SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549


                                  FORM 10-Q/A-1

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

                 FOR THE QUARTERLY PERIOD ENDING JUNE 30, 1999

                                       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, 1999, was 14,334,922.

                                       1
<PAGE>



                                      INDEX

                          PART I. FINANCIAL INFORMATION

                                                                         PAGE
                                                                         NUMBER
                                                                         ------
Item 1.  Financial Statements.                                              4

         Consolidated Statement of Income for the three and six months
           ended June 30, 1999 and 1998.                                    4
         Consolidated Balance Sheet as of June 30, 1999 and
           December 31, 1998.                                               5
         Consolidated Statement of Cash Flows for the three and six
           months ended June 30, 1999 and 1998.                             7

         Notes to Consolidated Financial Statements.                        8
           -   Statement of Accounting Policies                             8
           -   Capitalization                                               8
           -   Rate-Related Regulatory Proceedings                         10
           -   Short-term Credit Arrangements                              13
           -   Income Taxes                                                14
           -   Supplementary Information                                   15
           -   Fuel Financing Obligations and Other Lease Obligations      16
           -   Commitments and Contingencies                               16
               -  Capital Expenditure Program                              16
               -  Nuclear Insurance Contingencies                          16
               -  Other Commitments and Contingencies                      16
                  - Connecticut Yankee                                     16
                  - Hydro-Quebec                                           17
                  - Environmental Concerns                                 17
                  - Site Decontamination, Demolition and Remediation Costs 18
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning     18
           -   Restatement of Financial Results                            19

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations.                                        20

           -   Major Influences on Financial Condition                     20
           -   Capital Expenditure Program                                 21
           -   Liquidity and Capital Resources                             22
           -   Subsidiary Operations                                       23
           -   Results of Operations                                       23
           -   Looking Forward                                             28

         SIGNATURES                                                        34


                                       2
<PAGE>

     This  amendment  to the  Quarterly  Report  on  Form  10-Q  of  The  United
Illuminating  Company (the  "Company")  for the quarter ended June 30, 1999 (the
"Original  Form 10-Q")  amends and modifies the Original  Form 10-Q by restating
Part I:  Financial  Information,  Item  I:  Financial  Statements  in  order  to
supplement  and revise the  "Consolidated  Statement  of Income",  "Consolidated
Statement of Cash Flows", "Consolidated Balance Sheet", and Notes (F) and (G) to
the  Notes  to  Consolidated   Financial  Statements,   and  to  add  Note  (Q),
"Restatement  of  Financial  Results"  to the  Notes to  Consolidated  Financial
Statements  and by restating  Item 2:  "Management's  Discussion and Analysis of
Financial  Condition and Results of Operations" in order to amend and supplement
the  sections  captioned,  "Liquidity  and Capital  Resources"  and  "Results of
Operations".



                                       3
<PAGE>
<TABLE>
<CAPTION>
                          PART I: FINANCIAL INFORMATION
                          ITEM I: FINANCIAL STATEMENTS
                         THE UNITED ILLUMINATING COMPANY
                        CONSOLIDATED STATEMENT OF INCOME
                      (THOUSANDS EXCEPT PER SHARE AMOUNTS)
                                   (UNAUDITED)

                                                                        Three Months Ended               Six Months Ended
                                                                             June 30,                        June 30,
                                                                        1999           1998            1999           1998
                                                                        ----           ----            ----           ----
<S>                                                                      <C>           <C>             <C>            <C>
OPERATING REVENUES (NOTE G)                                              $164,533      $159,792        $333,200       $322,266
                                                                    --------------  ------------    ------------  -------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                       38,483        33,412          72,382         73,953
     Capacity purchased                                                     8,678         8,978          17,740         15,200
     Other                                                                 36,761        38,094          75,515         71,403
  Maintenance                                                               6,013        10,560          15,459         21,593
  Depreciation                                                             15,618        20,632          33,357         41,438
  Amortization of cancelled nuclear project,
       deferred return and regulatory tax asset                             6,464         3,439          13,490          6,879
  Income taxes (Note F)                                                    15,851        11,193          31,376         22,680
  Other taxes (Note G)                                                     11,472        12,310          25,481         25,269
                                                                    --------------  ------------    ------------  -------------
       Total                                                              139,340       138,618         284,800        278,415
                                                                    --------------  ------------    ------------  -------------
OPERATING INCOME                                                           25,193        21,174          48,400         43,851
                                                                    --------------  ------------    ------------  -------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                         254            40             267             70
  Other-net (Note G)                                                       (2,380)          439          (2,849)           884
  Non-operating income taxes                                                1,748           905           2,639            988
                                                                    --------------  ------------    ------------  -------------
       Total                                                                 (378)        1,384              57          1,942
                                                                    --------------  ------------    ------------  -------------
INCOME BEFORE INTEREST CHARGES                                             24,815        22,558          48,457         45,793
                                                                    --------------  ------------    ------------  -------------
INTEREST CHARGES
  Interest on long-term debt                                               10,163        12,879          22,390         26,402
  Interest on Seabrook obligation bonds owned by the company               (1,711)       (1,818)         (3,422)        (3,636)
  Dividend requirement of mandatorily redeemable securities                 1,203         1,203           2,406          2,406
  Other interest (Note G)                                                     820         1,432           2,676          2,276
  Allowance for borrowed funds used during construction                      (323)         (135)           (771)          (264)
                                                                    --------------  ------------    ------------  -------------
                                                                           10,152        13,561          23,279         27,184
  Amortization of debt expense and redemption premiums                        677           618           1,291          1,268
                                                                    --------------  ------------    ------------  -------------
       Net Interest Charges                                                10,829        14,179          24,570         28,452
                                                                    --------------  ------------    ------------  -------------


NET INCOME                                                                 13,986         8,379          23,887         17,341
Premium (Discount) on preferred stock redemptions                              53           (21)             53            (21)
Dividends on preferred stock                                                   15            50              66            101
                                                                    --------------  ------------    ------------  -------------
INCOME APPLICABLE TO COMMON STOCK                                         $13,918        $8,350         $23,768        $17,261
                                                                    ==============  ============    ============  =============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                        14,049        14,021          14,045         14,004
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                      14,050        14,024          14,047         14,011

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                      $0.99         $0.60           $1.69          $1.23

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.

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

                                           ASSETS
                                   (Thousands of Dollars)

                                                             June 30,          December 31,
                                                               1999               1998*
                                                               ----               ----
                                                            (Unaudited)
<S>                                                            <C>                <C>
Utility Plant at Original Cost
  In service                                                   $1,512,288         $1,886,930
  Less, accumulated provision for depreciation                    517,889            714,375
                                                          ----------------    ---------------
                                                                  994,399          1,172,555

Construction work in progress                                      30,495             33,695
Nuclear fuel                                                       23,823             20,174
                                                          ----------------    ---------------
     Net Utility Plant                                          1,048,717          1,226,424
                                                          ----------------    ---------------


Other Property and Investments
  Investment in generation facility                                75,439                        -
  Nuclear decommissioning trust fund assets                        25,973             23,045
  Other                                                            18,215             14,828
                                                          ----------------    ---------------
                                                                  119,627             37,873
                                                          ----------------    ---------------

Current Assets
  Unrestricted cash and temporary cash investments                 23,180             97,689
  Restricted cash                                                  28,045             26,812
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                                 59,790             54,178
   Other, less allowance for doubtful accounts
     of $864 and $545                                              48,093             64,240
  Accrued utility revenues                                         25,892             21,079
  Fuel, materials and supplies, at average cost                     7,846             33,613
  Prepayments                                                       3,662              7,424
  Other                                                               409                154
                                                          ----------------    ---------------
     Total                                                        196,917            305,189
                                                          ----------------    ---------------

Deferred Charges
  Unamortized debt issuance expenses                                8,704              9,421
  Other                                                             1,962              1,664
                                                          ----------------    ---------------
     Total                                                         10,666             11,085
                                                          ----------------    ---------------

Regulatory Assets (future amounts due from customers
                   through the ratemaking process)
  Income taxes due principally to book-tax differences            199,845            264,811
  Connecticut Yankee                                               39,397             42,633
  Deferred return - Seabrook Unit 1                                 6,293             12,586
  Unamortized redemption costs                                     22,900             23,468
  Unamortized cancelled nuclear projects                           10,366             10,952
  Uranium enrichment decommissioning cost                           1,108              1,177
  Other                                                            20,279              4,962
                                                          ----------------    ---------------
     Total                                                        300,188            360,589
                                                          ----------------    ---------------

                                                               $1,676,115         $1,941,160
                                                          ================    ===============
</TABLE>

*Derived from audited financial statements

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

                                       5
<PAGE>
<TABLE>
<CAPTION>
                         THE UNITED ILLUMINATING COMPANY
                           CONSOLIDATED BALANCE SHEET

                         CAPITALIZATION AND LIABILITIES
                             (Thousands of Dollars)

                                                                   June 30,         December 31,
                                                                     1999              1998*
                                                                     ----              ----
                                                                 (Unaudited)
<S>                                                                <C>                <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                    $292,006           $292,006
    Paid-in capital                                                    2,140              2,046
    Capital stock expense                                             (2,171)            (2,182)
    Unearned employee stock ownership plan equity                     (9,735)           (10,210)
    Retained earnings                                                167,378            163,847
                                                              ---------------    ---------------
                                                                     449,618            445,507
  Preferred stock                                                                   -     4,299
  Company-obligated mandatorily redeemable securities
   of subsidiary holding solely parent debentures                     50,000             50,000
  Long-term debt
    Long-term debt                                                   605,604            757,370
    Investment in Seabrook obligation bonds                          (87,413)           (92,860)
                                                              ---------------    ---------------
      Net long-term debt                                             518,191            664,510
                                                              ---------------    ---------------

          Total                                                    1,017,809          1,164,316
                                                              ---------------    ---------------

Noncurrent Liabilities
  Connecticut Yankee contract obligation                              29,151             32,711
  Pensions accrued (Note H)                                           25,948             31,097
  Nuclear decommissioning obligation                                  25,973             23,045
  Obligations under capital leases                                    16,322             16,506
  Other                                                                6,185              6,622
                                                              ---------------    ---------------
          Total                                                      103,579            109,981
                                                              ---------------    ---------------

Current Liabilities
  Current portion of long-term debt                                    6,806             66,202
  Notes payable                                                       48,684             86,892
  Accounts payable                                                    36,740             48,749
  Accounts payable - APS utility customers                            49,662             54,515
  Dividends payable                                                   10,115             10,155
  Taxes accrued                                                       48,936              9,015
  Interest accrued                                                    16,616             10,203
  Obligations under capital leases                                       361                348
  Other accrued liabilities                                           27,869             39,845
                                                              ---------------    ---------------
          Total                                                      245,789            325,924
                                                              ---------------    ---------------

Customers' Advances for Construction                                   1,867              1,867
                                                              ---------------    ---------------

Regulatory Liabilities (future amounts owed to customers
                        through the ratemaking process)
  Accumulated deferred investment tax credits                         15,242             15,623
  Deferred gain on sale of property                                   15,708                  4
  Other                                                                8,679              2,061
                                                              ---------------    ---------------
          Total                                                       39,629             17,688
                                                              ---------------    ---------------

Deferred Income Taxes (future tax liabilities owed                   267,442            321,384
                       to taxing authorities)
Commitments and Contingencies (Note L)
                                                              ---------------    ---------------
                                                                  $1,676,115         $1,941,160
                                                              ===============    ===============
</TABLE>

* Derived from audited financial statements

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

                                       6
<PAGE>
<TABLE>
<CAPTION>
                         THE UNITED ILLUMINATING COMPANY
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                             (THOUSANDS OF DOLLARS)
                                   (UNAUDITED)

                                                                     Three Months Ended            Six Months Ended
                                                                          June 30,                      June 30,
                                                                    1999            1998          1999           1998
                                                                    ----            ----          ----           ----
<S>                                                                  <C>             <C>          <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                          $13,986         $8,379       $23,887         $17,341
                                                                --------------  -------------  ------------  --------------
  Adjustments to reconcile net income to net cash provided by
    operating activities:
     Depreciation and amortization                                     19,252         21,897        41,718          43,748
     Deferred income taxes                                              4,547         (1,011)        3,815          (3,262)
     Deferred income taxes - generation asset sale                    (70,222)             -       (70,222)              -
     Deferred investment tax credits - net                               (191)          (191)         (381)           (381)
     Amortization of nuclear fuel                                       1,489          1,232         4,680           2,497
     Allowance for funds used during construction                        (577)          (175)       (1,038)           (334)
     Amortization of deferred return                                    3,146          3,146         6,293           6,293
     Changes in:
             Accounts receivable - net                                   (578)       (14,727)       10,535         (10,569)
             Fuel, materials and supplies                                 639         (7,794)          212         (11,562)
             Prepayments                                                8,806         (3,113)        3,762          (6,081)
             Accounts payable                                          15,619         12,127       (16,862)         (2,691)
             Interest accrued                                           2,508          5,389         6,413           7,917
             Taxes accrued                                             (9,615)       (10,000)        4,810           1,920
             Taxes accrued - generation asset sale                     35,111              -        35,111               -
             Other assets and liabilities                             (26,915)         3,987       (36,733)          1,195
                                                                --------------  -------------  ------------  --------------
     Total Adjustments                                                (16,981)        10,767        (7,887)         28,690
                                                                --------------  -------------  ------------  --------------
NET CASH PROVIDED BY OPERATING ACTIVITIES                              (2,995)        19,146        16,000          46,031
                                                                --------------  -------------  ------------  --------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Common stock                                                           269            295           569           4,310
   Long-term debt                                                           -              -             -          99,780
   Notes payable                                                      (33,488)        73,705       (38,208)         81,074
   Securities redeemed and retired:
     Preferred stock                                                   (4,299)           (52)       (4,299)            (52)
     Long-term debt                                                  (125,000)       (80,000)     (211,202)       (213,976)
   Discount (Premium) on preferred stock redemption                       (53)            21           (53)             21
   Expense of issue                                                         -              -             -            (800)
   Lease obligations                                                      (86)           (84)         (171)           (166)
   Dividends
     Preferred stock                                                      (65)           (51)         (116)           (102)
     Common stock                                                     (10,111)       (10,090)      (20,215)        (20,090)
                                                                --------------  -------------  ------------  --------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                  (172,833)       (16,256)     (273,695)        (50,001)
                                                                --------------  -------------  ------------  --------------

CASH FLOWS FROM INVESTING ACTIVITIES
    Investment in unregulated businesses                              (75,092)             -       (75,092)              -
    Net cash received from sale of generation assets                  270,590              -       270,590               -
    Plant expenditures, including nuclear fuel                        (10,742)        (2,213)      (16,526)        (10,569)
    Investment in debt securities                                           -              -         5,447           8,528
                                                                --------------  -------------  ------------  --------------
NET CASH PROVIDED BY (USED IN) ACTIVITIES                             184,756         (2,213)      184,419          (2,041)
                                                                --------------  -------------  ------------  --------------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                               8,928            677       (73,276)         (6,011)
BALANCE AT BEGINNING OF PERIOD                                         42,297         46,377       124,501          53,065
                                                                --------------  -------------  ------------  --------------
BALANCE AT END OF PERIOD                                               51,225         47,054        51,225          47,054
LESS: RESTRICTED CASH                                                  28,045         34,675        28,045          34,675
                                                                                               ------------  --------------
                                                                ==============  =============  ============  ==============
BALANCE: UNRESTRICTED CASH                                            $23,180        $12,379       $23,180         $12,379
                                                                ==============  =============  ============  ==============

CASH PAID DURING THE PERIOD FOR:
   Interest (net of amount capitalized)                                $8,177         $8,824       $14,483         $19,450
                                                                ==============  =============  ============  ==============
   Income taxes                                                       $54,250        $20,150       $57,950         $23,050
                                                                ==============  =============  ============  ==============
</TABLE>

 Note:      Cash Flows from  Operating  Activities  for the three and six months
            ended June 30, 1999 were  reduced by the current  income tax effects
            of the generation asset sale in the amount of $35,111.

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

                                       7
<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 for a fair
presentation 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, 1998.  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
1999 and 1998 was 7.0% and 8.0% on a before-tax basis.

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 $1,950,000 and $1,290,000 in the first six
months of 1999 and 1998, respectively,  into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 1999, the Company's  shares of
the trust fund balances,  which included accumulated earnings on the funds, were
$18.7  million  and $7.3  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.

COMPREHENSIVE INCOME

     Comprehensive  income  for the six months  ended June 30,  1999 and 1998 is
equal to net income as reported.

(B)  CAPITALIZATION

     (a) COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding  at June 30, 1999, of which 286,389 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


                                       8
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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, 1999.  No options were  exercised  during the
first six months of 1999.

     On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the  awarding of options to purchase up to 650,000  shares of the  Company's
common stock over periods of from one to ten years  following the dates when the
options are granted.  The exercise  price of each option cannot be less than the
market  value of the  stock  on the date of the  grant.  On June 28,  1999,  the
Company's  shareowners  approved the plan. Options to purchase 137,000 shares of
stock at an exercise  price of $43 7/32 per share have been granted by the Board
of  Directors  and  remained  outstanding  at June 30,  1999.  No  options  were
exercisable during the second quarter of 1999.

     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, 1999, 286,389 shares, with a fair market value of $12.2
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 $200 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
$109.2 million were free from such limitations at June 30, 1999.

     (c) PREFERRED STOCK

     On April 8, 1999,  the Company  called for  redemption all 10,370 shares of
its  outstanding  $100 par value  4.35%  Preferred  Stock,  Series A, all 17,158
shares of its outstanding  $100 par value 4.72% Preferred  Stock,  Series B, all
12,745 shares of its outstanding $100 par value 4.64% Preferred Stock,  Series C
and all 2,712 shares of its outstanding  $100 par value 5 5/8% Preferred  Stock,
Series D. The Company  paid a redemption  premium of $53,355 in effecting  these
redemptions, which were completed on May 14, 1999.

     (e) LONG-TERM DEBT

     On February 1, 1999, the Company  converted $7.5 million  principal  amount
Connecticut  Development Authority Bonds from a weekly reset mode to a five-year
multiannual  mode.  The  interest  rate on the  Bonds for the  five-year  period
beginning  February  1, 1999 is 4.35% and  interest  will be paid  semi-annually
beginning  on August 1, 1999.  In  addition,  on February  1, 1999,  the Company
converted $98.5 million principal amount Business Finance Authority of the State
of New  Hampshire  Bonds from a weekly  reset mode to a  multiannual  mode.  The
interest  rate on $27.5  million  principal  amount  of the Bonds is 4.35% for a
three-year  period beginning  February 1, 1999. The interest rate on $71 million
principal amount of the Bonds is 4.55% for a five-year  period.  Interest on the
Bonds will be paid semi-annually beginning on August 1, 1999.

     On March 8, 1999,  the Company  prepaid and  terminated  $20 million of the
remaining  $70  million  outstanding  debt  under  its $150  million  Term  Loan
Agreement  dated August 29, 1995.  On April 16,  1999,  the Company  prepaid and
terminated  the entire  remaining $50 million  outstanding  debt under said $150
million Term Loan Agreement,  and the entire $75 million  outstanding debt under
its Term Loan Agreement dated October 25, 1996.



                                       9
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(C) RATE-REGULATED REGULATORY PROCEEDINGS

     In April  1998,  Connecticut  enacted  Public Act 98-28 (the  Restructuring
Act),  a massive  and  complex  statute  designed  to  restructure  the  State's
regulated  electric utility  industry.  The business of generating and supplying
electricity  directly  to  consumers  will be  price-deregulated  and  opened to
competition  beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution  business. The business of delivering
electricity  will  remain  with  the  incumbent   franchised  utility  companies
(including  the  Company),  which will  continue to be  regulated by the DPUC as
Distribution  Companies.  Beginning in 2000, each retail consumer of electricity
in Connecticut  (excluding  consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity  from among  competing
licensed  suppliers,  for  delivery  over the  wires  system  of the  franchised
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,  and has now reopened
its  proceeding to consider the amount of the generation  services  charge to be
included on consumers' bills.

     A  major  component  of  the  Restructuring  Act  is  the  collection,   by
Distribution  Companies,  of a "competitive  transition  assessment," a "systems
benefits  charge," a  "conservation  and load  management  program charge" and a
"renewable energy investment charge". The competitive transition assessment will
recover  stranded  costs  that  have  been  reasonably  incurred  by, or will be
incurred by, Distribution  Companies to meet their public service obligations as
electric  companies,  and that will likely not  otherwise  be  recoverable  in a
competitive  generation  and supply  market.  These costs  include  above-market
long-term  purchased power contract  obligations,  regulatory asset recovery and
above-market investments in power plants. The systems benefits charge represents
public policy costs,  such as generation  decommissioning  and displaced  worker
protection  costs.  Beginning in 2000, a  Distribution  Company must collect the
competitive transition assessment, the systems benefits charge, the conservation
and load management  program charge and the renewable energy  investment  charge
from all Distribution  Company customers,  except customers taking service under
special  contracts  pre-dating the Restructuring  Act. The Distribution  Company
will also be  required  to offer a  "standard  offer"  rate that is,  subject to
certain adjustments, at least 10% below its fully bundled prices for electricity
at rates in effect  during 1996,  as  discussed  below.  The  standard  offer is
required, subject to certain adjustments, to be the total rate charged under the
standard offer,  including the generation services  component,  transmission and
distribution charge, the competitive transition assessment, the systems benefits
charge,  the conservation  and load management  program charge and the renewable
energy investment charge.

     The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants,  its  fossil-fueled
generating  plants must be sold prior to 2000, with any net excess proceeds used
to mitigate  its  recoverable  stranded  costs,  and the Company must attempt to
divest its ownership interest in its nuclear-fueled  power plants prior to 2004.
By October 1, 1998,  each  Distribution  Company was  required to file,  for the
DPUC's approval, an "unbundling plan" to separate, on or before October 1, 1999,
all of its  power  plants  that  will not have  been  sold  prior to the  DPUC's
approval of the unbundling plan or will not be sold prior to 2000.

      In May of 1998,  the Company  announced  that it would  commence  selling,
through a two-stage bidding process,  all of its non-nuclear  generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its  operating  fossil-fueled  generating  stations,  Bridgeport
Harbor  Station and New Haven Harbor  Station,  to  Wisvest-Connecticut,  LLC, a
single-purpose  subsidiary  of Wisvest  Corporation.  Wisvest  Corporation  is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin. On
February 24, 1999,  the Federal  Energy  Regulatory  Commission  issued an order
authorizing the sale, on March 5, 1999, the DPUC issued a decision approving the
sale; and the sale was completed on April 16, 1999.



                                       10
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

      The Company received  approximately  $277.9 million in cash from this sale
of its  operating  fossil-fueled  generating  stations.  The Company  realized a
before-tax book gain of $86.5 million, or $16.2 million after-tax, from the sale
of these plant investments. However, under the Restructuring Act, this gain will
be  offset  by  a  writedown  of  above-market  generation  costs  eligible  for
collection by the Company under the Restructuring  Act's competitive  transition
assessment,  such as regulated plant costs and tax-related  regulatory assets or
other costs related to the restructuring transition,  such that there will be no
net income  effect of the sale.  The Company used the net cash proceeds from the
sale to reduce debt.

      On October 1, 1998,  in its  "unbundling  plan" filing with the DPUC under
the  Restructuring  Act, the Company  stated that it plans to divest its nuclear
generation  ownership  interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone  Station Unit No. 3 in  Connecticut)  by the end of 2003, in
accordance with the Restructuring  Act. The divestiture  method has not yet been
determined.  In anticipation of ultimate  divestiture,  the Company  proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating  assets be separated from its transmission  and distribution  assets.
This would be accomplished by transferring the nuclear  generating assets into a
separate new division of the Company,  using divisional financial statements and
accounting  to  segregate  all  revenues,   expenses,   assets  and  liabilities
associated with nuclear ownership  interests.  In a decision dated May 19, 1999,
the DPUC approved the Company's proposal in this regard.

      The  Company's  unbundling  plan also  proposes  to  separate  its ongoing
regulated transmission and distribution  operations and functions,  that is, the
Distribution  Company  assets  and  operations,  from  all  of  its  unregulated
operations  and  activities.  This would be achieved by  undergoing  a corporate
restructuring into a holding company structure. In the holding company structure
proposed,  the  Company  will  become a  wholly-owned  subsidiary  of a  holding
company,  and each share of the common  stock of the Company  will be  converted
into a share of common  stock of the holding  company.  In  connection  with the
formation of the holding company  structure,  all of the Company's  interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company  and,  to  the  extent  new  businesses  are  subsequently  acquired  or
commenced,  they will also be  financed  and owned by the  holding  company.  An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate  unbundling plan and corporate
restructuring  commenced on February 18, 1999. In a decision dated May 19, 1999,
the DPUC approved the proposed corporate  restructuring.  The proposed corporate
restructuring  is  also  subject  to  approval  by the  Company's  common  stock
shareowners  and by the Federal  Energy  Regulatory  Commission  and the Nuclear
Regulatory Commission.

      On March 24, 1999,  the Company  applied to the DPUC for a calculation  of
the Company's  stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999,  the DPUC  determined  that the Company's  stranded  costs
total $801.3  million,  consisting of $160.4 million of  above-market  long-term
purchased  power  contract  obligations,  $153.3  million of  generation-related
regulatory  assets  (net of  related  tax and  accounting  offsets),  and $487.6
million of above-market  investments in nuclear  generating  units (net of $26.4
million  of gains  from  generation  asset  sales and other  offsets  related to
generation assets).  The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act.

      Under the Restructuring  Act, 35% of the Company's  customers will be able
to choose their power supply  providers on and after January 1, 2000, and all of
the Company's  customers will be able to choose their power supply  providers as
of July 1, 2000. On and after January 1, 2000 and through December 31, 2003, the
Company  will be  required  to offer  fully-bundled  "standard  offer"  electric
service,  under regulated rates, to all customers who do not choose an alternate
power supply provider.  The standard offer rates will include the  fully-bundled
price of generation,  transmission  and distribution  services,  the competitive
transition  assessment,  the systems benefits charge and the conservation,  load
management and renewable energy charges. The fully-bundled  standard offer rates
must


                                       11
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

be at least 10% below the average  fully-bundled prices in 1996. The Company has
already delivered about 4.8% of this decrease, in bill reductions through 1998.

     In March of 1999,  the DPUC  commenced a proceeding  to determine  what the
Company's  standard  offer rates should be. In April,  May and June of 1999, the
Company filed descriptive material,  data and supporting testimony with the DPUC
setting forth the Company's  overall  approach for determining the components of
its standard  offer  rates,  and for  continuation  of the  five-year  Rate Plan
ordered by the DPUC in its 1996 financial and operational  review of the Company
(see below) through the four-year  standard offer period.  On July 27, 1999, the
Company and Enron Capital & Trade Resources Corp.  (Enron) filed with the DPUC a
joint stipulation and settlement  proposal to resolve  simultaneously all of the
issues in the Company's standard offer rate proceeding. The proposal includes an
arrangement  between  the  Company  and Enron  with  respect  to the  generation
services  needed by the Company to meet its standard offer  obligations  for the
four-year  standard  offer  period,  and an assumption by Enron of the Company's
long-term purchased power contract  obligations.  The stipulation and settlement
proposal also provides for the Company's standard offer rates at a fully-bundled
level that complies with the 10% reduction  required by the  Restructuring  Act,
including  the  generation  services  component  of these rates,  the  Company's
stranded  costs for  purposes of future  recovery,  the  competitive  transition
assessment,  systems benefits charge,  delivery  (transmission and distribution)
charges,  and  conservation,  load management and renewable energy charges.  The
Company also requests that a purchased power adjustment clause authorized by the
Restructuring  Act be put in place to adjust  standard  offer  rates for limited
purposes,   and  that  the  Company's  five-year  Rate  Plan,  as  modified  and
supplemented by the stipulation and settlement proposal, be continued during the
four-year  standard offer period.  UI believes that the global  stipulation  and
settlement   proposal  (i)  effectuates  the  Company's   standard  offer  power
procurement  in a manner  that will  assure  the  Company's  customers  reliable
standard offer  generation  services,  (ii) provides a fair standard offer power
supply  component  that will enable  retail  generation  suppliers to compete to
serve end-use customers,  (iii) buys out the Company's power purchase agreements
on a satisfactory basis, (iv) resolves a potentially contentious adjudication of
the Company's recoverable stranded costs, and (v) clears the way for the Company
to  focus  on the  energy  delivery  business,  including  the new  complexities
associated with the onset of retail competition.

FIVE-YEAR RATE PLAN
-------------------

      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 Rate Plan).  The DPUC did not change the existing
base rates  charged to retail  customers,  but did provide  for retail  customer
price  reductions of about 5% compared to 1996 and phased-in over 1997-2001;  3%
in 1997  compared  to 1996,  an  additional  1% in 2000 and  another  1% in 2001
compared  to 1996.  The price  reductions  are  accomplished  primarily  through
reductions of conservation adjustment mechanism revenues, through a surcredit in
each of the five plan years, and through acceptance of the Company's proposal to
modify the  operation  of the fossil fuel clause  mechanism.  The Rate Plan also
increased amortization of the Company's conservation and load management program
investments  during  1997-1998,  and  accelerated the  amortization  recovery of
unspecified  assets during  1999-2001 if the Company's  return on utility common
stock  equity  exceeds  10.5%,   on  an  annual  basis,   after   recording  the
amortization.  The specified  accelerated  amortizations  for  1999-2001,  on an
after-tax   basis,   are  $12.1  million,   $29.7  million  and  $32.8  million,
respectively.  The Company's  authorized  return on utility  common stock equity
under the Rate Plan is 11.5%, on an annual basis. Earnings above 11.5% are to be
"shared" by utilizing one-third for retail customer price reductions,  one-third
for increased  amortization  of  regulatory  assets,  and one-third  retained as
earnings.

     The Rate Plan had  significant  impacts  on the  Company's  1998  financial
results. Retail customer prices actually decreased by approximately 4.8% in 1998
compared  to  1996.  Also in  1998,  all of the  increased  amortization  of the
Company's conservation and load management program investments prescribed by the
Rate Plan were  recorded.  No "shared"  earnings  were  recorded in 1998 because
one-time  items reduced the Company's  return on utility  common stock equity to
less than 11.5%,  although earnings from operations,  excluding  one-time items,
would have


                                       12
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

been above  11.5% and  "sharing"  would have  occurred  based on  earnings  from
operations alone. See "Results of Operations" for a more complete  discussion of
these results.

     The Rate Plan was  reopened  in 1998,  in  accordance  with its  terms,  to
determine the assets to be subjected to accelerated  recovery in 1999,  2000 and
2001.  The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory  tax assets will be subjected to  accelerated  recovery in 1999.  The
DPUC has not yet  determined  the assets to be subjected to recovery after 1999.
The Rate Plan also  includes a provision  that it may be reopened  and  modified
upon the enactment of electric utility restructuring  legislation in Connecticut
and, as a consequence of the 1998  Restructuring  Act described  above, the Rate
Plan  may  be  reopened  and  modified.  However,  aside  from  implementing  an
additional  price  reduction in 2000 to achieve the minimum  aggregate 10% price
reduction  compared to 1996 required by the  Restructuring  Act and the probable
reductions  in the  accelerated  amortizations  scheduled in the Rate Plan,  the
Company is unable to predict, at this time, in what other respects the Rate Plan
may be modified on account of this legislation.

(E)  SHORT-TERM CREDIT ARRANGEMENTS

     The Company has a revolving credit  agreement with a group of banks,  which
currently  extends to December 8, 1999. The borrowing  limit of this facility is
$75 million.  The facility  permits the Company to borrow funds at a fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
June 30, 1999, the Company had $46 million in short-term borrowings  outstanding
under this facility.

     In  addition,   as  of  June  30,  1999,  one  of  the  Company's  indirect
subsidiaries,  American  Payment  Systems,  Inc., had borrowings of $2.6 million
outstanding under a bank line of credit agreement.


                                       13
<PAGE>
<TABLE>
<CAPTION>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


                                                                      Three Months Ended            Six Months Ended
(F) INCOME  TAXES                                                           June 30,                     June 30,
                                                                      1999          1998            1999          1998
                                                                      ----          ----            ----          ----
<S>                                                                   <C>          <C>              <C>          <C>
Income tax expense consists of:                                       (000's)      (000's)          (000's)      (000's)

Income tax provisions:
  Current
              Federal                                                  $63,457        $8,907         $75,794       $19,626
              State                                                     16,512         2,583          19,731         5,709
                                                                   ------------  ------------    ------------  ------------
                 Total current                                          79,969        11,490          95,525        25,335
                                                                   ------------  ------------    ------------  ------------
  Deferred
              Federal                                                  (51,490)         (591)        (51,644)       (2,142)
              State                                                    (14,185)         (420)        (14,763)       (1,120)
                                                                   ------------  ------------    ------------  ------------
                 Total deferred                                        (65,675)       (1,011)        (66,407)       (3,262)
                                                                   ------------  ------------    ------------  ------------

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

     Total income tax expense                                          $14,103       $10,288         $28,737       $21,692
                                                                   ============  ============    ============  ============

Income tax components charged as follows:
  Operating expenses                                                   $15,851       $11,193         $31,376       $22,680
  Other income and deductions - net                                     (1,748)         (905)         (2,639)         (988)
                                                                   ------------  ------------    ------------  ------------

     Total income tax expense                                          $14,103       $10,288         $28,737       $21,692
                                                                   ============  ============    ============  ============


The following table details the components of the deferred
   income taxes:
     Tax gain on sale of generation assets                            ($70,222)          -          ($70,222)          -
     Seabrook sale/leaseback transaction                                (2,082)       (2,180)         (4,164)       (4,361)
     Pension benefits                                                      580           383           2,105           983
     Accelerated depreciation                                            1,250         1,534           2,500         3,068
     Tax depreciation on unrecoverable plant investment                  1,186         1,212           2,374         2,424
     Unit overhaul and replacement power costs                           3,116           860           2,218           462
     Conservation and load management                                     (872)       (2,006)         (1,745)       (4,013)
     Postretirement benefits                                              (265)         (106)           (698)         (208)
     Displaced worker protection costs                                   2,215               -         2,215               -
     Other - net                                                          (581)         (708)           (990)       (1,617)
                                                                   ------------  ------------    ------------  ------------

Deferred income taxes - net                                           ($65,675)      ($1,011)       ($66,407)      ($3,262)
                                                                   ============  ============    ============  ============
</TABLE>

                                       14
<PAGE>
<TABLE>
<CAPTION>
                                THE UNITED ILLUMINATING COMPANY

                          NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION


                                                        Three Months Ended             Six Months Ended
                                                             June 30,                      June 30,
                                                        1999          1998           1999           1998
                                                        ----          ----           ----           ----
                                                        (000's)      (000's)         (000's)      (000's)

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

    Retail                                              $155,538      $149,222       $307,929       $295,767
    Wholesale                                              5,676         8,446         19,269         23,261
    Other                                                  3,319         2,124          6,002          3,238
                                                     ------------  ------------   ------------  -------------
         Total Operating Revenues                       $164,533      $159,792       $333,200       $322,266
                                                     ============  ============   ============  =============

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

    Retail
    Residential                                          443,304       420,484        977,072        908,813
    Commercial                                           591,114       566,975      1,144,912      1,131,764
    Industrial                                           292,199       292,989        561,259        558,617
    Other                                                 11,850        11,848         24,049         24,021
                                                     ------------  ------------   ------------  -------------
                                                       1,338,467     1,292,296      2,707,292      2,623,215
    Wholesale                                            205,837       255,472        858,583        763,789
                                                     ------------  ------------   ------------  -------------
         Total Sales by Class                          1,544,304     1,547,768      3,565,875      3,387,004
                                                     ============  ============   ============  =============


Depreciation
------------
    Plant in Service                                     $11,916       $14,331        $26,571        $28,661
    Amortization Conservation and
           Load Management Costs                           2,418         5,656          4,836         11,313
    Nuclear Decommissioning                                1,284           645          1,950          1,464
                                                     ------------  ------------   ------------  -------------
                                                         $15,618       $20,632        $33,357        $41,438
                                                     ============  ============   ============  =============
Other Taxes
-----------

    Charged to:
    Operating:
       State gross earnings                               $5,898        $5,550        $11,752        $11,171
       Local real estate and personal property             4,349         5,419         10,675         10,901
       Payroll taxes                                       1,225         1,341          3,054          3,197
                                                     ------------  ------------   ------------  -------------
                                                          11,472        12,310         25,481         25,269
    Nonoperating and other accounts                          158           145            292            293
                                                     ------------  ------------   ------------  -------------
         Total Other Taxes                               $11,630       $12,455        $25,773        $25,562
                                                     ============  ============   ============  =============

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

    Interest income                                         $462          $340         $1,129           $660
    Equity earnings from Connecticut Yankee                  143           218            324            525
    Earnings (Loss) from subsidiary companies             (2,314)          177         (3,520)           372
    Miscellaneous other income and (deductions) - net       (671)         (296)          (782)          (673)
                                                     ------------  ------------   ------------  -------------
         Total Other Income and (Deductions) - net       ($2,380)         $439        ($2,849)          $884
                                                     ============  ============   ============  =============

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

    Notes Payable                                           $359          $797         $1,643         $1,315
    Other                                                    461           635          1,033            961
                                                     ------------  ------------   ------------  -------------
         Total Other Interest Charges                       $820        $1,432         $2,676         $2,276
                                                     ============  ============   ============  =============
</TABLE>

                                       15
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(K)  FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS

     The Company had a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases.  On
April 16, 1999,  the Company sold all of its  operating  non-nuclear  generation
facilities to an  unaffiliated  entity.  See Note (C)  "Rate-Related  Regulatory
Proceedings".  As a result,  the Company no longer has a need to acquire  fossil
fuel.  The  Company  and the  financial  institution  agreed to  terminate  this
agreement as of May 31,1999.

(L)  COMMITMENTS AND CONTINGENCIES

CAPITAL EXPENDITURE PROGRAM

     The Company's continuing capital expenditure program is presently estimated
at $130.8 million, excluding AFUDC, for 1999 through 2003.

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 $83.9 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 $83.9 million, or $4.2
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 $17.8 million per incident. However, any assessment would be limited to
$2.1 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
$3.1 million.

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


                                       16
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

     The Company's  estimate of its remaining share of Connecticut Yankee costs,
including  decommissioning,  less  return  of  investment  (approximately  $10.2
million) and return on investment (approximately $4.4 million) at June 30, 1999,
is  approximately  $29.1  million.  This  estimate,  which is subject to ongoing
review and revision,  has been  recorded by the Company as an  obligation  and a
regulatory asset 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
Firm  Energy  Contract,  which  currently  provides  for the  sale of 9  million
megawatt-hours  per year by Hydro-Quebec to the New England  participants in the
Phase II facility,  is scheduled to expire in September of 2001,  but is subject
to  extension  in order to  remedy  deficiencies  in  deliveries  of  energy  by
Hydro-Quebec.  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, 1999, the Company's guarantee liability for this debt was approximately
$6.5 million.

                             ENVIRONMENTAL CONCERNS

     In complying  with  existing  environmental  statutes and  regulations  and
further developments in areas of environmental  concern,  including  legislation
and  studies  in the  fields of water  quality,  hazardous  waste  handling  and
disposal,  toxic substances,  and electric and magnetic fields,  the Company may
incur  substantial   capital   expenditures  for  equipment   modifications  and
additions,  monitoring  equipment  and  recording  devices,  and  it  may  incur
additional  operating expenses.  Litigation  expenditures may also increase as a
result of scientific investigations,  and speculation and debate, concerning the
possibility of harmful health effects of electric and magnetic fields. The total
amount of these expenditures is not now determinable.



                                       17
<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, 1999,  and that the
value of the property following  remediation will not exceed $6.0 million.  As a
result of a 1992 DPUC  retail  rate  decision,  beginning  January 1, 1993,  the
Company  has  been  recovering  through  retail  rates  $1.075  million  of  the
remediation costs per year. The remediation  costs,  property value and recovery
from  customers  will be subject to true-up in the  Company's  next  retail rate
proceeding  based on actual  remediation  costs and actual gain on the Company's
disposition of the property.

     The Company is  presently  remediating  an area of PCB  contamination  at a
site,  bordering  the  Mill  River  in New  Haven,  that  contains  transmission
facilities  and  the   deactivated   English  Station   generation   facilities.
Remediation costs,  including the repair and/or replacement of approximately 560
linear  feet of sheet  piling,  are  currently  estimated  at $7.5  million.  In
addition,  the  Company is  planning  to repair  and/or  replace  the  remaining
deteriorated  sheet  piling  bordering  the  English  Station  property,  at  an
additional estimated cost of $10.0 million.

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

(M)  NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING

     New   Hampshire   has   enacted  a  law   requiring   the   creation  of  a
government-managed  fund to finance the  decommissioning  of nuclear  generating
units  in  that  state.  The New  Hampshire  Nuclear  Decommissioning  Financing
Committee  (NDFC)  has  established  $497  million  (in  1999  dollars)  as  the
decommissioning  cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 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 1999 was $1.2 million.  UI's share of the fund at
June 30, 1999 was approximately $18.7 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 $560 million (in 1999  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 1999 was $244,000. UI's share of the fund at June
30,  1999 was  approximately  $7.3  million.  The current  decommissioning  cost
estimate  for the  Connecticut  Yankee  Unit,  assuming  the prompt  removal and
dismantling of the unit commencing in 1997, is $476 million, of which UI's share
would be $45 million.  Through June 30, 1999, $123 million has been expended for
decommissioning.  The projected remaining  decommissioning cost is $353 million,
of which UI's share would be $34 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 $1.2 million were
funded by UI during the first six months of 1999,  and UI's share of the fund at
June 30, 1999 was $21.6 million.



                                       18
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(Q)  RESTATEMENT OF FINANCIAL RESULTS

     Subsequent to filing its Form 10-Q for the quarter ended June 30,1999,  the
Company reviewed, in consultation with our independent  accountants and staff of
the Securities and Exchange Commission, the periods in which it recorded certain
charges  and,  as a result,  has  recorded  certain of these  charges in earlier
periods. These restatements did not result in any change to retained earnings as
originally  reported as of June 30, 1999 and December  31, 1998.  As a result of
this  review,  net income and  earnings  per share  originally  reported for the
quarter and six month to date periods  ended June 30, 1998 have been restated as
follows  to  reflect  the  restatement  of a $2.9  million  (after-tax)  charge,
originally  recorded in the second  quarter of 1998 related to the  recording of
additional  reserves  for  uncollectible  amounts  related to  American  Payment
Systems, Inc. (APS) agent collections, to prior periods.

<TABLE>
<CAPTION>
                                                              Quarter Ended       Six Months Ended
                                                              June 30, 1998           June 30, 1998
                                                              -------------------------------------
<S>                                                              <C>                  <C>
Income applicable to common stock, as originally reported        $5,468               $14,379
Effect on net income of restatement, increase/(decrease)          2,882                 2,882
                                                              -------------       ---------------
Income applicable to common stock, as restated                   $8,350               $17,261
                                                              -------------       ---------------

Earnings per share, as originally reported
 - Basis                                                          $0.39                 $1.03
 - Diluted                                                        $0.39                 $1.03


Earnings per share, as restated
 - Basis                                                          $0.59                 $1.23
 - Diluted                                                        $0.59                 $1.23
</TABLE>


     In  addition,  as a result of this  review,  the  Company  has  included in
restricted  cash as of June 30,  1999 and  December  31,  1998  amounts of $24.8
million and $ 23.1 million,  respectively,  representing collections by American
Payment Systems,  Inc. (APS) agents that are held in APS agent accounts prior to
transmittal to the respective  APS customers.  In addition,  as a result of this
review,  the Company has included in other  accounts  receivable  as of June 30,
1999  and  December  31,  1998  amounts  of $22.9  million  and  $26.8  million,
respectively,  representing  amounts collected by APS agents on those days which
had  not  been   deposited  into  APS  bank  accounts  until  a  later  date.  A
corresponding  restatement of accounts payable has been recorded to reflect that
these  receivable  amounts  are owed to APS utility  customers.  The Company had
previously  presented  its  consolidated  balance  sheet  net of these  accounts
receivable and accounts payable amounts.


                                       19
<PAGE>


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


                     MAJOR INFLUENCES ON FINANCIAL CONDITION

     In April  1998,  Connecticut  enacted  Public Act 98-28 (the  Restructuring
Act),  a massive  and  complex  statute  designed  to  restructure  the  State's
regulated  electric utility  industry.  See Note (C),  "Rate-Related  Regulatory
Proceedings",  for a discussion of the  Restructuring  Act and its impact on the
Company.

     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.  Total  operation and  maintenance  expense,  excluding
one-time  items  and  cogeneration  capacity  purchases,  declined  by 1.1%,  on
average, during the past 5 years. There will be significant changes to operation
and  maintenance  expense and other expenses in 1999,  partly as a result of the
Generation Asset Divestiture described in "Looking Forward" below.

     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.

     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. The Company expects to continue to meet
these  criteria in the  foreseeable  future.  The  Restructuring  Act enacted in
Connecticut  in 1998  provides  for the  Company to recover in future  regulated
service rates  previously  deferred  costs  through  ongoing  assessments  to be
included  in  such  rates.  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 could 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.


                                       20
<PAGE>

                           CAPITAL EXPENDITURE PROGRAM

     The Company's  1999-2003 capital expenditure  program,  excluding allowance
for funds used  during  construction  and its effect on certain  capital-related
items, is presently budgeted as follows:

<TABLE>
<CAPTION>
                                         1999          2000         2001        2002         2003         Total
                                         ----          ----         ----        ----         ----         -----
                                                                         (000's)
<S>                                     <C>          <C>          <C>         <C>          <C>          <C>
Generation  (1)                          $4,891       $4,229       $2,435      $1,851       $1,280       $14,686
Distribution and Transmission            16,954       15,761       11,470      11,509       12,816        68,510
Other                                     6,443        5,238        2,731       2,543        1,949        18,904
                                         ------       ------       ------      ------       ------       -------
Subtotal                                 28,288       25,228       16,636      15,903       16,045       102,100

Nuclear Fuel                              2,413        9,298        6,774       2,953        7,302        28,740
                                         ------       ------       ------      ------       ------       -------

  Total Expenditures                    $30,701      $34,526      $23,410     $18,856      $23,347      $130,840
                                        =======      =======      =======     =======      =======      ========

Rate Base and Other Selected Data:
Depreciation
  Book Plant (1)                        $50,200      $48,120      $48,636     $48,910      $49,531
  Conservation Assets                     5,048            0            0           0            0
  Decommissioning                         2,781        2,892        3,007       3,128        3,253
Additional Required Amortization
  Regulatory Tax Assets (pre-tax
            and after-tax)               12,096            0            0           0            0
  Other Regulatory Assets (pre-tax)(2)        0       49,500       54,500           0            0
Amortization of Deferred
 Return on Seabrook Unit 1
 Phase-In (after-tax)                    12,586            0            0           0            0

Estimated Rate Base
 (end of period)                        849,684
 (average)                              920,367
</TABLE>

(1)    Reflects divestiture of operating fossil-fueled generation plant on April
       16, 1999.  See Note (C),  "Rate-Related  Regulatory  Proceedings",  for a
       description  of  this  divestiture.  Remaining  operating  generation  is
       nuclear, excluding nuclear fuel.

(2)    Additional  amortization of unspecified  regulatory assets, as ordered by
       the Connecticut  Department of Public Utility Control in its December 31,
       1996 retail rate order, provided that, as expected,  common equity return
       on utility  investment  exceeds  10.5%  after  recording  the  additional
       amortization. Substantially all of this accelerated amortization may have
       to be  eliminated  in order to achieve the  minimum  10% price  reduction
       (compared to the average  fully  bundled  prices in effect  during 1996),
       while  providing  for the added  costs  imposed by Public  Act  98-28,  a
       statute  enacted by  Connecticut,  designed  to  restructure  the State's
       regulated  electric  utility  industry.   See  Note  (C),   "Rate-Related
       Regulatory Proceedings", for a discussion of this statute.



                                       21
<PAGE>

                         LIQUIDITY AND CAPITAL RESOURCES

     At June 30, 1999,  the Company had $26.4 million of cash and temporary cash
investments,  including  the Seabrook  Unit 1 operating  deposit,  but excluding
restricted cash of American Payments Systems,  Inc., a decrease of $75.0 million
from the  corresponding  balance at December 31, 1998.  The  components  of this
decrease,  which are detailed in the  Consolidated  Statement of Cash Flows, are
summarized as follows:

                                                                    (Millions)

  Balance, December 31, 1998                                         $ 101.4
                                                                      ------

  Net cash provided by operating activities                             14.3

  Net cash provided by (used in) financing activities:
  - Financing  activities,  excluding  dividend payments              (253.5)
  - Dividend payments                                                  (20.3)
 Net cash provided by investing activities, excluding
   investment in plant                                                   5.5
 Net cash provided from sale of generation  assets                     270.6
 Cash invested  in  unregulated  generation  facility                  (75.1)
 Cash invested in plant, including nuclear fuel                        (16.5)
                                                                        ----

        Net Change in Cash                                             (75.0)

  Balance, June 30, 1999                                               $26.4
                                                                        ====

     The Company's capital requirements are presently projected as follows:

<TABLE>
<CAPTION>
                                                         1999       2000       2001       2002       2003
                                                         ----       ----       ----       ----       ----
                                                                             (millions)
<S>                                                      <C>        <C>        <C>        <C>        <C>
Cash on Hand - Beginning of Year  (1)                    $101.4      $ -       $ -        $46.0      $ 1.3
Internally Generated Funds less Dividends  (2)             91.4       82.6      84.7       89.5       91.5
Net Proceeds from Sale of Fossil Generation Plants        200.4        -         -          -          -
                                                          -----      ------    -----      -----       ----
         Subtotal                                         393.2       82.6      84.7      135.5       92.8

Less:
Utility Capital Expenditures  (2)                          30.7       34.5      23.4       18.9       23.3
Investments in subsidiaries  (3)                          110.0       15.0      15.0       15.0       15.0
                                                          -----      -----     -----      -----      -----

Cash Available to pay Debt Maturities and Redemptions     252.5       33.1      46.3      101.6       54.5

Less:
Maturities and Mandatory Redemptions                       69.6        0.4       0.3      100.3      100.5
Optional Redemptions                                      125.0       50.0        -          -        -
Repayment of Short-Term Borrowings                         80.0        -          -          -        -
                                                          -----       -----    -----      -----      -----


External Financing Requirements (Surplus)  (2)            $22.1      $17.3    $(46.0)    $(1.3)     $46.0
                                                           ====       ====     ======     =====      ====
</TABLE>

(1)  Includes  Seabrook Unit 1 operating  deposit,  but not  restricted  cash of
     American Payment Systems,  Inc. of $23.1 million.
(2)  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  December  31,  1996 price
     levels by the year 2000. Connecticut's Restructuring Act, described at Note
     (C), "Rate-Related Regulatory Proceedings",  required the Company to


                                       22
<PAGE>

     divest  itself of its  fossil-fueled  generating  plants and requires it to
     attempt  to divest  itself of its  ownership  interests  in  nuclear-fueled
     generating  units prior to January 1, 2004. This forecast  reflects the net
     after-tax proceeds from the divestiture of fossil-fueled  generation plants
     on April 16,  1999.  All of these  estimates  are  subject to change due to
     future events and conditions that may be substantially different from those
     used in developing the projections.
(3)  Investment  for 1999 in  United  Bridgeport  Energy  $85.0  million,  Allan
     Electric Co., Inc. $8.0 million,  Precision  Power,  Inc. $14.0 million and
     United  Resources,   Inc.  $4.0  million.  Forward  estimates  are  targets
     necessary to meet earnings growth goals.

     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 with a group of banks,  described below, the
Company  expects to be able to satisfy its external  financing  needs by issuing
additional  short-term and long-term  debt. 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 8, 1999. The borrowing  limit of this facility is
$75 million.  The facility  permits the Company to borrow funds at a fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
June 30, 1999, the Company had $46 million in 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  UI's  regulated  electric  utility  business  and provide  long-term
rewards to UI's shareowners.

     URI has four  wholly-owned  subsidiaries.  American Payment  Systems,  Inc.
manages a national network of agents for the processing of bill payments made by
customers of UI and other utilities.  It manages agent networks in 36 states and
processed   approximately   $7.5  billion  in  customer  payments  during  1998,
generating  operating  revenues of  approximately  $33.7  million and  operating
income  of  approximately  $1.7  million.  Another  subsidiary  of URI,  Thermal
Energies,  Inc.,  owns and  operates  heating  and  cooling  energy  centers  in
commercial and institutional  buildings, and is participating in the development
of district  heating  and cooling  facilities  in the  downtown  New Haven area,
including  the energy  center  for an office  tower and  participation  as a 52%
partner in the energy center for a city hall and office tower  complex.  A third
URI  subsidiary,   Precision   Power,   Inc.  and  its   subsidiaries,   provide
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 a 33 1/3% owner of Bridgeport  Energy,  LLC, which
owns and operates a 500-megawatt merchant wholesale electric generating facility
in Bridgeport, Connecticut.

                              RESULTS OF OPERATIONS

SECOND QUARTER OF 1999 VS. SECOND QUARTER OF 1998
-------------------------------------------------

     Earnings  for the second  quarter of 1999 were $13.9  million,  or $.99 per
share (on both a basic and diluted basis),  up $5.6 million,  or $.39 per share,
from the second  quarter of 1998.  There were no one-time  items recorded in the
second quarter of 1999 or 1998.

     Retail  revenues  from  operations  increased by $6.3 million in the second
quarter of 1999  compared to the second  quarter of 1998,  as electric  revenues
increased  for the  reasons  detailed  below.  Retail  fuel and  energy


                                       23
<PAGE>

expense increased by $6.3 million,  primarily from higher purchased power prices
as a result of the  Company's  transition  from a producer to a purchaser of its
customers'  energy  requirements.  Overall,  retail sales margin from operations
decreased by $0.7  million.  The  principal  components  of the change in retail
sales margin for the quarter, year-over-year, include:

                                                                      $millions
 --------------------------------------------------------------------- --------
 Revenue from:
 --------------------------------------------------------------------- --------
   Estimate of "real" retail sales growth, up 3.0%                         4.6
 --------------------------------------------------------------------- --------
   Estimate of weather effect on retail sales, up 1.4%                     2.2
 --------------------------------------------------------------------- --------
   Sales decrease from Yale University cogeneration, (0.8)%               (1.2)
 --------------------------------------------------------------------- --------
   Price mix of sales and other                                            0.7
 --------------------------------------------------------------------- --------
 Fuel and energy, margin effect:
 --------------------------------------------------------------------- --------
   Sales increase                                                         (1.1)
 --------------------------------------------------------------------- --------
   Nuclear fuel prices and refueling outage replacement costs             (3.1)
 --------------------------------------------------------------------- --------
   Replacement power for fossil unit outage in 1998                        1.7
 --------------------------------------------------------------------- --------
   Fossil fuel and purchased energy prices                                (3.7)
 --------------------------------------------------------------------- --------

          On April 16, 1999,  the Company  completed  the sale of its  operating
     fossil-fueled generating plants and existing wholesale sales contracts that
     was  required by  Connecticut's  electric  utility  industry  restructuring
     legislation.  As a result,  the  "geography" of the Company's  costs on the
     income statement and, hence, the year-over-year variances, have changed and
     will  change   significantly   beginning  in  the  second   quarter.   This
     particularly  relates to wholesale  revenue,  retail  purchased  energy and
     fossil fuel expenses,  operation and maintenance expense,  depreciation and
     interest  charges.  For  example,  the  increased  purchased  energy  costs
     included  in the table above are more than offset by some of the decline in
     miscellaneous  operation and  maintenance  expense,  due principally to the
     sale of generating  plants,  shown in the table below,  and to decreases in
     depreciation and property taxes. See the "Looking Forward" section for more
     details.

     Net wholesale margin (wholesale  revenue less wholesale  expense) decreased
by $1.6 million in the second  quarter of 1999 compared to the second quarter of
1998 from lower  wholesale  capacity sales  resulting from the generation  asset
sale.  Other  operating  revenues,  which include  NEPOOL  related  transmission
revenues,   increased  by  $1.2  million.   NEPOOL  transmission   revenues  are
recoveries, for the most part, of NEPOOL transmission expense and simply reflect
new  accounting  requirements  implemented  by  the  Federal  Energy  Regulatory
Commission.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $6.2 million in the second quarter of 1999 compared to the
second  quarter of 1998.  The  principal  components  of these  expense  changes
include:


                                       24
<PAGE>

                                                                      $millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Connecticut Yankee                                                     (0.1)
--------------------------------------------------------------------- ----------
   Cogeneration and other purchases                                       (0.2)
--------------------------------------------------------------------- ----------
 Other O&M expense:
--------------------------------------------------------------------- ----------
   Seabrook Unit 1 (refueling outage and accruals)                         2.5
--------------------------------------------------------------------- ----------
   Millstone Unit 3 (refueling outage and accruals)                        0.5
--------------------------------------------------------------------- ----------
   Other expenses at nuclear units                                        (0.8)
--------------------------------------------------------------------- ----------
   Fossil generation unit overhaul and outage costs                       (4.3)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                             0.6
--------------------------------------------------------------------- ----------
   Other miscellaneous, including impact of generation asset sale         (4.4)
--------------------------------------------------------------------- ----------

     Depreciation  expense  decreased by $1.7  million in the second  quarter of
1999 compared to the second  quarter of 1998,  due  primarily to the  generation
asset sale. Property tax expense decreased by $1.1 million due to this sale.

     On December 31, 1996, the Connecticut  Department of Public Utility Control
issued an order that  implemented a five-year  Rate Plan to reduce the Company's
retail  prices and  accelerate  the  recovery  of certain  "regulatory  assets".
According  to the Rate Plan,  under  which the Company is  currently  operating,
"accelerated"  amortization  of past utility  investments is scheduled for every
year that the Rate Plan is in  effect,  contingent  upon the  Company  earning a
10.5% return on utility  common stock equity.  All of the scheduled  accelerated
amortization  for 1998,  amounting to $13.1  million  (before-tax,  $8.5 million
after-tax), was recorded against earnings from operations in 1998. One-fourth of
the total, or $3.3 million (before-tax, $2.1 million after-tax), was recorded in
each  quarter.  The Company is amortizing  regulatory  income tax assets for the
1999 amount,  totaling  $12.1 million  (after-tax,  about $20 million in pre-tax
equivalent),  one-fourth of it, or $3.0 million (after-tax,  about $5 million in
pre-tax equivalent), in each quarter.

     The Company can also incur additional accelerated amortization expense as a
result of the "sharing"  mechanism in the Rate Plan,  if the Company  achieves a
return on utility common stock equity above 11.5%,  which the Company expects to
achieve from operations  midway through the third quarter of 1999.  There was no
"sharing"  recorded  against  earnings from operations in the second quarters of
1998 or 1999. See the "Looking Forward" section for a more detailed  explanation
of the "sharing" mechanism.

     Unregulated subsidiary income, reported as "Other net" income, decreased by
about $2.9 million in the second  quarter of 1999 compared to second  quarter of
1998. American Payment Systems,  Inc. (APS), earned about $280,000  (before-tax)
in the  second  quarter  of  1999,  almost  one-third  more  than  the  $214,000
(before-tax)  earned in the  second  quarter of 1998.  The  income of  Precision
Power,  Inc. (PPI)  decreased $1.9 million  (before-tax),  reflecting  increased
infrastructure costs as it prepares to expand its service offerings.  The second
quarter PPI loss was in line with expectations outlined in the "Looking Forward"
section  of the  Company's  1998  Form  10-K.  On May 11,  1999,  the  Company's
unregulated  subsidiary,  United  Resources,  Inc.,  increased  its  4%  passive
investment,  through United  Bridgeport  Energy,  Inc., in Bridgeport Energy LLC
(BE) to 33 1/3%. The second phase of BE's merchant wholesale electric generating
project went into  commercial  operation in July 1999,  adding 180  megawatts of
generation capacity for a total of 520 megawatts. As a result of the shutdown of
the first phase  generator to allow for  construction  of the second phase,  the
Company  experienced  a loss of about $1 million  from  project  operations  and
financing in the second quarter of 1999. The Company's investment in the project
is expected to produce positive income in the second half of the year.

<TABLE>
<CAPTION>
                                                                      2nd Q 99    2nd Q 99
                                                                        vs.        vs.
Summary of Unregulated Subsidiaries Pre-tax Income: $millions         2nd Q 98    1st Q 99
--------------------------------------------------------------------- ---------- ---------
   <S>                                                                    <C>       <C>
   American Payment Systems, Inc.                                         0.1       - -
--------------------------------------------------------------------- ---------- ---------
   Precision Power, Inc.                                                 (1.9)      (1.2)
--------------------------------------------------------------------- ---------- ---------
   United Bridgeport Energy                                              (1.1)      (1.1)
--------------------------------------------------------------------- ---------- ---------
   United Resources, Inc. Capital Projects                                 - -       0.6
--------------------------------------------------------------------- ---------- ---------
</TABLE>



                                       25
<PAGE>

     Interest  charges  continued on their  downward  trend,  decreasing by $3.8
million for the regulated business in the second quarter of 1999 compared to the
second quarter of 1998, partly offset by an increase of $0.6 million in interest
charges for unregulated subsidiaries.  Most of the reduction in utility interest
charges  anticipated  for 1999  compared to 1998 is coming after the  generation
asset sale,  which was  completed  on April 16,  1999.  On April 16,  1999,  the
Company used  proceeds  received  from the sale to pay off $205 million of debt.
See the "Looking Forward" section for more details.

FIRST SIX MONTHS OF 1999 VS. FIRST SIX MONTHS OF 1998
-----------------------------------------------------

     Earnings for the first six months of 1999 were $23.8 million,  or $1.69 per
share (on both a basic and diluted basis),  up $6.5 million,  or $.46 per share,
from the first six months of 1998.  Excluding  a one-time  item  recorded in the
first quarter of 1999, earnings from operations were $23.2 million, or $1.65 per
share, up $5.9 million, or $.42 per share.

     There were no one-time  items recorded in the first six months of 1998. The
one-time item reported in the first six months of 1999 was:

                             One-time Items                               EPS
-------------------------------------------------------------------------------
  1999 Quarter 1   Purchased power expense refund                       $ .12
                   "Sharing" due to one-time refund                     $(.08)
-------------------------------------------------------------------------------

     Retail revenues from operations increased by $13.1 million in the first six
months of 1999  compared to the first six months of 1998,  as electric  revenues
increased for the reasons  detailed  below.  Retail  revenues  decreased by $1.0
million because of "sharing" required under the current regulatory  structure as
applied to the one-time gain recorded in the first quarter of 1999.  Retail fuel
and energy expense  increased by $1.3 million,  primarily from higher  purchased
power  prices as a result  of the  Company's  transition  from a  producer  to a
purchaser  of its  customers'  energy  requirements,  and the  need to  purchase
additional  energy to replace power lost from nuclear plant  refueling  outages.
Overall,  retail sales margin from  operations  increased by $11.6  million,  or
10.3%.  The  principal  components  of the retail  sales  margin  change for the
quarter, year-over-year, include:

                                                                      $ millions
--------------------------------------------------------------------- ----------
 Revenue from:
--------------------------------------------------------------------- ----------
   Estimate of "real" retail sales growth, up 2.9%                        8.8
--------------------------------------------------------------------- ----------
   Estimate of weather effect on retail sales, up 1.5%                    4.6
--------------------------------------------------------------------- ----------
   Sales decrease from Yale University cogeneration, (1.3)%              (3.7)
--------------------------------------------------------------------- ----------
   Price mix of sales and other                                           3.4
--------------------------------------------------------------------- ----------
   "Sharing" due to one-time gain                                        (1.0)
--------------------------------------------------------------------- ----------
 Fuel and energy, margin effect:
--------------------------------------------------------------------- ----------
   Sales increase                                                        (1.8)
--------------------------------------------------------------------- ----------
   Nuclear fuel prices and outage replacement costs                      (4.0)
--------------------------------------------------------------------- ----------
   Replacement power for fossil unit outage in 1998                       1.7
--------------------------------------------------------------------- ----------
   Fossil fuel price                                                      2.8
--------------------------------------------------------------------- ----------

     On April 16, 1999, the Company  completed the sale of its operating  fossil
fueled  generating  plants  and  existing  wholesale  sales  contracts  that was
required by Connecticut's electric utility industry  restructuring  legislation.
As a result, the "geography" of the Company's costs on the income statement and,
hence, the year-over-year  variances, have changed and will change significantly
beginning in the second quarter. This particularly relates to wholesale revenue,
retail  purchased  energy and fossil fuel expense,  operations  and  maintenance
expense,  depreciation and interest  charges.  See the "Looking Forward" section
for more details.

     Net wholesale margin (wholesale  revenue less wholesale  expense) decreased
by $3.8 million in the first six months of 1999 compared to the first six months
of 1998 from lower wholesale  capacity sales.  Other operating


                                       26
<PAGE>

revenues, which include NEPOOL related transmission revenues,  increased by $2.8
million.  NEPOOL  transmission  revenues are  recoveries,  for the most part, of
NEPOOL  transmission  expense  and simply  reflect new  accounting  requirements
implemented by the Federal Energy Regulatory Commission.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  increased by $0.5  million in the first six months of 1999  compared to
the  first  six of 1998.  The  principal  components  of these  expense  changes
include:
                                                                      $millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Connecticut Yankee                                                     (0.5)
--------------------------------------------------------------------- ----------
   Cogeneration and other purchases (see Note)                             3.0
--------------------------------------------------------------------- ----------
 Other O&M expense:
--------------------------------------------------------------------- ----------
   Seabrook Unit 1 (refueling outage and accruals)                         4.1
--------------------------------------------------------------------- ----------
   Millstone Unit 3 (refueling outage and accruals)                        1.0
--------------------------------------------------------------------- ----------
   Other expenses at nuclear units                                        (1.1)
--------------------------------------------------------------------- ----------
   Fossil generation unit overhaul and outage costs                       (6.3)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                             1.5
--------------------------------------------------------------------- ----------
   Other miscellaneous, including impact of generation asset sale         (1.2)
--------------------------------------------------------------------- ----------

   Note:  A  cogeneration  facility was out of service for about a month in the
         first quarter of 1998 but has operated normally in 1999.

     Depreciation  expense  decreased by $1.5 million in the first six months of
1999 compared to the first six months of 1998,  due primarily to the  generation
asset sale.

     On December 31, 1996, the Connecticut  Department of Public Utility Control
issued an order that  implemented a five-year  Rate Plan to reduce the Company's
retail  prices and  accelerate  the  recovery  of certain  "regulatory  assets."
According  to the Rate Plan,  under  which the Company is  currently  operating,
"accelerated"  amortization  of past utility  investments is scheduled for every
year that the Rate Plan is in  effect,  contingent  upon the  Company  earning a
10.5% return on utility  common stock equity.  All of the scheduled  accelerated
amortization  for 1998,  amounting to $13.1  million  (before-tax,  $8.5 million
after-tax), was recorded against earnings from operations in 1998. One-fourth of
the total, or $3.3 million (before-tax, $2.1 million after-tax), was recorded in
each  quarter.  The Company is amortizing  regulatory  income tax assets for the
1999 amount, totaling $12.1 million (after-tax, $20 million pre-tax equivalent),
one-fourth of it, or $3.0 million (after-tax, $5 million pre-tax equivalent), in
each quarter.

     The Company can also incur additional accelerated amortization expense as a
result of the "sharing"  mechanism in the Rate Plan,  if the Company  achieves a
return on utility common stock equity above 11.5%,  which the Company expects to
achieve  midway through the third quarter of 1999.  Such "sharing"  amortization
was  recorded  in the first  quarter  of 1999,  in the  amount  of $0.6  million
(after-tax),  as a result of the one-time gain  recorded in that quarter.  There
was no "sharing"  recorded  against  earnings  from  operations in the first six
months of 1998 or 1999.

     "Other net" income  decreased by about $3.7 million in the first six months
of 1999  compared  to the  first  six  months  of 1998.  The  Company's  largest
unregulated subsidiary,  American Payment Systems, Inc. (APS), earned about $0.5
million from operations  (before-tax) in the first six months of 1999, unchanged
from the first six months of 1998.  The income of Precision  Power,  Inc.  (PPI)
decreased $2.6 million (before-tax),  reflecting increased  infrastructure costs
as it continues to prepare to expand its service  offerings.  The  six-month PPI
loss was in line with expectations  outlined in the "Looking Forward" section of
the  Company's  1998 Form  10-K.  On May 11,  1999,  the  Company's  unregulated
subsidiary, United Resources, Inc., increased its 4% passive investment, through
United  Bridgeport  Energy,  Inc., in Bridgeport Energy LLC (BE) to 33 1/3%. The
second phase of BE's merchant  wholesale  electric  generating project went into
commercial  operation in July 1999, adding 180 megawatts of generation  capacity
for a total of 520  megawatts.  As a result of the  shutdown  of the first phase
generator to allow for construction of the second phase, the Company experienced
a loss of about $1 million from project  operations


                                       27
<PAGE>

and financing in the second  quarter of 1999.  The  Company's  investment in the
project is expected to produce positive income in the second half of the year.


                                                                      1st 6 mos.
Summary of Unregulated Subsidiaries Pre-tax Income: $millions         99 vs. 98
--------------------------------------------------------------------- ----------
  American Payment Systems, Inc.                                         - -
--------------------------------------------------------------------- ----------
  Precision Power, Inc.                                                 (2.6)
--------------------------------------------------------------------- ----------
  United Bridgeport Energy, Inc.                                        (1.1)
--------------------------------------------------------------------- ----------
  United Resources, Inc. Capital Projects                                - -
--------------------------------------------------------------------- ----------

     Interest  charges  continued on their  downward  trend,  decreasing by $4.0
million for the regulated business in the second quarter of 1999 compared to the
second quarter of 1998, partly offset by an increase of $0.6 million in interest
charges for unregulated subsidiaries.  Most of the reduction in utility interest
charges  anticipated  for 1999  compared to 1998 is coming after the  generation
asset sale,  which was  completed  on April 16,  1999.  On April 16,  1999,  the
Company used proceeds received from the sale of plant to pay off $205 million of
debt. See the "Looking Forward" section for more details.

                                 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
INCOME AND EARNINGS 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 to reduce the Company's  retail prices and  accelerate the recovery of
certain  "regulatory  assets," beginning with deferred  conservation  costs. The
Company  operated 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  annual  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 (see "Sharing  Implementation"  below) any utility income
that would  produce a return above the 11.5%  level:  one-third to be applied to
customer price reductions, one-third to be applied to additional amortization of
regulatory assets,  and one-third to be retained by shareowners.  Utility income
is inclusive of earnings from operations and one-time  items.  The Order remains
in effect  through  2001,  although it does  include a provision  that it may be
modified as a result of the restructuring  legislation passed by the Connecticut
legislature in 1998.  Please see the "Looking  Forward" section of the Company's
1998 Form 10-K for a more extensive description of the five-year Rate Plan.

Sharing Implementation
----------------------

     The Company  estimates  that its return on regulated  utility  common stock
equity  invested in utility  assets of 11.5%,  that is, the level that  triggers
"sharing" of additional  utility  earnings,  will require  utility  common stock
equity income (after-tax) of about $47 million for 1999. The Company will record
"sharing"  customer price  reductions and additional  amortization of regulatory
assets once it begins earning above that level of income for 1999.  Based on the
traditional  quarterly earnings pattern,  the Company realizes about half of its
pre-sharing  utility earnings in the third quarter.  The Company will not likely
ever exceed the sharing  level of utility  earnings  before the third quarter of
any year that  "sharing"  is in effect.  Assuming  the sharing  level of utility
earnings  is  exceeded  in the third  quarter  of a  particular  year,  then all
positive  utility  earnings  recorded in the fourth quarter of that year will be
subject to sharing. This methodology will ensure stable, year-over-year earnings
comparisons  based on actual utility  financial  results and will be unlikely to
result in any sharing  reversals  in the fourth  quarter  that are  unrelated to
income in the fourth quarter.



                                       28
<PAGE>

1999 Earnings
-------------

     1999 will be a year of transition to the January 1, 2000  effective date of
electric  utility  restructuring  under  legislation  passed by the  Connecticut
legislature in 1998.  The Company has taken one major step toward  restructuring
by proceeding with the sale of its fossil-fueled  generation plants and existing
wholesale sales contracts  (known as the Generation  Asset  Divestiture or GAD).
That sale was  completed on April 16, 1999.  All of the changes  resulting  from
GAD, described below, began occurring on April 16.

     One result of the GAD will be a  reduction  in the  electric  utility  rate
base, the basis for measuring  return on utility common stock equity.  Rate base
is expected to decline  from an average of $1,128  million in 1998 to an average
of about  $920  million  in 1999.  This  would  result in a  similar  percentage
reduction  in the  Company's  utility  common  stock  equity,  except  that  the
Company's  longstanding  policy  of debt  paydown  will  partially  offset it by
increasing the portion of rate base financed by equity. The portion of rate base
that is financed  by equity is,  then,  expected  to decline  from an average of
about $431 million in 1998 to about  $410-$420  million in 1999.  During 1998, a
return of 11.5% on utility common stock equity produced  earnings of about $3.43
per share.  Because of the reduced equity portion of rate base expected in 1999,
the allowed return is expected to produce  utility  earnings in the  $3.35-$3.40
per share range.

     The Company's  earnings from its utility business are affected  principally
by: retail sales that fluctuate with weather  conditions and economic  activity,
nuclear  generating unit  availability  and operating costs, and interest rates.
These are all items over which the Company has little control.

     The  Company's  revenues are  principally  dependent on the level of retail
electricity  sales.  The two  primary  factors  that  affect the volume of these
retail sales are economic conditions and weather. The Company's retail sales for
1998 of 5,452  gigawatt-hours set an all-time record for the Company and were up
1.4% from the 1997 level.

     The Company  estimates that mild 1998 weather reduced retail  kilowatt-hour
sales by about 0.5%,  retail  revenues by about $3.4  million,  and retail sales
margin by about  $2.7  million.  Weather  corrected  retail  sales for 1998 were
probably in the 5,470-5,500 gigawatt-hour range. On this weather-adjusted basis,
the  Company  experienced  about  1.0-1.5% of "real"  sales  growth in 1998 over
weather-adjusted  1997 sales,  with most of the growth appearing to occur in the
first three quarters of the year.

     Aside from "real" economic growth,  reductions in retail  electricity sales
has and will occur in 1999 compared to 1998 as a result of a  cogeneration  unit
at Yale  University  that  produces  approximately  one-half  of  Yale's  annual
electricity  requirements (about 1.5% of the Company's total 1998 retail sales).
This unit  commenced  operations in mid-1998,  and reduced total Company  retail
kilowatt-hour  sales by about 0.9% in 1998  compared to 1997.  The impact of the
Yale sales decline  continued  through the first six months of 1999,  decreasing
the Company's  sales  compared to the first six months of 1998 by 1.3%, and will
continue  somewhat in the third quarter of 1999,  decreasing the Company's sales
by as much as 1.0% in that quarter.  The overall impact of Yale  cogeneration on
the  Company's  1999 sales will be a reduction  of about  0.5%-1.0%  compared to
1998.  Thus, it will require "real" growth of this much, for the year, to merely
offset the decrease due to Yale.  "Real" growth in  kilowatt-hour  sales for the
first six months of 1999  compared to the first six months of 1998 was estimated
to be 2.9%,  only  partially  offset by the 1.3%  decrease  due to Yale.  Retail
kilowatt-hour  sales growth of 1.0% produces a margin  improvement of about $5.0
million on an annual basis, before any "sharing" effect considerations.

     Prices in individual customer rate classes will not change in 1999 relative
to 1998, exclusive of any "sharing".  However, sales growth is occurring in rate
classes with higher than average prices,  and the Company expects an increase in
retail  revenue of about $3.0  million in 1999  compared to 1998 from this price
mix improvement.

     Other  operating  revenues  are  expected to increase as a result of NEPOOL
related transmission revenues by about $4.0 million, due to NEPOOL restructuring
changes; but this will have no net income effect, as the higher revenues are due
to higher transmission  operating expense.  Other than the NEPOOL impact,  these
revenues are expected to decrease by about $2.0 million to a more normal  level.
The Company does not  anticipate,  at this time,


                                       29
<PAGE>

any other  significant  revenue  reductions in 1999 retail revenues  compared to
1998, unless the Company is achieving a "sharing" level of earnings.

     As a result of the GAD,  wholesale capacity revenues will decrease by about
$7.7  million  in 1999  compared  to  1998,  because  existing  wholesale  sales
contracts  were part of the GAD. Also as a result of the GAD, the Company's fuel
and purchased energy charges will increase in 1999 compared to 1998 by about $40
million, to replace the power previously provided by the Company's fossil fueled
generation  plants. A power supply purchase agreement was part of the GAD and it
will help to ensure  adequate  resources to meet customer energy demands under a
short-term fixed price agreement until July 2000 (the price declines somewhat in
2000  compared  to 1999)  when all  customers  will have a choice of  generation
suppliers.  The Company expects that its projected 1999 energy requirements that
are not met by the GAD  power  supply  purchase  agreement  will be met at lower
prices than those  experienced  in 1998,  primarily  because of lower  projected
fossil fuel prices and energy  prices in general.  This is expected to result in
energy cost savings of about $5 million.

     Purchased  capacity costs should  decrease by about $2 million in 1999, due
primarily  to  decreases in  decommissioning  costs for the retired  Connecticut
Yankee nuclear generation plant.

     Several other expense  categories are expected to be reduced  substantially
in 1999  because  of the GAD and the  Company's  other cost  reduction  efforts,
offsetting the impact of the increase in purchased energy charges. Operation and
maintenance  expense is expected to decrease by a net $22 million,  reflecting a
decrease of $32 million due to the GAD and other general changes,  partly offset
by increases of about $5 million for nuclear unit refueling outages,  $1 million
for Y2K costs, and $4 million due to NEPOOL transmission charges The latter will
have no net income effect, as the higher transmission expense will be covered by
higher transmission  revenues.  Total Y2K costs for 1999 are currently projected
at about $3.6 million.  Other operation and maintenance  expenses in 1999 should
be fairly  stable  compared  to 1998,  unless  an event  occurs  that  cannot be
predicted at this time.

     Consolidated  interest  costs  are now  expected  to  decline  by about $12
million in 1999  compared to 1998,  to about $40 million,  a level that was last
experienced  in 1982.  This  anticipated  interest  cost  reduction  will result
largely from utility debt paydown  through use of the  after-tax  cash  proceeds
from the GAD, partly offset by the increase in the Company's  passive  financial
investment  in  Bridgeport  Energy LLC. The  Bridgeport  Energy  investment  was
announced in a news release dated March 30, 1999, and represents a 33 1/3% stake
in an operational combined cycle gas turbine wholesale electric generating plant
operated  on a  merchant  basis by Duke  Energy.  The  Company  also  expects to
generate  substantial  cash flow from  operations  after  dividend  and  capital
spending, which will also be used to pay down debt.

     Depreciation,  excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to the GAD but also to the near
completion  in 1998  of  depreciation  of  previously  capitalized  conservation
program  expenditures.  A significant portion of the depreciation being recorded
for the GAD assets was not tax  deductible  and did not affect  taxable  income.
Therefore,  a significant portion of the decrease in depreciation related to the
GAD will not  increase  income  taxes,  and will  therefore  supplement  the $13
million depreciation decrease with an additional tax benefit,  comparing 1999 to
1998, of about $2.5 million, or $.18 per share.

     Accelerated amortization, pursuant to the Rate Plan, will increase by about
$4  million  (on an  equivalent  after-tax  basis)  in 1999  compared  to  1998,
exclusive of any "sharing" amortization. Property taxes should decrease by about
$2 million,  due mostly to the GAD. Other operating  expenses can be expected to
experience some increases and some decreases that should,  more or less,  offset
one another.

     In summary,  the Company expects  substantial  net expense  reductions as a
result of the GAD and  ongoing  cost  control  measures  that  should  more than
compensate for increased charges for replacement power and increased accelerated
amortization  costs in 1999. Such  performance  should allow utility earnings to
increase above an 11.5% return on utility common stock equity into the "sharing"
range of the Order.  Currently,  the Company  expects its regulated  business to
earn, for the entire year of 1999, about $15 million to $17 million  (after-tax)
above  the  11.5%  return  "sharing"  threshold  of  about  $47  million  set by
regulators  ($3.35-$3.40  per share).  These  earnings  would


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<PAGE>

result in about $9  million  in  customer  price  reductions,  and $9 million in
offsets to stranded costs (pre-tax).  Given current  expectations,  the retained
portion of shared  earnings  would add about  $.35-$.40 per share,  resulting in
earnings from operations for the regulated business of about $3.70-$3.80 for the
year.  The Company  expects to achieve the sharing  threshold of earnings and to
begin  sharing  in the  third  quarter  of the  year,  assuming  normal  weather
patterns.  In that case, all utility business earnings in the fourth quarter can
be expected to be subject to sharing.  The Company  expects that 1999  quarterly
earnings  from  operations  will  follow a pattern  similar to that of 1998 on a
weather-normalized basis.

     Unregulated subsidiaries are expected to experience losses of $.10-$.15 per
share in 1999.  American  Payment  Systems,  Inc. is expected to build on 1998's
contribution to earnings from operations of $.07 per share.  However,  this will
depend on its ability to expand sales to its utility customers.  Precision Power
Inc.  (PPI)  increased its  organizational  infrastructure  in 1998,  also in an
effort to increase its presence in its principal  markets of  distributed  power
systems  and  services.  At its  current  level of  expense,  PPI's  Connecticut
operations  will lose $.15 per share in 1999 if no substantial new contracts are
obtained.  PPI recently acquired Allen Electric Co., Inc., a similar  enterprise
in New  Jersey,  which is  expected to be  accretive  slightly  this year and is
expected  to earn  $.07-$.10  per share  annually  going  forward.  For 2000 and
beyond,  the Company's  passive  financial  investment  in Bridgeport  Energy is
expected to increase UI's annual  earnings per share from  operations by $.10 to
$.15.

     As a  result  of the  earnings  contributions  anticipated  from all of its
different business activities  described above, the Company expects net earnings
per share from  operations  to be in the range of $3.55 to $3.70 in 1999.  These
estimates are subject to all of the contingencies and uncertainties  detailed in
the  preceding  discussion;  and the reader is  cautioned  to read the  "Looking
Forward" section in its entirety.

Year 2000
---------

     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.  This  comprehensive  program includes all
information   technology  systems  and  encompasses   systems  critical  to  the
generation,  transmission  and  distribution  of  electric  energy  as  well  as
traditional  business  systems.  Critical  systems  have been  defined  as those
business processes,  including embedded technology,  which if not remediated may
have  a  significant  impact  on  safety,   customers,   revenue  or  regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged  and is asking for assurance of their Year 2000
compliance.

     An inventory and assessment of the Company's computer system  applications,
hardware,   software  and  embedded   technologies  have  been  completed,   and
recommended solutions to all identified risks and exposures have been generated.
A testing, remediation,  renovation, replacement and retirement program has been
in progress  since early 1998.  Both  external and internal  resources are being
utilized to accomplish the testing,  remediation and renovation efforts. A total
of 383 affected  business  processes  have been  identified and 350 of them have
been verified as Year 2000 compliant through testing,  remediation,  replacement
or retirement.  The remediation  methodology  utilized has been Fixed Windowing,
and totally  independent  platforms  have been  installed for testing all of the
applications.  Necessary  upgrades  to  mainframe  hardware  and  software  were
completed and tested by June 30, 1999. This included a  "destructive"  mainframe
test performed at an independent site in Ponca City, Oklahoma.

     The Company included its operating non-nuclear generation facilities in the
Year 2000 program up to the date of their divestiture on April 16, 1999. At that
point,   all  related   documentation   was   transferred   and   delivered   to
Wisvest-Connecticut, LLC, the purchaser of these generation facilities. See Note
(C),  "Rate-Related  Regulatory  Proceedings"  above,  for a description of this
transaction.

     As of August 3, 1999  there  were 36  business  processes  remaining  to be
determined as Year 2000 ready.  The summary of remaining  business  processes by
department and priority level is as follows:

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<PAGE>

                        Priority 1  Priority 2   Priority 3  Priority 4   Total

Customer Services          1           20            8           1          30
Support Services           0            0            1           0           1
Controller's Department    2            0            0           0           2
                        --------------------------------------------------------
    Total                  3           20            9           1          33
                        ========================================================

       Priority  one   processes   are  those   defined  as  affecting   safety,
reliability, regulatory compliance or having a significant financial impact. The
priority  one Customer  Services  process  relates to the  Customer  Information
System  that has been 100%  tested  but is under  continuous  change  due to the
electric industry restructuring in Connecticut.  The Controller's department has
two systems awaiting  modification and testing,  the accounts payable system and
the  general  ledger  system.  All  priority  one  systems are to be complete by
December  31,  1999.  Priority  two  implies  that  failure of this  software or
hardware  will present a disruption  of service at current  budget  levels,  but
work-arounds  with negative  implications for current service or cost levels are
available,  if needed.  Priority  three implies that failure of this software or
hardware may present an  inconvenience  to occasional  work  requirements  or an
impediment  to  achievement  of  higher  service  or  lower  cost  levels,   but
alternative work-arounds can be pursued if deemed necessary at some future date.
Priority  four implies that failure of this  software or hardware will produce a
nuisance  or  confusion  but will  not  present  any  direct  negative  business
consequence.  As of August 3, 1999, the Company had completed the assessment and
remediation phases of its program for these non-priority one business processes,
which  are in  various  stages  of the  testing  and  approval  process  and are
projected to be completed by September 1, 1999.

     UI  has  successfully  complied  with  all  regulatory  requirements.  Most
recently, UI successfully  completed a Connecticut  Department of Public Utility
Control  audit along with eight other  utilities in the state.  The Company also
provides monthly reports to the North American Electric  Reliability  Council on
the  Year   compliance   2000   status   of  its   transmission,   distribution,
telecommunication and system control and data acquisition assets.

     Requests  for  documented  compliance  information  have  been  sent to all
critical suppliers,  data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed.  While failure to achieve Year 2000  compliance by any one of a number
of critical  suppliers  and data sharers  could have some adverse  effect on the
success of the Company's  implementation  program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications  providers,  the other  participants in the New England Power
Pool  (NEPOOL),  and the  Independent  System  Operator  (ISO) that operates the
NEPOOL bulk power supply system.  Year 2000 compliance  failures by any of these
entities could have a material effect on electricity  delivery and telemetering.
In its efforts to mitigate these risks,  the Company has taken several  actions.
UI has  communicated its concerns to its principal  telecommunications  provider
and a joint  effort to design and plan  appropriate  testing to insure  that all
critical  telecommunications  functions will be operational  has commenced.  The
Year 2000 Issue is also being  addressed at the regional level by NEPOOL and the
ISO. Coordination efforts with NEPOOL to establish utility testing and readiness
are in  progress.  The  Company  is a  participant  in all of the  subcommittees
working  within  NEPOOL/ISO on efforts to assure  operational  reliability.  The
Company is also  actively  involved with  NEPOOL/ISO in the planning  effort for
integrated  contingency  planning,  as directed by the North  American  Electric
Reliability  Council  (NERC).  The first  NERC  directed  test was  successfully
completed on April 9, 1999.

     Aside from  telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant   risk  to  the  success  of  the  Company's  Year  2000  compliance
implementation  program.  In order to minimize these risks, the Company has been
and will be  actively  involved in  contingency  planning.  While the  Company's
knowledge and experience in electric system recovery  planning and execution has
been  demonstrated  in the  past,  the  Company  recognizes  the need  for,  and
importance  of, Year  2000-specific  contingency  planning,  because the complex
interaction of today's computing and communications  systems precludes certainty
that all critical system remediation will be successful.  High level contingency
planning for essential business  processes has been completed.  These plans will
be continually  reviewed,  revised and modified  throughout the remainder of the
year  as  appropriate.   As  a  part  of  the  contingency   planning   process,
consideration will be given to potential frequency and duration of interruptions
in  the  generating,   financial  and  communications


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<PAGE>

infrastructures.  Since  contingency  planning  is,  by  nature,  a  speculative
process,  there can be no assurance that this planning will completely eliminate
the  risk of  material  impacts  to the  Company's  business  due to  Year  2000
problems.  However,  the Company recognizes the importance to its customers of a
reliable supply of electricity,  and it intends to devote whatever resources are
necessary to assure that both the program and its implementation are successful.

     The Company  believes that the  successful  implementation  of this program
should  ultimately  cost  approximately  $6.1 million for  existing  information
systems and embedded technology. A total of $5.2 million had been expended as of
June 30, 1999. As systems testing progresses and more embedded technology vendor
product information is forthcoming,  business decisions made and testing results
verified, the need for increased expenditures, if necessary, will be determined.
The Company  believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.


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<PAGE>

                                   SIGNATURES

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

                         THE UNITED ILLUMINATING COMPANY




Date     11/03/99        Signature              /s/ Robert L.Fiscus
    ----------------               -------------------------------------------
                                                    Robert L. Fiscus
                                        Vice Chairman of the Board of Directors
                                                  and Chief Financial Officer



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