SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549


                                  FORM 10-Q/A-2

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

                 FOR THE QUARTERLY PERIOD ENDING MARCH 31, 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 March 31, 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 months
           ended March 31, 1999 and 1998.                                  4
         Consolidated Balance Sheet as of March 31, 1999
           and December 31, 1998.                                          5
         Consolidated Statement of Cash Flows for the three months
           ended March 31, 1999 and 1998.                                  7

         Notes to Consolidated Financial Statements.                       8
           -   Statement of Accounting Policies                            8
           -   Capitalization                                              8
           -   Rate-Related Regulatory Proceedings                         9
           -   Short-term Credit Arrangements                             12
           -   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                     17
                  - Connecticut Yankee                                    17
                  - Hydro-Quebec                                          17
                  - Environmental Concerns                                18
                  - 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                                            25

         SIGNATURES                                                       30



                                      - 2 -
<PAGE>



     This  amendment  to the  Quarterly  Report  on  Form  10-Q  of  The  United
Illuminating  Company (the  "Company") for the quarter ended March 31, 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 amend
the "Consolidated  Statement of Cash Flows" and "Consolidated  Balance Sheet" to
specify that they have been  restated  from those  included in the Original Form
10-Q.

                                      - 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
                                                                            March 31,
                                                                     1999                1998
                                                                     ----                ----

<S>                                                                  <C>                 <C>
OPERATING REVENUES (NOTE G)                                          $168,667            $162,474
                                                                 -------------       -------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                   33,899              40,541
     Capacity purchased                                                 9,062               6,222
     Other                                                             38,754              33,309
  Maintenance                                                           9,446              11,033
  Depreciation (Note G)                                                17,739              20,806
  Amortization of cancelled nuclear project,
        deferred return and regulatory tax asset                        7,026               3,440
  Income taxes (Note F)                                                15,525              11,487
  Other taxes (Note G)                                                 14,009              12,959
                                                                 -------------       -------------
       Total                                                          145,460             139,797
                                                                 -------------       -------------
OPERATING INCOME                                                       23,207              22,677
                                                                 -------------       -------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                      13                  30
  Other-net (Note G)                                                     (469)                445
  Non-operating income taxes                                              891                  83
                                                                 -------------       -------------
       Total                                                              435                 558
                                                                 -------------       -------------
INCOME BEFORE INTEREST CHARGES                                         23,642              23,235
                                                                 -------------       -------------
INTEREST CHARGES
  Interest on long-term debt                                           12,227              13,523
  Interest on Seabrook obligation bonds owned by the company           (1,711)             (1,818)
  Dividend requirement of mandatorily redeemable securities             1,203               1,203
  Other interest (Note G)                                               1,856                 844
  Allowance for borrowed funds used during construction                  (448)               (129)
                                                                 -------------       -------------
                                                                       13,127              13,623
  Amortization of debt expense and redemption premiums                    614                 650
                                                                 -------------       -------------
       Net Interest Charges                                            13,741              14,273
                                                                 -------------       -------------

NET INCOME                                                              9,901               8,962
Dividends on preferred stock                                               51                  51
                                                                 -------------       -------------
INCOME APPLICABLE TO COMMON STOCK                                      $9,850              $8,911
                                                                 =============       =============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                    14,042              13,987
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                  14,044              13,997

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                  $0.70               $0.64

CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK                       $0.72               $0.72
</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)
                                   AS RESTATED
                                                       March 31,         December 31,
                                                         1999                1998*
                                                         ----                ----
                                                      (Unaudited)
<S>                                                      <C>                 <C>
Utility Plant at Original Cost
  In service                                             $1,888,526          $1,886,930
  Less, accumulated provision for depreciation              729,772             714,375
                                                    ----------------    ----------------
                                                          1,158,754           1,172,555

Construction work in progress                                29,622              33,695
Nuclear fuel                                                 24,944              20,174
                                                    ----------------    ----------------
     Net Utility Plant                                    1,213,320           1,226,424
                                                    ----------------    ----------------


Other Property and Investments                               38,507              37,873
                                                    ----------------    ----------------

Current Assets
  Unrestricted cash and temporary cash investments           15,794              97,689
   Restricted cash                                           26,503              26,812
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                           55,469              54,178
   Other, less allowance for doubtful accounts
     of  $775 and $631                                       51,836              64,240
  Accrued utility revenues                                   21,450              21,079
  Fuel, materials and supplies, at average cost              34,040              33,613
  Prepayments                                                12,468               7,424
  Other                                                       1,503                 154
                                                    ----------------    ----------------
     Total                                                  219,063             305,189
                                                    ----------------    ----------------

Deferred Charges
  Unamortized debt issuance expenses                          9,105               9,421
  Other                                                       2,477               1,664
                                                    ----------------    ----------------
     Total                                                   11,582              11,085
                                                    ----------------    ----------------

Regulatory Assets (future amounts due from customers
                   through the ratemaking process)
  Income taxes due principally to book-tax differences      259,452             264,811
  Connecticut Yankee                                         40,861              42,633
  Deferred return - Seabrook Unit 1                           9,439              12,586
  Unamortized redemption costs                               23,175              23,468
  Unamortized cancelled nuclear projects                     10,659              10,952
  Uranium enrichment decommissioning cost                     1,143               1,177
  Other                                                       4,613               4,962
                                                    ----------------    ----------------
     Total                                                  349,342             360,589
                                                    ----------------    ----------------

                                                         $1,831,814          $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)
                                         AS RESTATED

                                                            March 31,           December 31,
                                                               1999                1998*
                                                           (Unaudited)
<S>                                                             <C>                  <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                 $292,006             $292,006
    Paid-in capital                                                 2,108                2,046
    Capital stock expense                                          (2,182)              (2,182)
    Unearned employee stock ownership plan equity                  (9,972)             (10,210)
    Retained earnings                                             163,587              163,847
                                                         -----------------    -----------------
                                                                  445,547              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                                                730,586              757,370
    Investment in Seabrook obligation bonds                       (87,413)             (92,860)
                                                         -----------------    -----------------
      Net long-term debt                                          643,173              664,510
                                                         -----------------    -----------------

          Total                                                 1,138,720            1,164,316
                                                         -----------------    -----------------

Noncurrent Liabilities
  Connecticut Yankee contract obligation                           30,759               32,711
  Pensions accrued                                                 27,412               31,097
  Nuclear decommissioning obligation                               24,213               23,045
  Obligations under capital leases                                 16,415               16,506
  Other                                                             6,358                6,622
                                                         -----------------    -----------------
          Total                                                   105,157              109,981
                                                         -----------------    -----------------

Current Liabilities
  Current portion of preferred stock                                4,299                             -
  Current portion of long-term debt                                 6,806               66,202
  Notes payable                                                    82,172               86,892
  Accounts payable                                                 21,202               48,749
  Accounts payable - APS utility customers                         49,581               54,515
  Dividends payable                                                10,160               10,155
  Taxes accrued                                                    23,440                9,015
  Interest accrued                                                 14,108               10,203
  Obligations under capital leases                                    354                  348
  Other accrued liabilities                                        36,585               39,845
                                                         -----------------    -----------------
          Total                                                   248,707              325,924
                                                         -----------------    -----------------

Customers' Advances for Construction                                1,866                1,867
                                                         -----------------    -----------------

Regulatory Liabilities (future amounts owed to customers
                        through the ratemaking process)
  Accumulated deferred investment tax credits                      15,433               15,623
  Other                                                             3,051                2,065
                                                         -----------------    -----------------
          Total                                                    18,484               17,688
                                                         -----------------    -----------------

Deferred Income Taxes (future tax liabilities owed
                       to taxing authorities                      318,880              321,384
Commitments and Contingencies (Note L)
                                                         -----------------    -----------------
                                                               $1,831,814           $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)
                                   AS RESTATED
                                                                        Three Months Ended
                                                                            March 31,
                                                                      1999              1998
                                                                      ----              ----
<S>                                                                   <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                            $9,901           $8,962
                                                                   ------------      -----------
  Adjustments to reconcile net income to net cash
   provided by operating activities:
     Depreciation and amortization                                      22,466           21,851
     Deferred income taxes                                                (732)          (2,251)
     Deferred investment tax credits - net                                (190)            (190)
     Amortization of nuclear fuel                                        3,191            1,265
     Allowance for funds used during construction                         (461)            (159)
     Amortization of deferred return                                     3,147            3,147
     Changes in:
                   Accounts receivable - net                            11,113            4,159
                   Fuel, material and supplies                            (427)          (3,768)
                   Prepayments                                          (5,044)          (2,968)
                   Accounts payable                                    (32,481)         (14,818)
                   Interest accrued                                      3,905            2,528
                   Taxes accrued                                        14,425           11,919
                   Other assets and liabilities                         (9,818)          (2,792)
                                                                   ------------      -----------
     Total Adjustments                                                   9,094           17,923
                                                                   ------------      -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES                               18,995           26,885
                                                                   ------------      -----------

CASH FLOWS FROM FINANCING ACTIVITIES
  Common stock                                                             300            4,015
  Long-term debt                                                             -           99,780
  Notes payable                                                         (4,720)           7,369
  Securities redeemed and retired:
    Long-term debt                                                     (86,202)        (133,976)
  Expense of issue                                                           -             (800)
  Lease obligations                                                        (85)             (82)
  Dividends
    Preferred stock                                                        (51)             (51)
    Common stock                                                       (10,104)         (10,000)
                                                                   ------------      -----------
NET CASH USED IN FINANCING ACTIVITIES                                 (100,862)         (33,745)
                                                                   ------------      -----------

CASH FLOWS FROM INVESTING ACTIVITIES
   Plant expenditures, including nuclear fuel                           (5,784)          (8,356)
   Investment in debt securities                                         5,447            8,528
                                                                   ------------      -----------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES                       (337)             172
                                                                   ------------      -----------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                              (82,204)          (6,688)
BALANCE AT BEGINNING OF PERIOD                                         124,501           53,065
                                                                   ------------      -----------
BALANCE AT END OF PERIOD                                                42,297           46,377
LESS: RESTRICTED CASH                                                   26,503           32,709
                                                                   ------------      -----------
BALANCE: UNRESTRICTED CASH                                             $15,794          $13,668
                                                                   ============      ===========

CASH PAID DURING THE PERIOD FOR:
  Interest (net of amount capitalized)                                  $6,306          $10,626
                                                                   ============      ===========
  Income taxes                                                          $3,700           $2,900
                                                                   ============      ===========
</TABLE>



          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  to a fair
statement of the results for the periods presented.  All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial  statements prepared in accordance with generally accepted
accounting  principles have been condensed or omitted pursuant to such rules and
regulations.  The Company believes that the disclosures are adequate to make the
information  presented not misleading.  These consolidated  financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year  ended  December  31,  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 three months of 1999
and 1998 was 7.0% and 8.0%, respectively, 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  $666,000 and $645,000 in the first three
months of 1999 and 1998, respectively,  into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 1999, the Company's shares of
the trust fund balances,  which included accumulated earnings on the funds, were
$17.4  million  and $6.9  million  for  Seabrook  Unit 1 and  Millstone  Unit 3,
respectively.   These  fund  balances  are  included  in  "Other   Property  and
Investments"  and  the  accrued   decommissioning   obligation  is  included  in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.

 (B)  CAPITALIZATION

     (a) COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding at March 31, 1999, of which 293,374 shares were  unallocated  shares
held by the Company's  Employee Stock Ownership Plan ("ESOP") and not recognized
as outstanding for accounting purposes.

     In 1990, the Company's  Board of Directors and the  shareowners  approved a
stock  option plan for  officers  and key  employees  of the  Company.  The plan
provides  for the  awarding of options to  purchase up to 750,000  shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are  granted.  The  Connecticut  Department  of Public  Utility
Control  (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan.  The  exercise  price of each  option  cannot be less than the market
value of the stock on the date of the grant. Options to purchase 3,500 shares of
stock  at an  exercise  price  of $30 per  share,  7,800  shares  of stock at an
exercise  price of $39.5625 per share,  and 5,000 shares of stock at an exercise
price of $42.375  per share  have been  granted  by the Board of  Directors  and
remained  outstanding  at March 31, 1999. No options were  exercised  during the
first quarter of 1999.


                                      - 8 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     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 March 31,  1999,  293,374  shares,  with a fair market value of
$12.3  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
$105.4 million were free from such limitations at March 31, 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.

(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


                                     - 9 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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," an "energy  conservation and load management  program charge"
and  a  "renewable  energy  investment  charge".   The  competitive   transition
assessment  represents  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 (so-called stranded costs). 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 energy  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 on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments,  to be the total rate charged under the standard  offer,  including
generation  and  transmission  and   distribution   services,   the  competitive
transition assessment,  the systems benefits charge, the energy 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
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.

      The Company has received  approximately  $277.9  million in cash from this
sale of its operating fossil-fueled generating stations, which amount is subject
to certain post-closing adjustments. The Company realized a small book gain from
the  sale  proceeds  net of taxes  and  plant  investment.  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


                                      - 10 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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 draft decision
dated April 23, 1999, the DPUC  tentatively  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 draft  decision  dated April
23, 1999, the DPUC tentatively approved the proposed corporate restructuring.  A
final decision is expected in late May. 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.

      Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power  supply  providers  after June 30, 2000.  The Company
will be required to offer  fully-bundled  service to customers under a regulated
"standard  offer"  rate and will also become the power  supply  provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power  generation.  In order
to mitigate the financial risk that these regulated  service  mandates will pose
to the Company in an unregulated  power generation  environment,  its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates,  effective  July 1, 2000,  as permitted by the  Restructuring  Act.  This
clause,  similar to and based on the  purchased gas  adjustment  clauses used by
Connecticut's  natural gas local  distribution  companies,  would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay  competitive  market rates for power supply  services and that the
Company collects its costs of providing such services.  The Distribution Company
is also required  under the  Restructuring  Act to provide  back-up power supply
service to  customers  whose  electric  supplier  fails to provide  power supply
services for reasons other than the customers' failure to pay for such services.
The  Restructuring  Act  provides  for the  Distribution  Company to recover its
reasonable costs of providing this back-up service.

     On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible  for  providing a standard  offer  service to  customers  who do not
choose an alternate electricity supplier.  The standard offer prices,  including
the fully-bundled price of generation,  transmission and distribution  services,
the  competitive  transition  assessment,  the systems  benefits  charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational  review order (see below)  anticipated
sufficient  income in 2000 to accelerate  amortization  of regulatory  assets of
about $50 million, equivalent to about 8% of retail revenues.  Substantially all
of this  accelerated  amortization  may have to be  eliminated  to allow for the
additional  standard  offer price  reduction  requirement  of 10%, at a minimum,
while  providing for the added costs imposed by the  restructuring  legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.



                                     - 11 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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 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
March 31, 1999, the Company had no short-term borrowings  outstanding under this
facility.

     On April 16,  1999,  the  Company  repaid  and  terminated  an $80  million
revolving credit agreement prior to its June 7, 1999 due date.



                                      - 12 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     In  addition,  as  of  March  31,  1999,  one  of  the  Company's  indirect
subsidiaries,  American  Payment  Systems,  Inc., had borrowings of $2.1 million
outstanding under a bank line of credit agreement.


                                     - 13 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(F) INCOME TAXES

                                                      Three Months Ended
                                                           March 31,
                                                    1999               1998
                                                    ----               ----
                                                             (000's)
Income tax expense consists of:

Income tax provisions:
  Current
           Federal                                   $12,337            $10,719
           State                                       3,219              3,126
                                                -------------      -------------
               Total current                          15,556             13,845
                                                -------------      -------------
  Deferred
           Federal                                      (154)            (1,551)
           State                                        (578)              (700)
                                                -------------      -------------
               Total deferred                           (732)            (2,251)
                                                -------------      -------------

  Investment tax credits                                (190)              (190)
                                                -------------      -------------
     Total income tax expense                        $14,634            $11,404
                                                =============      =============

Income tax components charged as follows:
  Operating expenses                                 $15,525            $11,487
  Other income and deductions - net                     (891)               (83)
                                                -------------      -------------
     Total income tax expense                        $14,634            $11,404
                                                =============      =============


The following table details the components
 of the deferred income taxes:
     Seabrook sale/leaseback transaction             ($2,082)           ($2,181)
     Pension benefits                                  1,525                600
     Accelerated depreciation                          1,250              1,534
     Tax depreciation on unrecoverable plant
       investment                                      1,188              1,212
     Unit overhaul and replacement power costs          (898)              (398)
     Conservation and load management                   (873)            (2,007)
     Postretirement benefits                            (433)              (102)
     Other - net                                        (409)              (909)
                                                -------------      -------------
Deferred income taxes - net                            ($732)           ($2,251)
                                                =============      =============


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

                     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION

<CAPTION>
                                                               Three Months Ended
                                                                    March 31,
                                                             1999               1998
                                                             ----               ----
                                                                    (000's)
<S>                                                       <C>                <C>
Operating Revenues
------------------
     Retail                                                $152,391           $146,545
     Wholesale - capacity                                     1,854              3,426
               - energy                                      11,739             11,389
     Other                                                    2,683              1,114
                                                       -------------      -------------
          Total Operating Revenues                         $168,667           $162,474
                                                       =============      =============

Sales by Class(MWH's)
---------------------
    Retail
     Residential                                            533,768            488,329
     Commercial                                             553,798            564,789
     Industrial                                             269,060            265,628
     Other                                                   12,199             12,173
                                                       -------------      -------------
                                                          1,368,825          1,330,919
    Wholesale                                               652,746            508,317
                                                       -------------      -------------
          Total Sales by Class                            2,021,571          1,839,236
                                                       =============      =============

Depreciation
------------
     Plant in Service                                       $14,655            $14,330
     Amortization Conservation and
        Load Management Costs                                 2,418              5,657
     Nuclear Decommissioning                                    666                819
                                                       -------------      -------------
                                                            $17,739            $20,806
                                                       =============      =============

Other Taxes
-----------
    Charged to:
     Operating:
        State gross earnings                                 $5,854             $5,621
        Local real estate and personal property               6,326              5,482
        Payroll taxes                                         1,829              1,856
                                                       -------------      -------------
                                                             14,009             12,959
     Nonoperating and other accounts                            134                148
                                                       -------------      -------------
          Total Other Taxes                                 $14,143            $13,107
                                                       =============      =============

Other Income and (Deductions) - net
-----------------------------------
     Interest income                                           $667               $320
     Equity earnings from Connecticut Yankee                    181                307
     Earnings (Loss) from subsidiary companies               (1,206)               195
     Miscellaneous other income and (deductions) - net         (111)              (377)
                                                       -------------      -------------
          Total Other Income and (Deductions) - net           ($469)              $445
                                                       =============      =============

Other Interest Charges
----------------------
     Notes Payable                                           $1,284               $518
     Other                                                      572                326
                                                       -------------      -------------
          Total Other Interest Charges                       $1,856               $844
                                                       =============      =============
</TABLE>

                                      - 15 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(K)  FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS

     The Company has a Fossil Fuel Supply Agreement with a financial institution
providing  for the  financing of up to $37.5  million of fossil fuel  purchases.
Under this agreement, the financing entity may acquire and/or store natural gas,
coal and fuel oil for sale to the Company,  and the Company may  purchase  these
fossil  fuels  from the  financing  entity at a price for each type of fuel that
reimburses  the  financing  entity  for the  direct  costs  it has  incurred  in
purchasing and storing the fuel,  plus a charge for  maintaining an inventory of
the fuel determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed  commercial  paper in New York. The Company is obligated to insure
the  fuel  inventories  and  to  indemnify  the  financing  entity  against  all
liabilities,  taxes and other  expenses  incurred as a result of its  ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to May 2000, when it will terminate. At March 31, 1999, no fossil fuel purchases
were being  financed under this  agreement.  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 will not finance any fuel purchases  under this  agreement  prior to its
termination in May 2000.

(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.



                                      - 16 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

OTHER COMMITMENTS AND CONTINGENCIES

                               CONNECTICUT YANKEE

     On December  4, 1996,  the Board of  Directors  of the  Connecticut  Yankee
Atomic  Power  Company  (Connecticut  Yankee)  voted  unanimously  to retire the
Connecticut  Yankee nuclear plant (the Connecticut  Yankee Unit) from commercial
operation.  The Company has a 9.5% stock ownership share in Connecticut  Yankee.
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  $10.1
million)  and return on  investment  (approximately  $4.5  million) at March 31,
1999, is approximately $30.8 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
March  31,  1999,   the  Company's   guarantee   liability  for  this  debt  was
approximately $6.7 million.



                                      - 17 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

                             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 and air quality  (particularly  "air  toxics"
and "global warming"),  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.

             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 March 31, 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 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  quarter of 1999 was $0.5  million.  UI's share of the fund at
March 31, 1999 was approximately $17.4 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


                                      - 18 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

decommissioning  trust fund managed by Northeast  Utilities  (NU). UI's share of
the Millstone Unit 3  decommissioning  payments made during the first quarter of
1999  was  $0.1  million.  UI's  share  of  the  fund  at  March  31,  1999  was
approximately $6.9 million.  The current  decommissioning  cost estimate for the
Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit
commencing in 1997,  is $476 million,  of which UI's share would be $45 million.
Through March 31, 1999, $93.0 million has been expended for decommissioning. The
projected  remaining  decommissioning  cost is $391 million, of which UI's share
would be $37 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 $0.6  million  were funded by UI
during the first  quarter of 1999,  and UI's share of the fund at March 31, 1999
was $24.1 million.

(Q)  RESTATEMENT OF FINANCIAL RESULTS

     Subsequent  to filing its Form 10-Q for the quarter  ended March 31,  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 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 March 31, 1999 and December 31, 1998.  However,  as a
result of this review,  the Company has included in restricted  cash as of March
31, 1999 and  December  31, 1998  amounts of $23.3  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 March 31, 1999 and December 31,
1998  amounts of $22.1  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 on December 31,
       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 March 31, 1999, the Company had $19.0 million of cash and temporary cash
investments,  including the Seabrook operating deposit, but excluding restricted
cash of American Payment Systems, Inc. This was a decrease of $82.4 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                            18.8

  Net cash provided by (used in) financing activities:
  - Financing  activities,  excluding  dividend  payments             (90.7)
  - Dividend payments                                                 (10.2)
  Net cash  provided by  investing  activities,  excluding
       investment in plant                                              5.5
  Cash invested in plant,  including  nuclear fuel                     (5.8)

             Net Change in Cash                                       (82.4)
                                                                      -----
  Balance, March 31, 1999                                             $19.0
                                                                      =====


     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      $34.5       $9.0      $42.7      $  -
Internally Generated Funds less Dividends (2)             98.4       59.4       57.4       64.4       72.7
Net Proceeds from Sale of Fossil Generation Plants       160.0        -           -          -          -
                                                         -----      -----       ----      -----       ----
         Subtotal                                        359.8       93.9       66.4      107.1       72.7

Less:
Capital Expenditures (excluding AFUDC) (2)                30.7       34.5       23.4       18.9       23.3
                                                         -----      -----       ----      -----       ----

Cash Available to pay Debt Maturities and Redemptions    329.1       59.4       43.0       88.2       49.4

Less:
Maturities and Mandatory Redemptions                      69.6        0.4        0.3      100.3      100.5
Optional Redemptions                                     145.0       50.0         -          -          -
Repayment of Short-Term Borrowings                        80.0         -          -          -          -
                                                         -----      -----       ----      -----      -----

External Financing Requirements (Surplus)               $(34.5)     $(9.0)    $(42.7)     $12.1      $51.1
                                                         =====      =====     ======      =====      =====
</TABLE>

(1)    Includes Seabrook Unit 1 operating deposit, but not restricted cash of
       American Payments 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.

     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
March 31, 1999, the Company had no 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.  The  largest  URI  subsidiary,
American  Payment  Systems,  Inc.,  manages a national network of agents for the
processing  of bill  payments  made by customers of UI and other  utilities.  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.,  provides
power-related  equipment  and  services to the owners of  commercial  buildings,
government buildings and industrial facilities. URI's fourth subsidiary,  United
Bridgeport Energy,  Inc., is a 33 1/3% owner of Bridgeport Energy, LLC, which is
completing construction of a 500-megawatt merchant wholesale electric generating
facility in Bridgeport, Connecticut.

                              RESULTS OF OPERATIONS

FIRST QUARTER OF 1999 VS. FIRST QUARTER OF 1998
-----------------------------------------------

     Earnings for the first quarter of 1999 were $9.9 million, or $.70 per share
(on both a basic and diluted basis),  up $1.0 million,  or $.06 per share,  from
the first quarter of 1998.  Excluding  one-time items,  earnings from operations
were $9.3 million,  or $.66 per share,  up $.02 per share from the first quarter
of 1998.



                                      - 23 -
<PAGE>

     The one-time items recorded in the first quarter of 1999 were:
                                                                          EPS
 ------------------------------------------------------------------------------
  1999 Quarter 1   Purchased power expense refund                       $.12
                   "Sharing" of earnings due to refund                 $(.08)
 ------------------------------------------------------------------------------

     Retail  revenues  from  operations  increased  by $6.8 million in the first
quarter  of 1999  compared  to the first  quarter  of 1998,  as  electric  sales
increased for reasons detailed below.  Retail revenues decreased by $1.0 million
because of "sharing" of earnings 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  decreased by $5.0 million,  primarily from lower fossil
fuel prices,  and there was an increase of $0.2 million in revenue-based  taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
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%                     4.3
 ------------------------------------------------------------------ -----------
   Estimate of weather affect on retail sales, up 1.6%                 2.4
 ------------------------------------------------------------------ -----------
   Sales decrease from Yale University cogeneration, (1.7)%           (2.5)
 ------------------------------------------------------------------ -----------
   Price mix of sales and other                                        2.5
 ------------------------------------------------------------------ -----------
   "Sharing" due to one-time gain                                     (1.0)
 ------------------------------------------------------------------ -----------
 Fuel and energy, margin effect:
 ------------------------------------------------------------------ -----------
   Sales increase                                                     (0.7)
 ------------------------------------------------------------------ -----------
   Nuclear fuel prices to account for previously spent fuel           (0.8)
 ------------------------------------------------------------------ -----------
   Fossil fuel price                                                   6.6
 ------------------------------------------------------------------ -----------

     Net wholesale margin (wholesale  revenue less wholesale  expense) decreased
by $2.2 million in the first  quarter of 1999  compared to the first  quarter of
1998 from lower  wholesale  capacity  sales.  Other  operating  revenues,  which
include NEPOOL related transmission revenues,  increased by $1.6 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 (FERC).

     It should be noted that on April 16, 1999,  the Company  completed the sale
of its operating  fossil-fueled  generating plants and existing  wholesale sales
contracts (known as the Generation  Asset  Divestiture or GAD) that was required
by  Connecticut's  electric  utility industry  restructuring  legislation.  As a
result of GAD, the "geography" of the Company's  costs on the income  statement,
and hence, the year-over-year  variances, will change significantly beginning in
the second quarter. This particularly relates to wholesale revenue,  fossil fuel
expense, operations and maintenance expense,  depreciation and interest charges.
See "Looking Forward" below for more details.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  increased by $6.7 million in the first  quarter of 1999 compared to the
first  quarter  of 1998.  The  principal  components  of these  expense  changes
include:
                                                                    $ millions
  ------------------------------------------------------------------ ---------
  Capacity expense:
  ------------------------------------------------------------------ ---------
    Connecticut Yankee                                                (0.4)
  ------------------------------------------------------------------ ---------
    Cogeneration and other purchases (see Note)                        3.2
  ------------------------------------------------------------------ ---------
  Other O&M expense:
  ------------------------------------------------------------------ ---------
    Seabrook Unit (refueling outage and accruals)                      1.9
  ------------------------------------------------------------------ ---------
    Millstone Unit 3                                                  (0.2)
  ------------------------------------------------------------------ ---------
    Fossil generation unit overhaul and outage costs                  (1.6)
  ------------------------------------------------------------------ ---------
    NEPOOL transmission expense                                        0.9
  ------------------------------------------------------------------ ---------
    Other miscellaneous                                                2.9
  ------------------------------------------------------------------ ---------

                                     - 24 -
<PAGE>

 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 increased by $0.2 million in the first quarter of 1999
compared to the first quarter of 1998.

     On December 31, 1996, the Connecticut  Department of Public Utility Control
(DPUC)  issued an order (the 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
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  accelerated  amortization  for  1999,  or  $3.3  million
(before-tax,  $2.1 million  after-tax),  was recorded in the first quarter.  The
Company has begun amortizing  regulatory  income tax assets for the 1999 amount,
totaling  $12.1  million   (after-tax),   one-fourth  of  it,  or  $3.0  million
(after-tax), in the first 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%,  on an annual  basis.  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 the
first quarter.  There was no "sharing" recorded against earnings from operations
in the first quarter of 1998, or in 1999.

     Other net income  decreased by about $0.9  million in the first  quarter of
1999  compared  to first  quarter of 1998.  The  Company's  largest  unregulated
subsidiary,  American Payment Systems (APS), earned about $246,000  (before-tax)
in the first  quarter  of 1999,  slightly  less than the  $284,000  (before-tax)
earned in the first quarter of 1998. Income for Precision Power, Inc.  decreased
$0.7  million  (before-tax),  reflecting  increased  infrastructure  costs as it
prepares to expand its service  offerings.  The first  quarter  loss was in line
with  expectations  outlined  in  the  "Looking  Forward"  section  of  Item  7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations  in the  Company's  annual  report  on Form  10-K for the year  ended
December 31, 1998. Income from other unregulated subsidiary activities at United
Resources, Inc. decreased by $0.6 million (before-tax) from start-up costs.

     Interest  charges  continued on their  downward  trend,  decreasing by $0.2
million in the first quarter of 1999 compared to the first quarter of 1998. Most
of the reduction in interest charges  anticipated for 1999 compared to 1998 will
come after the GAD,  which was  completed on April 16, 1999.  On April 16, 1999,
the Company used proceeds  received from the sale of plant to repay $205 million
of debt. See "Looking Forward" below 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
-------------------

     The reader is referred to Note (C), "Rate-Related  Regulatory  Proceedings"
above, for a description of the Company's  five-year Rate Plan and Connecticut's
electric utility industry restructuring legislation.



                                      - 25 -
<PAGE>

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

     1999 will be a year of transition to the January 1, 2000  effective date of
electric utility restructuring legislation passed by the Connecticut legislature
in 1998. The Company has taken one major step toward  restructuring by effecting
the sale of its operating fossil fuel generation  plants and existing  wholesale
sales contracts (known as the Generation  Asset  Divestiture  program,  or GAD).
That sale was  completed on April 16, 1999.  All of the changes  resulting  from
GAD, described below, will occur beginning 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 about $920
million in 1999.  Offsetting the effect of the decline in total rate base is the
Company's  long-standing  policy of debt paydown that  increases  the portion of
rate base  financed  by equity.  The  portion of rate base that is  financed  by
equity is 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  would have  produced  earnings  of about $3.43 per share.
Absent the one-time items that reduced  earnings in 1998,  utility earnings from
operations  above $3.43 per share would have given rise to an imputed  "sharing"
benefit of an additional $.12 per share.  Because of the equity funded rate base
reduction  expected  in 1999,  the  allowed  11.5%  return  would be expected to
produce  utility  earnings in the $3.35-$3.40  per share range.  Currently,  the
Company  expects to be in a "sharing"  position in 1999,  to a somewhat  greater
extent than was the case for earnings from operations in 1998.

     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
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  has  reduced  total  Company  retail
kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The remaining impact
will be  reflected  in the first half of 1999.  Thus,  it would  require  "real"
growth of 0.5% in 1999  compared  to 1998  just to  maintain  the 1998  level of
"real" sales. "Real" growth in kilowatt-hour sales for the first quarter of 1999
compared to the first quarter of 1998 was estimated to be 2.9%,  only  partially
offset by a 1.7%  decrease  in sales to Yale  University.  Retail  kilowatt-hour
sales  growth of 1.0%,  on an  annual  basis,  produces  a retail  sales  margin
improvement of about $5.0 million, 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 to have 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 by about $4.0 million in
1999 relative to 1998,  due to increased  transmission  revenues  resulting from
NEPOOL restructuring  changes; but this should 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


                                      - 26 -
<PAGE>

anticipate,  at this time,  any other  significant  revenue  reductions  in 1999
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
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 that the Company has  adequate  resources  to meet  customer
energy  demands  until July 2000 (the price under this  short-term,  fixed-price
agreement  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 the retirement of the 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 and $1
million  for Y2K  costs and $4  million  due to  NEPOOL  transmission  operating
expense  charges  The  latter  would have no net  income  effect,  as the higher
transmission expense should be offset 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  sale,  partly  offset  by the  impact  of the  Company's  passive
financial  investment  increase 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  operated  on a
merchant  basis by Duke Energy in  Bridgeport,  Connecticut.  The  Company  also
expects to generate  substantial  cash flow from  operations  after dividend and
capital spending, which will also be used to reduce debt.

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

     Accelerated  amortization,  under 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 have
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 purchased power and increased  accelerated
amortization costs in 1999. This should allow utility earnings to increase above
an 11.5% return on utility  common stock equity into the "sharing"  range of the
Rate  Plan.  The 11.5%  return  level  would  allow for  utility  earnings  from
operations  of about  $3.35-$3.40  per share,  while the "shared"  earnings from
operations  above


                                      - 27 -
<PAGE>

that level are  currently  anticipated  to increase per share  earnings by about
$.20 per share,  although the size of this  increase will  fluctuate  with every
event that affects utility  operations during the year. 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 occasion a loss of up to $.10 per
share to earnings 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
would occasion a loss of $.10 to $.15 per share in 1999, if no  substantial  new
contracts are obtained.  PPI may also engage in  acquisition  activities in 1999
that may have  short-term  dilutive  effects on earnings  beyond those indicated
above.  For 2000 and beyond,  the  Company's  passive  financial  investment  in
Bridgeport  Energy is expected to increase  annual  earnings from  operations by
$.10 to $.15 per share.

     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 $3.45 to $3.65 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 this  "Looking
Forward" section in its entirety.

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

     The Company's  planning and  operations  functions,  and its cash flow, are
dependent  on the  timely  flow of  electronic  data to and from its  customers,
suppliers and other electric utility system managers and operators.  In order to
assure that this data flow will not be disturbed by the problems  emanating from
the fact that many existing computer programs were designed without  considering
the impact of the year 2000 and use only two digits to identify  the year in the
date field of the  programs  (the Year 2000  Issue),  the Company  initiated  in
mid-1997,  and is  pursuing,  an  aggressive  program to  identify  and  correct
deficiencies in its computer systems.  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 307 of them have
been verified as Year 2000 compliant through testing,  remediation,  replacement
or retirement.  The remediation  methodology  utilized has been Fixed Windowing,
and totally  independent  platforms  have been  installed for testing all of the
applications. Necessary upgrades to mainframe hardware and software are expected
to be  completed  and tested by June 30,  1999.  A parallel  program for desktop
hardware and application  software on all platforms is currently projected to be
completed and tested,  for all critical  systems,  by June 1, 1999,  except in a
minority of cases where a business specific need dictates a later date - but not
later than December 31, 1999.  Requests for  documented  compliance  information
have been sent to all critical  suppliers,  data  sharers and facility  building
owners  and,  as  responses  are  received,  appropriate  solutions  and testing
programs are being  developed and executed.  The Company  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.

     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


                                      - 28 -
<PAGE>

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 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
commenced its 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  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
will cost approximately $6 million for existing information systems and embedded
technology.  A total of $4.6 million had been  expended as of March 31, 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.


                                      - 29 -
<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   11/30/99          Signature          /s/ Robert L. Fiscus
    --------------                ------------------------------------------
                                                Robert L. Fiscus
                                     Vice Chairman of the Board of Directors
                                            and Chief Financial Officer



                                      - 30 -