in the  Registrant's
proxy statement for the meeting were elected by the following votes:

                                                      NUMBER OF SHARES
                                           ----------------------------------
                                             VOTED                      NOT
           NOMINEE                           "FOR"                     VOTED
           -------                           -----                     -----

       Thelma R. Albright                  12,573,251                 173,602
       Marc C. Breslawsky                  12,585,923                 160,930
       David E. A. Carson                  12,589,837                 157,016
       John F. Croweak                     12,585,210                 161,643
       J. Hugh Devlin                      12,592,918                 153,935
       Robert L. Fiscus                    11,879,894                 866,959
       Richard J. Grossi                   11,890,717                 856,136
       Betsy Henley-Cohn                   12,571,418                 175,435
       John L. Lahey                       12,589,215                 157,638
       F. Patrick McFadden, Jr.            12,583,615                 163,238
       Frank R. O'Keefe, Jr.               12,573,342                 173,511
       James A. Thomas                     12,573,354                 173,499


     The employment of Price  Waterhouse  LLP as the firm of independent  public
accountants to audit the books and affairs of the Registrant for the fiscal year
1998 was approved by the following vote:

                                       NUMBER OF SHARES
                     ------------------------------------------------
                        VOTED               VOTED                NOT
                        "FOR"             "AGAINST"             VOTED
                        -----             ---------             -----

                     12,595,433             47,639             103,781


     The  proposal  to  amend  the  Registrant's  Certificate  of  Incorporation
relative to the number of members of the Board of Directors  was approved by the
following vote:

                                       NUMBER OF SHARES
                     -----------------------------------------------
                        VOTED               VOTED                NOT
                        "FOR"             "AGAINST"             VOTED
                        -----             ---------             -----

                     12,125,056            367,467             254,330


ITEM 5.  OTHER INFORMATION.

       See the  Company's  Current  Report  (Form  8-K),  dated  July 15,  1998,
regarding the creation of $4.9 million of  additional  reserves by the Company's
subsidiary  American Payment Systems,  Inc. and the resultant one-time charge to
the Company's  second quarter  earnings of $2.9 million  after-tax,  or $.21 per
share of the Company's common stock.


                                     - 30 -
<PAGE>

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

     (a) Exhibits.

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


<S>                  <C>          <C>                                                                
 (3)                  3.1d        Copy of  Certificate  Amending  Certificate of  Incorporation  by
                                  Actions of Board of Directors  and  Shareholders,  dated  May 28,
                                  1998.

 (3)                  3.2         Copy of Bylaws of The United Illuminating  Company, as amended to
                                  May 28, 1998.

(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
                                  June 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.

          Item             Financial
          Reported         Statements       Date of Report
          --------         ----------       --------------

              5              None           May 20, 1998
              5              None           July 15, 1998



                                     - 31 -
<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  8/13/98                  Signature      /s/ Robert L. Fiscus
    --------------                      ----------------------------------------
                                                  Robert L. Fiscus
                                        Vice Chairman of the Board of Directors
                                              and Chief Financial Officer



                                     - 32 -
<PAGE>




                                  EXHIBIT INDEX

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

<S>                   <C>         <C>                                                                 
 (3)                  3.1d        Copy of  Certificate  Amending  Certificate of  Incorporation  by
                                  Actions of Board of Directors  and  Shareholders,  dated  May 28,
                                  1998.

 (3)                  3.2         Copy of Bylaws of The United Illuminating  Company, as amended to
                                  May 28, 1998.

(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
                                  June 30,  1998 and Twelve Months Ended  December 31,  1997, 1996,
                                  1995, 1994 and 1993).

(27)                 27           Financial Data Schedule
</TABLE>