SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549


                                  FORM 10-Q/A-1

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

                 FOR THE QUARTERLY PERIOD ENDING SEPTEMBER 30, 1999

                                       OR

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

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


Commission file number 1-6788

                         THE UNITED ILLUMINATING COMPANY

             (Exact name of registrant as specified in its charter)

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

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

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


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


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

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

     The  number of shares  outstanding  of the  issuer's  only  class of common
stock, as of September 30, 1999, was 14,334,922.



                                     - 1 -
<PAGE>




                                      INDEX

                          Part I. FINANCIAL INFORMATION

                                                                           Page
                                                                          Number
                                                                          ------

Item 1.  Financial Statements.                                               4

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

         Notes to Consolidated Financial Statements.                         8
           -   Statement of Accounting Policies                              8
           -   Capitalization                                                9
           -   Rate-Related Regulatory Proceedings                          10
           -   Short-term Credit Arrangements                               14
           -   Income Taxes                                                 15
           -   Supplementary Information                                    16
           -   Fuel Financing Obligations and Other Lease Obligations       17
           -   Commitments and Contingencies                                17
               -  Capital Expenditure Program                               17
               -  Nuclear Insurance Contingencies                           17
               -  Other Commitments and Contingencies                       17
                  - Connecticut Yankee                                      17
                  - Hydro-Quebec                                            18
                  - Environmental Concerns                                  18
                  - Site Decontamination, Demolition and Remediation Costs  19
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning      19
           -   Restatement of Financial Results                             20

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations.                                         22

           -   Major Influences on Financial Condition                      22
           -   Recovery of Stranded Costs                                   22
           -   Capital Expenditure Program                                  23
           -   Liquidity and Capital Resources                              24
           -   Subsidiary Operations                                        25
           -   Results of Operations                                        25
           -   Looking Forward                                              32

         SIGNATURES                                                         35



                                     - 2 -

<PAGE>
     This  amendment  to the  Quarterly  Report  on  Form  10-Q  of  The  United
Illuminating  Company (the  "Company") for the quarter ended  September 30, 1999
(the  "Original  Form 10-Q")  amends and modifies the Original  Form 10-Q by (a)
restating Part I: Financial  Information,  Item I: Financial Statements in order
to supplement and revise the "Consolidated  Statement of Income",  "Consolidated
Statement of Cash  Flows",  "Consolidated  Balance  Sheet," to specify that they
have been restated from those included in the Original Form 10-Q and Note (Q) to
the  Notes  to  Consolidated  Financial  Statements  and  Item 2:  "Management's
Discussion  and Analysis of Financial  Condition  and Results of  Operations  in
order to amend and supplement the section captioned, "Results of Operations".


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

                                                                           Three Months Ended              Nine Months Ended
                                                                              September 30,                  September 30,
                                                                          1999           1998            1999           1998
                                                                          ----           ----            ----           ----
                                                                                                                         AS
                                                                                                                      RESTATED
<S>                                                                      <C>           <C>             <C>            <C>
OPERATING REVENUES (NOTE G)                                              $199,071      $198,601        $532,271       $520,867
                                                                    --------------  ------------    ------------   ------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                       51,433        39,701         123,815        113,654
     Capacity purchased                                                     8,428         9,124          26,168         24,324
     Other                                                                 36,560        36,384         112,075        107,787
  Maintenance                                                               5,820        10,981          21,279         32,574
  Depreciation                                                             12,375        23,247          45,732         64,685
  Amortization of cancelled nuclear project,
       deferred return and regulatory tax asset                            11,444         3,440          24,934         10,319
  Income taxes (Note F)                                                    25,910        24,448          57,286         47,128
  Other taxes (Note G)                                                     12,918        13,814          38,399         39,083
                                                                    --------------  ------------    ------------   ------------
       Total                                                              164,888       161,139         449,688        439,554
                                                                    --------------  ------------    ------------   ------------
OPERATING INCOME                                                           34,183        37,462          82,583         81,313
                                                                    --------------  ------------    ------------   ------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                         347           (35)            614             35
  Other-net (Note G)                                                          307         1,798          (2,542)         2,682
  Non-operating income taxes                                                1,155           701           3,794          1,689
                                                                    --------------  ------------    ------------   ------------
       Total                                                                1,809         2,464           1,866          4,406
                                                                    --------------  ------------    ------------   ------------
INCOME BEFORE INTEREST CHARGES                                             35,992        39,926          84,449         85,719
                                                                    --------------  ------------    ------------   ------------
INTEREST CHARGES
  Interest on long-term debt                                                9,829        11,759          32,219         38,161
  Interest on Seabrook obligation bonds owned by the company               (1,711)       (1,817)         (5,133)        (5,453)
  Dividend requirement of mandatorily redeemable securities                 1,203         1,203           3,609          3,609
  Other interest (Note G)                                                   1,407         2,169           4,083          4,445
  Allowance for borrowed funds used during construction                      (327)         (241)         (1,098)          (505)
                                                                    --------------  ------------    ------------   ------------
                                                                           10,401        13,073          33,680         40,257
  Amortization of debt expense and redemption premiums                        594           617           1,885          1,885
                                                                    --------------  ------------    ------------   ------------
       Net Interest Charges                                                10,995        13,690          35,565         42,142
                                                                    --------------  ------------    ------------   ------------


NET INCOME                                                                 24,997        26,236          48,884         43,577
Premium (Discount) on preferred stock redemptions                            -             -                 53            (21)
Dividends on preferred stock                                                 -               50              66            151
                                                                    --------------  ------------    ------------   ------------
INCOME APPLICABLE TO COMMON STOCK                                         $24,997       $26,186         $48,765        $43,447
                                                                    ==============  ============    ============   ============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                        14,056        14,028          14,049         14,012
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                      14,058        14,032          14,051         14,018

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                      $1.78         $1.87           $3.47          $3.10

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



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


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

                                     ASSETS
                             (Thousands of Dollars)

                                                             September 30,        December 31,
                                                                 1999                 1998*
                                                                 ----                 ----
                                                              (Unaudited)         AS RESTATED
<S>                                                             <C>                 <C>
Utility Plant at Original Cost
  In service                                                    $1,514,999          $1,886,930
  Less, accumulated provision for depreciation                     528,087             714,375
                                                           ----------------    ----------------
                                                                  $986,912           1,172,555

Construction work in progress                                       34,941              33,695
Nuclear fuel                                                        22,036              20,174
                                                           ----------------    ----------------
     Net Utility Plant                                          $1,043,889           1,226,424
                                                           ----------------    ----------------


Other Property and Investments
  Investment in generation facility                                 88,684                        -
  Nuclear decommissioning trust fund assets                         26,854              23,045
  Other                                                             17,602              14,828
                                                           ----------------    ----------------
                                                                   133,140              37,873
                                                           ----------------    ----------------

Current Assets
  Unrestricted cash and temporary cash investments                  18,005              97,689
  Restricted cash                                                   35,999              26,812
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                                  71,914              54,178
   Other, less allowance for doubtful accounts of $796 and $631     58,147              64,240
  Accrued utility revenues                                          25,401              21,079
  Fuel, materials and supplies, at average cost                      7,887              33,613
  Prepayments                                                        5,647               7,424
  Other                                                              4,341                 154
                                                           ----------------    ----------------
     Total                                                         227,341             305,189
                                                           ----------------    ----------------

Deferred Charges
  Unamortized debt issuance expenses                                 8,422               9,421
  Other                                                              3,574               1,664
                                                           ----------------    ----------------
     Total                                                          11,996              11,085
                                                           ----------------    ----------------

Regulatory Assets (future amounts due from customers
                   through the ratemaking process)
  Income taxes due principally to book-tax differences             190,213             264,811
  Connecticut Yankee                                                38,122              42,633
  Deferred return - Seabrook Unit 1                                  3,147              12,586
  Unamortized redemption costs                                      22,589              23,468
  Unamortized cancelled nuclear projects                             9,073              10,952
  Uranium enrichment decommissioning cost                            1,074               1,177
  Other                                                             20,821               4,962
                                                           ----------------    ----------------
     Total                                                         285,039             360,589
                                                           ----------------    ----------------

                                                                 1,701,405          $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)

                                                                September 30,       December 31,
                                                                    1999               1998*
                                                                    ----               ----
                                                                 (Unaudited)        AS RESTATED
<S>                                                                <C>                <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                    $292,006           $292,006
    Paid-in capital                                                    2,187              2,046
    Capital stock expense                                             (2,171)            (2,182)
    Unearned employee stock ownership plan equity                     (9,497)           (10,210)
    Retained earnings                                                182,255            163,847
                                                              ---------------    ---------------
                                                                     464,780            445,507
  Preferred stock                                                       -                 4,299
  Company-obligated mandatorily redeemable securities of
    subsidiary holding solely parent debentures                       50,000             50,000
  Long-term debt
    Long-term debt                                                   605,623            757,370
    Investment in Seabrook obligation bonds                          (87,413)           (92,860)
                                                              ---------------    ---------------
      Net long-term debt                                             518,210            664,510
                                                              ---------------    ---------------

          Total                                                    1,032,990          1,164,316
                                                              ---------------    ---------------

Noncurrent Liabilities
  Connecticut Yankee contract obligation                              27,679             32,711
  Pensions accrued (Note H)                                           24,483             31,097
  Nuclear decommissioning obligation                                  26,854             23,045
  Obligations under capital leases                                    16,227             16,506
  Other                                                                5,438              6,622
                                                              ---------------    ---------------
          Total                                                      100,681            109,981
                                                              ---------------    ---------------

Current Liabilities
  Current portion of long-term debt                                    6,806             66,202
  Notes payable                                                       43,134             86,892
  Accounts payable                                                    34,080             48,749
  Accounts payable - APS utility customers                            68,337             54,515
  Dividends payable                                                   10,120             10,155
  Taxes accrued                                                       38,348              9,015
  Interest accrued                                                    14,154             10,203
  Obligations under capital leases                                       368                348
  Other accrued liabilities                                           33,395             39,845
                                                              ---------------    ---------------
          Total                                                      248,742            325,924
                                                              ---------------    ---------------

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

Regulatory Liabilities (future amounts owed to customers
                        through the ratemaking process)
  Accumulated deferred investment tax credits                         15,053             15,623
  Deferred gain on sale of property                                   15,745                  4
  Other                                                               17,489              2,061
                                                              ---------------    ---------------
          Total                                                       48,287             17,688
                                                              ---------------    ---------------

Deferred Income Taxes (future tax liabilities owed                   268,838            321,384
                       to taxing authorities)
Commitments and Contingencies (Note L)
                                                              ---------------    ---------------
                                                                  $1,701,405         $1,941,160
                                                              ===============    ===============
</TABLE>
* Derived from audited financial statements


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



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

                                                                  Three Months Ended           Nine Months Ended
                                                                     September 30,               September 30,
                                                                  1999          1998          1999          1998
                                                                  ----          ----          ----          ----
                                                               AS RESTATED                              AS RESTATED
<S>                                                              <C>           <C>          <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                     $24,997       $26,236       $48,884       $43,577
                                                            -------------  ------------  ------------  ------------
  Adjustments to reconcile net income to net cash
   provided by operating activities:
     Depreciation and amortization                                21,200        24,419        62,918        68,167
     Deferred income taxes                                         3,023           271         6,838        (2,991)
     Deferred income taxes - generation asset sale                     -             -       (70,222)            -
     Deferred investment tax credits - net                          (190)         (190)         (571)         (571)
     Amortization of nuclear fuel                                  1,978         1,641         6,658         4,138
     Allowance for funds used during construction                   (674)         (206)       (1,712)         (540)
     Amortization of deferred return                               3,146         3,146         9,439         9,439
     Changes in:
            Accounts receivable - net                            (26,987)      (11,973)      (11,643)      (22,542)
            Fuel, materials and supplies                             (42)        1,680           170        (9,882)
            Prepayments                                           (1,985)      (21,711)        1,777       (27,792)
            Accounts payable                                      20,824       (18,168)         (847)      (20,859)
            Interest accrued                                      (2,462)       (3,853)        3,951         4,064
            Taxes accrued                                          6,967        14,269        11,777        16,189
            Taxes accrued - generation asset sale                (17,555)            -        17,556             -
            Other assets and liabilities                          15,933         1,693       (20,800)        2,888
                                                            -------------  ------------  ------------  ------------
     Total Adjustments                                            23,176        (8,982)       15,289        19,708
                                                            -------------  ------------  ------------  ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES                         48,173        17,254        64,173        63,285
                                                            -------------  ------------  ------------  ------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Common stock                                                      284           308           853         4,618
   Long-term debt                                                      -             -             -        99,780
   Notes payable                                                  (5,550)       (5,630)      (43,758)       75,444
   Securities redeemed and retired:
     Preferred stock                                                   -             -        (4,299)          (52)
     Long-term debt                                                    -             -      (211,202)     (213,976)
   Discount (Premium) on preferred stock redemption                    -             -           (53)           21
   Expense of issue                                                    -             -             -          (800)
   Lease obligations                                                 (88)          (86)         (259)         (252)
   Dividends
     Preferred stock                                                   -           (50)         (116)         (152)
     Common stock                                                (10,114)      (10,095)      (30,329)      (30,185)
                                                            -------------  ------------  ------------  ------------
NET CASH USED IN FINANCING ACTIVITIES                            (15,468)      (15,553)     (289,163)      (65,554)
                                                            -------------  ------------  ------------  ------------

CASH FLOWS FROM INVESTING ACTIVITIES
    Investment in unregulated businesses                         (20,156)            -       (95,248)            -
    Net cash received from sale of generation assets                   -             -       270,590             -
    Plant expenditures, including nuclear fuel                    (9,770)       (9,047)      (26,296)      (19,616)
    Investment in debt securities                                      -             -         5,447         8,528
                                                            -------------  ------------  ------------  ------------
NET CASH (USED IN) PROVIDED BY ACTIVITIES                        (29,926)       (9,047)      154,493       (11,088)
                                                            -------------  ------------  ------------  ------------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                          2,779        (7,346)      (70,497)      (13,357)
BALANCE AT BEGINNING OF PERIOD                                    51,225        47,054       124,501        53,065
                                                            -------------  ------------  ------------  ------------
BALANCE AT END OF PERIOD                                          54,004        39,708        54,004        39,708
LESS: RESTRICTED CASH                                             35,999        30,135        35,999        30,135
                                                            -------------  ------------  ------------  ------------
BALANCE: UNRESTRICTED CASH                                       $18,005        $9,573       $18,005        $9,573
                                                            =============  ============  ============  ============

CASH PAID DURING THE PERIOD FOR:
   Interest (net of amount capitalized)                           $9,919       $13,895       $24,402       $33,345
                                                            =============  ============  ============  ============
   Income taxes                                                  $33,900       $12,100       $91,850       $35,150
                                                            =============  ============  ============  ============
</TABLE>

Note: Cash Flows from Operating Activities for the nine months ended September
      30, 1999 were reduced by the current income tax effects of the generation
      asset sale in the amount of $52,666.


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




                                      - 7 -
<PAGE>


                         THE UNITED ILLUMINATING COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                   (UNAUDITED)

     The consolidated  financial  statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange  Commission.  The statements  reflect
all  adjustments  that are, in the opinion of  management,  necessary for a fair
presentation of the results for the periods presented.  All such adjustments are
of a normal  recurring  nature.  Certain  information  and footnote  disclosures
normally included in financial  statements prepared in accordance with generally
accepted  accounting  principles have been condensed or omitted pursuant to such
rules and regulations. The Company believes that the disclosures are adequate to
make the information  presented not  misleading.  These  consolidated  financial
statements  should  be read  in  conjunction  with  the  consolidated  financial
statements and the notes to consolidated  financial  statements  included in the
annual  report on Form 10-K and Form  10-K/A-2  for the year ended  December 31,
1998. Such notes are supplemented as follows:

(A)  STATEMENT OF ACCOUNTING POLICIES

REGULATORY ACCOUNTING

     Generally accepted  accounting  principles for regulated entities allow the
Company to give accounting  recognition to the actions of regulatory authorities
in accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71,  "Accounting for the Effects of Certain Types of Regulation".  In
accordance  with SFAS No. 71, the Company has deferred  recognition  of costs (a
regulatory asset) or has recognized  obligations (a regulatory  liability) if it
is probable  that such costs will be  recovered or  obligations  relieved in the
future through the ratemaking  process. In addition to the Regulatory Assets and
Liabilities  separately  identified on the Consolidated Balance Sheet, there are
other regulatory assets and liabilities such as conservation and load management
costs and certain  deferred tax  liabilities.  The Company also has  obligations
under long-term power contracts, the recovery of which is subject to regulation.

     The effects of competition 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  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 the portion of the business that  continues to meet the criteria
for  application  of  SFAS  No.  71.  See  Note  (C),  "Rate-Related  Regulatory
Proceedings"  for a discussion  of the nature,  amount and timing of recovery of
the Company's  stranded  costs  associated  with the  generation  portion of its
assets and operations,  as well as a discussion of the regulatory decisions that
provide for such recovery.  Based on these regulatory decisions, the sale of the
Company's  fossil-generation  assets  in the  second  quarter  of 1999,  and the
planned divestiture of its nuclear generation  ownership interests by the end of
2003,  the Company  anticipates  that on January 1, 2000 it will cease  applying
SFAS No. 71 to the  generation  portion of its assets and  operations.  However,
based on the  recovery  mechanism  that allows  recovery of all of its  stranded
costs  through its standard  offer rates,  the Company does not  anticipate  any
write-offs in  connection  with this event.  The Company  expects to continue to
meet the criteria for  application  of SFAS No. 71 for the remaining  portion of
its assets and operations for the foreseeable  future. If a change in accounting
were to occur to the  non-generation  portion of the  Company's  operations,  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.


                                     - 8 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

     The  weighted  average  AFUDC rate applied in the first nine months of 1999
and 1998 was 7.67% and 7.33%, 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 $3,000,000 and $1,900,000 in the first nine
months of 1999 and 1998, respectively,  into the decommissioning trust funds for
Seabrook  Unit 1 and  Millstone  Unit 3. At September  30, 1999,  the  Company's
shares of the trust fund balances,  which included  accumulated  earnings on the
funds,  were $19.4  million and $7.4 million for Seabrook  Unit 1 and  Millstone
Unit 3,  respectively.  These fund balances are included in "Other  Property and
Investments"  and  the  accrued   decommissioning   obligation  is  included  in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.

COMPREHENSIVE INCOME

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

(B)  CAPITALIZATION

     (a) COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding  at September  30, 1999, of which  279,404  shares were  unallocated
shares held by the  Company's  Employee  Stock  Ownership  Plan ("ESOP") and not
recognized as outstanding for accounting purposes.

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

     On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the  awarding of options to purchase up to 650,000  shares of the  Company's
common stock over periods of from one to ten years  following the dates when the
options are granted.  The exercise  price of each option cannot be less than the
market  value of the  stock  on the date of the  grant.  On June 28,  1999,  the
Company's  shareowners  approved the plan. Options to purchase 137,000 shares of
stock at an exercise  price of $43 7/32 per share have been granted by the Board
of Directors  and remained  outstanding  at  September  30, 1999.  No options to
purchase  shares of the  Company's  common  stock can be  exercised  without the
approval  of the DPUC;  and,  as of  September  30,  1999,  the  Company had not
requested approval by the DPUC.



                                     - 9 -
<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 September 30, 1999, 279,404 shares,  with a fair market value of
$13.5  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
$124.1 million were free from such limitations at September 30, 1999.

     (c) PREFERRED STOCK

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

     (e) LONG-TERM DEBT

     On February 1, 1999, the Company  converted $7.5 million  principal  amount
Connecticut  Development Authority Bonds from a weekly reset mode to a five-year
multiannual  mode.  The  interest  rate on the  Bonds for the  five-year  period
beginning  February 1, 1999 is 4.35% and  interest is payable  semi-annually  on
August 1 and February 1. 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 is
payable semi-annually on August 1 and February 1.

     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-RELATED 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.


                                     - 10 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

Commencing no later than  mid-1999,  Distribution  Companies will be required to
separate on consumers' bills the charge for electricity generation services from
the charge for delivering the electricity and all other charges.

     A  major  component  of  the  Restructuring  Act  is  the  collection,   by
Distribution  Companies,  of a "competitive  transition  assessment," a "systems
benefits  charge," a  "conservation  and load  management  program charge" and a
"renewable energy investment charge". The competitive transition assessment will
recover  stranded  costs  that  have  been  reasonably  incurred  by, or will be
incurred by, Distribution  Companies to meet their public service obligations as
electric  companies,  and that will likely not  otherwise  be  recoverable  in a
competitive  generation  and supply  market.  These costs  include  above-market
long-term  purchased power contract  obligations,  regulatory asset recovery and
above-market investments in power plants. The systems benefits charge represents
public policy costs,  such as generation  decommissioning  and displaced  worker
protection  costs.  Beginning in 2000, a  Distribution  Company must collect the
competitive  transition  assessment  and the  systems  benefits  charge from all
Distribution  Company  customers,  except customers taking service under special
contracts   pre-dating  the  Restructuring   Act.  Also  beginning  in  2000,  a
Distribution  Company must collect the conservation and load management  program
charge and the renewable energy charge from all Distribution  Company customers,
without  exception.  The  Distribution  Company will also be required to offer a
"standard  offer"  rate that is,  subject to certain  adjustments,  at least 10%
below its fully bundled  prices for  electricity at rates in effect during 1996,
as  discussed  below.  The  standard  offer  is  required,  subject  to  certain
adjustments,  to be the total rate charged under the standard  offer,  including
the generation  services  component,  transmission and distribution  charge, the
competitive transition assessment, the systems benefits charge, the conservation
and load management program charge and the renewable energy investment charge.

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

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

      The Company received  approximately  $277.9 million in cash from this sale
of its  operating  fossil-fueled  generating  stations.  The Company  realized a
before-tax book gain of $86.5 million, or $15.7 million after-tax, from the sale
of these plant investments. However, under the Restructuring Act, this gain will
be  offset  by  a  writedown  of  above-market  generation  costs  eligible  for
collection by the Company under the Restructuring  Act's competitive  transition
assessment,  such as regulated plant costs and tax-related  regulatory assets or
other costs related to the restructuring transition,  such that there will be no
net income  effect of the sale.  The Company used the net cash proceeds from the
sale to reduce debt.

      On October 1, 1998,  in its  "unbundling  plan" filing with the DPUC under
the  Restructuring  Act, the Company  stated that it plans to divest its nuclear
generation  ownership  interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone  Station Unit No. 3 in  Connecticut)  by the end of 2003, in
accordance with the Restructuring  Act. The divestiture  method has not yet been
determined.  In anticipation of ultimate  divestiture,  the


                                     - 11 -
<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 decision dated
May 19, 1999, the DPUC approved the Company's proposal in this regard.

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

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

      Under the Restructuring  Act, 35% of the Company's  customers will be able
to choose their power supply  providers on and after January 1, 2000, and all of
the Company's  customers will be able to choose their power supply  providers as
of July 1, 2000. On and after January 1, 2000 and through December 31, 2003, the
Company  will be  required  to offer  fully-bundled  "standard  offer"  electric
service,  under regulated rates, to all customers who do not choose an alternate
power supply provider.  The standard offer rates will include the  fully-bundled
price of generation,  transmission  and distribution  services,  the competitive
transition  assessment,  the systems benefits charge and the conservation,  load
management and renewable energy charges. The fully-bundled  standard offer rates
must be at least 10% below the average fully-bundled prices in 1996. The Company
has already  delivered about 4.8% of this decrease,  in bill reductions  through
1998.

     In March of 1999,  the DPUC  commenced a proceeding  to determine  what the
Company's  standard  offer rates should be. In April,  May and June of 1999, the
Company filed descriptive material,  data and supporting testimony with the DPUC
setting forth the Company's  overall  approach for determining the components of
its standard  offer  rates,  and for  continuation  of the  five-year  Rate Plan
ordered by the DPUC in its 1996 financial and operational  review of the Company
(see below) through the four-year  standard offer period.  On July 27, 1999, the
Company and Enron Capital & Trade Resources Corp.  (Enron) filed with the DPUC a
joint stipulation and settlement  proposal to resolve  simultaneously all of the
issues in the Company's standard offer rate proceeding. The proposal includes an
arrangement  between  the  Company  and Enron  with  respect  to the  generation
services  needed by the Company to meet its standard offer  obligations  for the
four-year  standard  offer  period,  and an assumption by Enron of the


                                     - 12 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

Company's  long-term purchased power contract  obligations.  The stipulation and
settlement  proposal also provides for the Company's  standard  offer rates at a
fully-bundled  level  that  complies  with  the 10%  reduction  required  by the
Restructuring Act,  including the generation  services component of these rates,
the Company's  stranded costs for purposes of future  recovery,  the competitive
transition  assessment,  systems benefits  charge,  delivery  (transmission  and
distribution)  charges,  and conservation,  load management and renewable energy
charges.  The Company also requests  that a purchased  power  adjustment  clause
authorized by the  Restructuring  Act be put in place to adjust  standard  offer
rates for limited  purposes,  and that the  Company's  five-year  Rate Plan,  as
modified  and  supplemented  by the  stipulation  and  settlement  proposal,  be
continued  during the  four-year  standard  offer  period.  UI believes that the
global  stipulation  and  settlement  proposal  (i)  effectuates  the  Company's
standard  offer power  procurement  in a manner  that will assure the  Company's
customers  reliable  standard offer  generation  services,  (ii) provides a fair
standard  offer  power  supply  component  that will  enable  retail  generation
suppliers to compete to serve  end-use  customers,  (iii) buys out the Company's
power purchase  agreements on a satisfactory  basis, (iv) resolves a potentially
contentious  adjudication of the Company's  recoverable  stranded costs, and (v)
clears  the way for the  Company  to  focus  on the  energy  delivery  business,
including the new complexities  associated with the onset of retail competition.
In its decision,  dated October 1, 1999, on the Company's  standard offer rates,
the DPUC approved elements of the stipulation and settlement  proposal,  subject
to specified changes.  On October 15, 1999, the Company filed its standard offer
rates  in  compliance  with the  DPUC's  decision,  and the  Company  and  Enron
concurrently filed a revised stipulation and settlement proposal.  These filings
are being reviewed by the DPUC.

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.  The


                                     - 13 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

DPUC's October 1, 1999 decision in the Company's standard offer rates proceeding
implements  an  additional  price  reduction  in 2000  to  achieve  the  minimum
aggregate 10% price reduction compared to 1996 required by the Restructuring Act
and  reduces  the  accelerated  amortizations  scheduled  in the Rate Plan.  The
Company  has  filed its  standard  offer  rates in  compliance  with the  DPUC's
decision; and the rates are being reviewed by the DPUC. The Company is unable to
predict,  at this time, in what other  respects the Rate Plan may be modified in
the future 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 Company  expects that this agreement
will be extended to December 2000.  The borrowing  limit of this facility is $75
million.  The  facility  permits  the Company to borrow  funds at a  fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
September  30,  1999,  the  Company  had $43  million in  short-term  borrowings
outstanding under this facility.

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



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

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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

Income tax provisions:
  Current
              Federal                                                  $17,403        $18,331        $93,197        $37,957
              State                                                      4,519          5,335         24,250         11,044
                                                                   ------------   ------------   ------------   ------------
                 Total current                                          21,922         23,666        117,447         49,001
                                                                   ------------   ------------   ------------   ------------
  Deferred
              Federal                                                    2,802            184        (48,842)        (1,958)
              State                                                        221             87        (14,542)        (1,033)
                                                                   ------------   ------------   ------------   ------------
                 Total deferred                                          3,023            271        (63,384)        (2,991)
                                                                   ------------   ------------   ------------   ------------

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

     Total income tax expense                                          $24,755        $23,747        $53,492        $45,439
                                                                   ============   ============   ============   ============

Income tax components charged as follows:
  Operating expenses                                                   $25,910        $24,448        $57,286        $47,128
  Other income and deductions - net                                     (1,155)          (701)        (3,794)        (1,689)
                                                                   ------------   ------------   ------------   ------------

     Total income tax expense                                          $24,755        $23,747        $53,492        $45,439
                                                                   ============   ============   ============   ============


The following table details the components of the
  deferred income taxes:
     Tax gain on sale of generation assets                             $  -            $ -          $(70,222)       $  -
     Seabrook sale/leaseback transaction                                   686            808         (3,478)        (3,553)
     Pension benefits                                                      579          1,020          2,684          2,003
     Accelerated depreciation                                            1,251          1,535          3,751          4,603
     Tax depreciation on unrecoverable plant investment                  1,186          1,212          3,560          3,636
     Unit overhaul and replacement power costs                            (240)          (361)         1,978            101
     Conservation and load management                                     (410)        (2,922)        (2,155)        (6,935)
     Postretirement benefits                                              (265)           (94)          (963)          (302)
     Displaced worker protection costs                                      43           -             2,258           -
     Other - net                                                           193           (927)          (797)        (2,544)
                                                                   ------------   ------------   ------------   ------------

Deferred income taxes - net                                             $3,023           $271       ($63,384)       ($2,991)
                                                                   ============   ============   ============   ============
</TABLE>

                                     - 15 -
<PAGE>
<TABLE>
<CAPTION>
                            THE UNITED ILLUMINATING COMPANY

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION


                                                        Three Months Ended            Nine Months Ended
                                                          September 30,                 September 30,
                                                        1999          1998            1999          1998
                                                        ----          ----            ----          ----
                                                       (000's)       (000's)         (000's)       (000's)

<S>                                                   <C>           <C>             <C>           <C>
Operating Revenues
------------------
    Retail                                             $191,056      $185,982        $498,985      $481,749
    Wholesale                                             3,669         9,236          22,938        32,497
    Other                                                 4,346         3,383          10,348         6,621
                                                    ------------  ------------   ------------- -------------
         Total Operating Revenues                      $199,071      $198,601        $532,271      $520,867
                                                    ============  ============   ============= =============

Sales by Class(MWH's)
--------------------
    Retail
    Residential                                         604,600       553,475       1,581,672     1,462,288
    Commercial                                          663,457       639,637       1,808,369     1,771,401
    Industrial                                          323,782       312,088         885,041       870,705
    Other                                                11,803        11,874          35,852        35,895
                                                    ------------  ------------   ------------- -------------
                                                      1,603,642     1,517,074       4,310,934     4,140,289
    Wholesale                                            62,040       279,868         920,623     1,043,657
                                                    ------------  ------------   ------------- -------------
         Total Sales by Class                         1,665,682     1,796,942       5,231,557     5,183,946
                                                    ============  ============   ============= =============


Depreciation
------------
    Plant in Service                                    $11,347       $14,330         $37,918       $42,991
    Amortization Conservation and
           Load Management Costs                            (50)        8,272           4,786        19,585
    Nuclear Decommissioning                               1,078           645           3,028         2,109
                                                    ------------  -------------  ------------- -------------
                                                        $12,375       $23,247         $45,732       $64,685
                                                    ============  ============   ============= =============
Other Taxes
-----------
    Charged to:
    Operating:
       State gross earnings                              $7,704        $7,154         $19,456       $18,325
       Local real estate and personal property            4,062         5,316          14,737        16,217
       Payroll taxes                                      1,152         1,338           4,206         4,535
       Other                                                  -             6               -             6
                                                    ------------  ------------   ------------- -------------
                                                         12,918        13,814          38,399        39,083
    Nonoperating and other accounts                         140           105             432           398
                                                    ------------  ------------   ------------- -------------
         Total Other Taxes                              $13,058       $13,919         $38,831       $39,481
                                                    ============  ============   ============= =============

Other Income and (Deductions) - net
-----------------------------------
    Interest income                                        $294        $2,134          $1,423        $2,794
    Equity earnings from Connecticut Yankee                 197           168             521           693
    Earnings (Loss) from subsidiary companies               919           (85)         (2,601)          287
    Miscellaneous other income and (deductions) - net    (1,103)         (419)         (1,885)       (1,092)
                                                    ------------  ------------   ------------- -------------
         Total Other Income and (Deductions) - net         $307        $1,798         ($2,542)       $2,682
                                                    ============  ============   ============= =============

Other Interest Charges
----------------------
    Notes Payable                                          $698          $527          $2,341        $1,842
    Other                                                   709         1,642           1,742         2,603
                                                    ------------  ------------   ------------- -------------
         Total Other Interest Charges                    $1,407        $2,169          $4,083        $4,445
                                                    ============  ============   ============= =============
</TABLE>


                                     - 16 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(K)  FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS

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

(L)  COMMITMENTS AND CONTINGENCIES

CAPITAL EXPENDITURE PROGRAM

     The Company's continuing capital expenditure program is presently estimated
at $262.5  million,  excluding  AFUDC,  for 1999 through 2003.  See the "Capital
Expenditure Program" section for details.

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 two  operating  nuclear
generating  units in which the Company  has an  interest,  the  Company  will be
obligated  to  pay  its  ownership  and/or  leasehold  share  of  any  statutory
assessment  resulting from a nuclear  incident at any nuclear  generating  unit.
Based on its interests in these nuclear  generating units, the Company estimates
its maximum liability would be $17.8 million per incident.
However, any assessment would be limited to $2.1 million per incident per year.

     The NRC requires each nuclear  generating unit to obtain property insurance
coverage  in a minimum  amount of $1.06  billion  and to  establish  a system of
prioritized  use of the insurance  proceeds in the event of a nuclear  incident.
The system  requires that the first $1.06 billion of insurance  proceeds be used
to  stabilize  the  nuclear  reactor to prevent any  significant  risk to public
health and safety and then for  decontamination  and  cleanup  operations.  Only
following completion of these tasks would the balance, if any, of the segregated
insurance  proceeds become available to the unit's owners. For each of the three
nuclear  generating  units in which the Company has an interest,  the Company is
required to pay its ownership  and/or  leasehold share of the cost of purchasing
such  insurance.  Although  each of these units has  purchased  $2.75 billion of
property  insurance  coverage,  representing  the limits of  coverage  currently
available  from  conventional  nuclear  insurance  pools,  the cost of a nuclear
incident could exceed available insurance proceeds.  Under those  circumstances,
the nuclear  insurance  pools that  provide this  coverage may levy  assessments
against the insured owner companies if pool losses exceed the accumulated  funds
available to the pool.  The maximum  potential  assessments  against the Company
with respect to losses occurring  during current policy years are  approximately
$3.1 million.

OTHER COMMITMENTS AND CONTINGENCIES

                               CONNECTICUT YANKEE

     On December  4, 1996,  the Board of  Directors  of the  Connecticut  Yankee
Atomic  Power  Company  (Connecticut  Yankee)  voted  unanimously  to retire the
Connecticut  Yankee nuclear plant (the Connecticut  Yankee Unit) from


                                     - 17 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

     The Company's  estimate of its remaining share of Connecticut Yankee costs,
including  decommissioning,  less  return  of  investment  (approximately  $10.4
million) and return on investment  (approximately $4.2 million) at September 30,
1999, is approximately $27.7 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
September  30,  1999,  the  Company's  guarantee  liability  for  this  debt was
approximately $6.3 million.

                             ENVIRONMENTAL CONCERNS

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



                                     - 18 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

             SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS

     The  Company  has  estimated  that the total  cost of  decontaminating  and
demolishing  its Steel Point  Station  and  completing  requisite  environmental
remediation  of  the  site  will  be  approximately   $11.3  million,  of  which
approximately  $8.3 million had been incurred as of September 30, 1999, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate  decision,  beginning  January 1, 1993,  the
Company  has  been  recovering  through  retail  rates  $1.075  million  of  the
remediation costs per year. The remediation  costs,  property value and recovery
from  customers  will be subject to true-up in the  Company's  next  retail rate
proceeding  based on actual  remediation  costs and actual gain on the Company's
disposition of the property.

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

     As  described  at Note  (C),  "Rate-Related  Regulatory  Proceedings",  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 nine months of 1999 was $2.5 million. UI's share of the fund at
September 30, 1999 was approximately $19.4 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 decommissioning  trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during the first nine months of 1999 was $0.5 million. UI's share of the fund at
September 30, 1999 was approximately $7.4 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 September 30, 1999, $148 million has been expended
for  decommissioning.  The  projected  remaining  decommissioning  cost  is $328
million,  of which UI's share would be $31 million.  The  decommissioning  trust
fund for the  Connecticut  Yankee Unit is also managed by NU. For the  Company's
9.5% equity  ownership  in  Connecticut  Yankee,  decommissioning  costs of $1.8
million  were funded by UI during the first nine months of 1999,  and UI's share
of the fund at September 30, 1999 was $18.7 million.



                                     - 19 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(Q)  RESTATEMENT OF FINANCIAL RESULTS

     Subsequent to filing its Form 10-Q for the quarter ended June 30,1999,  the
Company reviewed, in consultation with its independent accountants and the staff
of the  Securities  and  Exchange  Commission,  the periods in which it recorded
certain  charges  and, as a result,  has  recorded  certain of these  charges in
earlier  periods.

     During 1997 and 1996, APS agent bank accounts were not fully  reconciled at
the time APS balance sheet items were prepared to allow for the  identification,
measurement  and enforcement of material claims for recovery from APS agents for
defalcated  amounts or from APS  customers  for checks  returned by banks due to
insufficient funds. As a result,  losses associated with collection agent errors
and defaults went undetected for extended periods of time. In the second quarter
of 1998,  the Company  performed a review of the  accounting  records at APS and
identified  significantly  past due  agent  collections  of $4.9  million  ($2.8
million,  after-tax) that represented agent deposit shortfalls and uncollectible
agent check deposits.  Pursuant to the result of this review,  APS increased its
provision  against  their  receivable  balance by $4.9  million  ($2.8  million,
after-tax) in the second quarter of 1998. The Company applied similar procedures
during 1996 and,  based on the results,  recorded a $4.5 million ($2.6  million,
after-tax)  increase in its provision in the fourth  quarter of 1996. Due to the
fact that these adjustments related to losses incurred in both current and prior
periods,  the Company has restated the effects of these  adjustments back to the
periods in which the losses occurred as shown below.

     These  restatements  did not result in any change to  retained  earnings as
originally  reported as of June 30, 1999 and December  31, 1998.  As a result of
this  review,  net income and  earnings  per share  originally  reported for the
nine-month  period  ended  September  30, 1998 have been  restated as follows to
reflect  the  restatement  of a  $2.9  million  (after-tax)  charge,  originally
recorded in the second  quarter of 1998,  related to the recording of additional
reserves for  uncollectible  amounts related to American Payment  Systems,  Inc.
(APS) agent collections, to prior periods.

                                                           NINE MONTHS ENDED
                                                           SEPTEMBER 30, 1998
                                                           ------------------
                                                          (thousands, except for
                                                           earnings per share)
Income applicable to common stock, as originally reported        $40,565
Effect on net income of restatement, increase/(decrease)           2,882
                                                                  ------
Income applicable to common stock, as restated                   $43,447
                                                                  ------

Earnings per share, as originally reported
- Basic                                                            $2.90
- Diluted                                                          $2.89


Earnings per share, as restated
- Basic                                                            $3.10
- Diluted                                                          $3.10


     In  addition,  as a result of this  review,  the  Company  has  included in
restricted cash $23.1 million as of December 31, 1998  representing  collections
by 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 $26.8 million as of December 31, 1998
representing  amounts  collected  by APS  agents  on that day which had not been
deposited into APS bank accounts until a later date. A corresponding restatement
of accounts payable



                                     - 20 -
<PAGE>
                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

has been  recorded  to reflect  that these  receivable  amounts  are owed to APS
customers.  The Company had previously  presented its consolidated balance sheet
net of these accounts receivable and accounts payable amounts.



                                     - 21 -
<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.  The  Company  is  experiencing  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  Restructuring  Act 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 the portion of the business  that
continues to meet the criteria for the application of SFAS No. 71. See "Recovery
of Stranded  Costs" below for a discussion  of the nature,  amount and timing of
recovery  of  stranded  costs  associated  with the  generation  portion  of the
Company's  assets and  operations.  The Company  expects to continue to meet the
criteria for application of SFAS No. 71 for the remaining  portion of its assets
and operations for the  foreseeable  future.  If a change in accounting  were to
occur to the non-generation portion of the Company's operations, 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.

                           RECOVERY OF STRANDED COSTS

     Under the  Restructuring  Act, the  business of  generating  and  supplying
electricity  directly  to  customers  will be  separated  from the  business  of
delivering  electricity  to consumers.  The latter  business,  also known as the
transmission  and  distribution   business,   will  remain  with  the  incumbent
franchised utility companies (including the Company),  which will continue to be
regulated by the  Department of Public Utility  Control  (DPUC) as  Distribution
Companies.  One  of  the  major  components  of  the  Restructuring  Act  is the
collection by a Distribution Company of a competitive  transition assessment for
the recovery of "stranded costs" that have been reasonably  incurred by, or will
be incurred by, the Distribution  Company to meet its public service obligations
as a regulated electric company, and that will not otherwise be recoverable in a
competitive generation and supply market. On March 24, 1999, the Company applied
to the DPUC for a determination  of the amount and the timing of the recovery of
the  Company's  stranded  costs as  prescribed  by the  Restructuring  Act. In a
decision dated August 4, 1999, the DPUC determined  that the Company's  stranded
costs  total  $801.3  million,  consisting  of $160.4  million  of  above-market
long-term

                                     - 22 -
<PAGE>

purchase  power  contract  obligations,  $153.3  million  of  generation-related
regulatory assets (net of related tax and accounting offsets), $487.6 million of
above-market  investments in nuclear  generating  units (net of $26.4 million of
gains from  generation  asset  sales and other  offsets  related  to  generation
assets).  The DPUC decision  provides that these stranded cost amounts are fully
recoverable, subject to true-ups on an ongoing basis.

     In March  1999,  the DPUC  commenced a  proceeding  to  determine  what the
Company's  standard offer rates should be beginning January 1, 2000 and, as part
of this proceeding,  the Company  proposed an approach for the recovery,  in its
rates,  of its stranded  costs.  In a decision  dated October 1, 1999,  the DPUC
approved the full recovery of all of the stranded costs  described above through
a  competitive  transition  assessment  charge as a component  of the  Company's
rates. Based on the rates approved in the decision,  it is currently anticipated
that all stranded cost recovery should be completed in approximately 12 years.

     Based on the decisions in the regulatory  proceedings  described above, the
sale of the Company's  fossil-generation  assets in the second  quarter of 1999,
and the planned divestiture of its nuclear generation ownership interests by the
end of 2003,  the  Company  anticipates  that on  January  1, 2000 it will cease
applying  SFAS No. 71 to the  generation  portion of its assets and  operations.
However, based on the favorable DPUC decisions that allow full recovery, through
the Company's  rates, of all historically  incurred  stranded costs, the Company
does not anticipate any write-offs in connection with this event.

                           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>
Nuclear Generation                      $ 4,003      $ 3,113      $ 3,591     $  -         $  -         $ 10,707
Distribution and Transmission            24,268       39,387       20,229      12,279       11,343       107,506
Other                                     4,643         -            -           -            -            4,643
                                         ------       ------       ------      ------       ------       -------
Subtotal                                 32,914       42,500       23,820      12,279       11,343       122,856

Nuclear Fuel                              2,235        8,162        7,086       2,744        7,267        27,494
                                         ------       ------       ------      ------       ------       -------

Total Utility Expenditures               35,149       50,662       30,906      15,023       18,610       150,350

Total Non-Regulated Businesses           99,949        3,200        3,000       3,000        3,000       112,149
                                         ------       ------       ------      ------       ------       -------

  Total                                $135,098      $53,862      $33,906     $18,023      $21,610      $262,499
                                       ========      =======      =======     =======      =======      ========
</TABLE>


Note:  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.


                                     - 23 -
<PAGE>

                         LIQUIDITY AND CAPITAL RESOURCES

     At September 30, 1999,  the Company had $20.3 million of cash and temporary
cash investments, including the Seabrook Unit 1 operating deposit, but excluding
restricted cash of American Payments Systems,  Inc., a decrease of $81.1 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                             53.6

   Net cash provided by (used in) financing activities:
   - Financing activities, excluding dividend payments                 (258.7)
   - Dividend payments                                                  (30.5)
   Net cash  provided by investing activities, excluding investment
     in plant                                                             5.5
   Net cash provided from sale of generation assets                     270.6
   Cash invested in unregulated generation facility                     (95.3)
   Cash invested in plant, including nuclear fuel                       (26.3)
                                                                        -----

       Net Change in Cash                                               (81.1)

       Balance, September 30, 1999                                      $20.3
                                                                         ====


     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)                            $ 97.7      $ -       $ -        $ -        $ -
Internally Generated Funds less Dividends  (2)                    115.6       62.4      70.9       57.5       66.4
Net Proceeds from Sale of Fossil Generation Plants                200.4        -         -          -          -
                                                                  -----      -----     -----      -----      -----
         Subtotal                                                 413.7       62.4      70.9       57.5       66.4

Less:
Utility Capital Expenditures  (2)                                  35.1       50.7      30.9       15.0       18.6
Investments in subsidiaries  (3)                                   99.9        3.2       3.0        3.0        3.0
                                                                  -----      -----      ----      -----      -----

Cash Available to pay Debt Maturities and Redemptions             278.7        8.5      37.0       39.5       44.8

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

External Financing Requirements (Surplus)  (2)                    $(4.1)     $41.9    $(36.7)     $60.8      $55.7
                                                                   ====       ====     ======      ====       ====
</TABLE>

(1)  Excludes $3.7 million Seabrook Unit 1 operating deposit and restricted cash
     of American Payment Systems, Inc. of $23.1 million.
(2)  Internally  Generated  Funds  less  Dividends,   Capital  Expenditures  and
     External Financing Requirements are estimates based on current earnings and
     cash flow  projections,  including the  implementation  of the  legislative
     mandate to  achieve a 10% price  reduction  from  December  31,  1996 price
     levels by the year 2000. Connecticut's Restructuring Act, described at Note
     (C), "Rate-Related Regulatory Proceedings",  required the Company to


                                     - 24 -
<PAGE>

     divest  itself of its  fossil-fueled  generating  plants and requires it to
     attempt  to divest  itself of its  ownership  interests  in  nuclear-fueled
     generating  units prior to January 1, 2004. This forecast  reflects the net
     after-tax proceeds from the divestiture of fossil-fueled  generation plants
     on April 16,  1999.  All of these  estimates  are  subject to change due to
     future events and conditions that may be substantially different from those
     used in developing the projections.
(3)  Investment  for 1999 in  United  Bridgeport  Energy  $87.0  million,  Allan
     Electric Co., Inc. $8.3  million,  Precision  Power,  Inc. $1.5 million and
     United Resources, Inc. $3.1 million.

     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 Company  expects that this agreement
will be extended to December 2000.  The borrowing  limit of this facility is $75
million.  The  facility  permits  the Company to borrow  funds at a  fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed  interest rates  determined by either the Eurodollar  interbank
market in London, or by bidding,  at the Company's option. If a material adverse
change in the business,  operations,  affairs, assets or condition, financial or
otherwise,  or prospects of the Company and its subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to the
Company under this revolving credit agreement,  although borrowings  outstanding
at the time of such an occurrence  would not then become due and payable.  As of
September  30,  1999,  the  Company  had $43  million in  short-term  borrowings
outstanding under this facility.

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

                              SUBSIDIARY OPERATIONS

     UI has one wholly-owned  subsidiary,  United  Resources,  Inc. (URI),  that
serves as the parent  corporation for several  unregulated  businesses,  each of
which is incorporated  separately to participate in business  ventures that will
complement  UI's  regulated  electric  utility  business  and provide  long-term
rewards to UI's shareowners.

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

                              RESULTS OF OPERATIONS

THIRD QUARTER OF 1999 VS. THIRD QUARTER OF 1998

     Earnings  for the third  quarter of 1999 were $25.0  million,  or $1.78 per
share (on both a basic and diluted basis), down $1.2 million, or $.09 per share,
from the third  quarter of 1998.  Excluding  the one-time  item  recorded in the


                                     - 25 -
<PAGE>

third quarter of 1998, earnings from operations were virtually unchanged.  There
were no one-time items recorded in the third quarter of 1999.

     The one-time item recorded in the third quarter of 1998 was:

                            One-time Item                     $millions     EPS
--------------------------------------------------------------------------------
1998 Quarter 3   Refund of prior period transmission charges,
                 with interest                                            $ .14
                 "Sharing" due to one-time item recorded
                 in the third quarter                                     $(.05)
                       "Sharing" revenues (before-tax)          $(0.6)
                       "Sharing" amortization (before-tax)        0.6
--------------------------------------------------------------------------------

Utility Earnings from Operations
--------------------------------

     Retail  revenues  from  operations  increased  by $5.1 million in the third
quarter of 1999  compared to the third  quarter of 1998,  as  electric  revenues
increased  for the  reasons  detailed  below.  Retail  fuel and  energy  expense
increased by $13.0 million,  primarily from higher  purchased  power prices as a
result  of the  Company's  transition  from a  producer  to a  purchaser  of its
customers'  energy  requirements.  Overall,  retail sales margin from operations
decreased by $9.0  million.  The  principal  components  of the change in retail
sales margin for the quarter, year-over-year, include:

                                                                     $ millions
------------------------------------------------------------------- ------------
 Revenue from:
------------------------------------------------------------------- ------------
   Sharing: year-to-date for 1999 (see note A)                          (6.3)
------------------------------------------------------------------- ------------
   Estimate of "real" retail sales growth, up 4.6%                       8.7
------------------------------------------------------------------- ------------
   Estimate of weather effect on retail sales, up 1.3%                   2.4
------------------------------------------------------------------- ------------
   Sales decrease from Yale University cogeneration, (0.2)%             (0.3)
------------------------------------------------------------------- ------------
 Revenue based taxes                                                    (0.5)
------------------------------------------------------------------- ------------
 Fuel and energy, margin effect:
------------------------------------------------------------------- ------------
    Sales increase                                                      (1.9)
------------------------------------------------------------------- ------------
    Nuclear fuel prices and outage replacement power costs               1.3
------------------------------------------------------------------- ------------
    Purchased energy prices (see note B)                               (12.4)
------------------------------------------------------------------- ------------

     A.   The Company's return on regulated  utility common stock equity for the
          first nine  months of 1999  exceeded  the 11.5%  "sharing"  trigger by
          about $25  million  of pre-tax  income.  As a result,  a book  revenue
          "sharing"  reduction of $8.7 million,  including a gross  earnings tax
          component,  was recorded in the third  quarter of 1999,  approximately
          $6.3  million  more  than  the $2.4  million  book  revenue  "sharing"
          reduction recorded from operations in the third quarter of 1998.

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



                                     - 26 -
<PAGE>

     Net wholesale margin (wholesale  revenue less wholesale  expense) decreased
by $4.3 million in the third  quarter of 1999  compared to the third  quarter of
1998 from lower wholesale sales resulting from the generation  asset sale. Other
operating  revenues,   which  include  NEPOOL  related  transmission   revenues,
increased by $1.0 million. NEPOOL transmission revenues are recoveries,  for the
most part,  of NEPOOL  transmission  expense and simply  reflect new  accounting
requirements implemented by the Federal Energy Regulatory Commission.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $6.2 million in the third  quarter of 1999 compared to the
third  quarter  of 1998.  The  principal  components  of these  expense  changes
include:
                                                                      $ millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Connecticut Yankee                                                    (0.2)
--------------------------------------------------------------------- ----------
   Cogeneration and other purchases                                      (0.5)
--------------------------------------------------------------------- ----------
 Other O&M expense:
--------------------------------------------------------------------- ----------
   Seabrook Unit 1                                                        0.5
--------------------------------------------------------------------- ----------
   Millstone Unit 3                                                       0.6
--------------------------------------------------------------------- ----------
   Fossil generation unit overhaul and outage costs                     (10.2)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                            1.1
--------------------------------------------------------------------- ----------
   Other miscellaneous, including impact of generation asset sale         1.2
--------------------------------------------------------------------- ----------

     Depreciation expense decreased by $5.0 million in the third quarter of 1999
compared to the third  quarter of 1998,  due primarily to the  generation  asset
sale. Property tax expense decreased by $1.3 million due to this sale.

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

     The Company also incurred additional  accelerated  amortization  expense of
$5.0 million (after-tax,  about $8.4 million in pre-tax equivalent) in the third
quarter of 1999 as a result of the "sharing"  mechanism in the Rate Plan, as the
Company  achieved a return on utility  common  stock  equity  above 11.5% midway
through the quarter.  "Sharing"  amortization  recorded  against  earnings  from
operations  in the third  quarter  of 1998 was $2.1  million  (before-tax,  $1.3
million  after-tax).  See the  "Looking  Forward"  section  for a more  detailed
explanation of the "sharing" mechanism.

     Interest  charges  continued on their  downward  trend,  decreasing by $4.0
million for the regulated  business in the third quarter of 1999 compared to the
third quarter of 1998,  partly offset by an increase of $1.4 million in interest
charges for unregulated subsidiaries.  Most of the reduction in utility interest
charges  anticipated  for  1999  compared  to  1998  began  accruing  after  the
generation asset sale, which was completed on April 16, 1999. On April 16, 1999,
the Company  used  proceeds  received  from the sale to pay off $205  million of
debt. See the "Looking Forward" section for more details.

Unregulated Business Earnings from Operations
---------------------------------------------

     Overall,  unregulated business income, after parent-allocated  interest but
before  income  taxes,  was a loss of about $0.4 million in the third quarter of
1999, compared to a loss of less than $0.3 million in the third quarter of 1998.
American Payment Systems,  Inc. (APS) earned about $0.8 million  (before-tax) in
the third  quarter of 1999,


                                     - 27 -
<PAGE>

more  than  double  the $0.39  million  earned  in the  third  quarter  of 1998.
Precision  Power,  Inc. (PPI) lost about $1.3 million  (before-tax) in the third
quarter of 1999,  compared to a loss of about $0.3 million in the third  quarter
of 1998,  reflecting  increased  infrastructure costs and lower than anticipated
contract margins.

     On May 11, 1999, the Company's  unregulated  subsidiary,  United Resources,
Inc.,  increased its 4% passive  investment,  through United Bridgeport  Energy,
Inc.,  in  Bridgeport  Energy  LLC (BE) to 33  1/3%.  The  second  phase of BE's
merchant wholesale electric generating project went into commercial operation in
July 1999,  adding  180  megawatts  of  generation  capacity  for a total of 520
megawatts.  UBE earned about $0.7 million  (before-tax)  in the third quarter of
1999. Other unregulated subsidiary projects lost about $0.6 million in the third
quarter of 1999,  compared to a loss of about $0.3 million in the third  quarter
of 1998.

Note:  Unregulated business before-tax income is reported as part of "Other net"
income;  parent interest  charges  allocated to the  unregulated  businesses are
reported  as part of  "Interest  charges";  and  related  income tax  expense is
reported as part of "Non-operating income taxes".

<TABLE>
<CAPTION>
                                                                        3rd Q      3rd Q 99    3rd Q 99
                                                                        ended          vs.        vs.
                                                                       Sept. 99    3rd Q 98    2nd Q 99
Summary of Unregulated Subsidiaries Pre-tax Income:                   $millions   $millions   $millions
--------------------------------------------------------------------- ------------ ---------- ----------
<S>                                                                       <C>          <C>       <C>
  American Payment Systems, Inc.                                          0.8          0.4       0.5
--------------------------------------------------------------------- ------------ ---------- ----------
  Precision Power, Inc.                                                  (1.3)        (1.0)      0.7
--------------------------------------------------------------------- ------------ ---------- ----------
  United Bridgeport Energy                                                0.7          0.7       1.7
-------------------------------------------------------------------- ------------ ---------- ----------
  United Resources, Inc. Capital Projects                                (0.6)        (0.3)     (0.5)
--------------------------------------------------------------------- ------------ ---------- ----------
</TABLE>

FIRST NINE MONTHS OF 1999 VS. FIRST NINE MONTHS OF 1998

     Earnings for the first nine months of 1999 were $48.8 million, or $3.47 per
share (on both a basic and diluted basis),  up $5.3 million,  or $.36 per share,
from the first nine months of 1998 (basic).  Excluding one-time items,  earnings
from operations were $48.2 million, or $3.43 per share, up $6.0 million, or $.41
per share.

     The one-time items reported in the first nine months of 1998 and 1999 were:

                              One-time Item                  $millions      EPS
--------------------------------------------------------------------------------
1998 Quarter 3   Refund of prior period transmission charges,
                 with interest                                            $ .14
                 "Sharing" due to one-time item recorded
                  in the third quarter                                    $(.05)
                      "Sharing" revenues (before-tax)          $(0.6)
                      "Sharing" amortization (before-tax)        0.6
--------------------------------------------------------------------------------

Utility Earnings from Operations
--------------------------------

     Retail  revenues  from  operations  increased by $17.6 million in the first
nine  months of 1999  compared  to the first nine  months of 1998,  as  electric
revenues increased for the reasons detailed below.  Retail revenues decreased by
$0.3  million  because  of  "sharing"  required  under  the  current  regulatory
structure as applied to the one-time items recorded in both periods. Retail fuel
and energy expense from  operations  increased by $13.8 million,  primarily from
higher  purchased  power prices as a result of the Company's  transition  from a
producer to a purchaser of its customers' energy  requirements,  and the need to
purchase  additional  energy to replace power lost from nuclear plant  refueling
outages. Overall, retail sales margin from operations increased by $2.6 million,
or 0.5%. The principal components of the retail sales margin change for the nine
months ended September 30, 1999, compared to the nine months ended September 30,
1998, include:



                                     - 28 -
<PAGE>

                                                                      $millions
-------------------------------------------------------------------- -----------
 Revenue from:
-------------------------------------------------------------------- -----------
   Sharing: year-to-date for 1999 (see Note A)                           (6.3)
-------------------------------------------------------------------- -----------
   Estimate of "real" retail sales growth, up 3.5%                       17.5
-------------------------------------------------------------------- -----------
   Estimate of weather effect on retail sales, up 1.4%                    7.0
-------------------------------------------------------------------- -----------
   Sales decrease from Yale University cogeneration, (0.9)%              (4.1)
-------------------------------------------------------------------- -----------
   Price mix of sales and other                                           3.4
-------------------------------------------------------------------- -----------
   "Sharing" due to one-time items                                       (0.3)
-------------------------------------------------------------------- -----------
 Revenue based taxes                                                     (1.1)
-------------------------------------------------------------------- -----------
 Fuel and energy, margin effect:
-------------------------------------------------------------------- -----------
   Sales increase                                                        (3.7)
-------------------------------------------------------------------- -----------
   Nuclear fuel prices and outage replacement power costs                (2.7)
-------------------------------------------------------------------- -----------
   Purchased energy prices (see Note B)                                  (7.4)
-------------------------------------------------------------------- -----------

     A.   The Company's return on regulated  utility common stock equity for the
          first nine  months of 1999  exceeded  the 11.5%  "sharing"  trigger by
          about $25  million  of pre-tax  income.  As a result,  a book  revenue
          "sharing"  reduction of $8.7 million,  including a gross  earnings tax
          component,  was recorded in the third  quarter of 1999,  approximately
          $6.3  million  more  than  the $2.4  million  book  revenue  "sharing"
          reduction recorded from operations in the third quarter of 1998.


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

     Net wholesale margin (wholesale  revenue less wholesale  expense) decreased
by $8.6  million in the first  nine  months of 1999  compared  to the first nine
months of 1998 from lower  wholesale  sales.  Other  operating  revenues,  which
include NEPOOL related transmission revenues,  increased by $3.7 million. NEPOOL
transmission revenues are recoveries,  for the most part, of NEPOOL transmission
expense  and simply  reflect  new  accounting  requirements  implemented  by the
Federal Energy Regulatory Commission.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
charges  decreased by $7.0 million in the first nine months of 1999  compared to
the first  nine of 1998.  The  principal  components  of these  expense  changes
include:


                                     - 29 -
<PAGE>

                                                                      $millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Connecticut Yankee                                                    (1.1)
--------------------------------------------------------------------- ----------
   Cogeneration and other purchases (see Note)                            2.9
--------------------------------------------------------------------- ----------
 Other O&M expense:
--------------------------------------------------------------------- ----------
   Seabrook Unit 1 (refueling outage costs and accruals)                  4.6
--------------------------------------------------------------------- ----------
   Millstone Unit 3 (refueling outage costs and accruals)                 1.2
--------------------------------------------------------------------- ----------
   Other expenses at nuclear units                                       (1.0)
--------------------------------------------------------------------- ----------
   Fossil generation unit operating and maintenance costs               (18.3)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                            2.6
--------------------------------------------------------------------- ----------
  Other miscellaneous, including impact of generation asset sale          2.1
--------------------------------------------------------------------- ----------

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


     Depreciation  expense decreased by $6.5 million in the first nine months of
1999 compared to the first nine months of 1998,  due primarily to the generation
asset sale.

     On December 31, 1996, the Connecticut  Department of Public Utility Control
issued an order that  implemented a five-year  Rate Plan to reduce the Company's
retail  prices and  accelerate  the  recovery  of certain  "regulatory  assets."
According  to the Rate Plan,  under  which the Company is  currently  operating,
"accelerated"  amortization  of past utility  investments is scheduled for every
year that the Rate Plan is in  effect,  contingent  upon the  Company  earning a
10.5% return on utility  common stock equity.  All of the scheduled  accelerated
amortization  for 1998,  amounting to $13.1  million  (before-tax,  $8.5 million
after-tax), was recorded against earnings from operations in 1998. Three-fourths
of the total, or $9.9 million (before-tax, $6.3 million after-tax), was recorded
in the first nine months of 1998.  The Company is amortizing  regulatory  income
tax assets for the 1999 amount,  totaling $12.1 million (after-tax,  $20 million
pre-tax  equivalent),  three-fourths  of it, or $9.1 million  (after-tax,  $15.2
million pre-tax equivalent), in the first nine months of 1999.

     The Company can also incur additional accelerated amortization expense as a
result of the "sharing"  mechanism in the Rate Plan,  if the Company  achieves a
return on utility common stock equity above 11.5%, which the Company did achieve
midway  through  the third  quarter of 1999.  Such  "sharing"  amortization  was
recorded in the first quarter of 1999, in the amount of $0.6 million (after-tax,
$1.0 million in pre-tax  equivalent),  as a result of the one-time gain recorded
in  that  quarter.  "Sharing"  amortization  from  operations  of  $5.0  million
(after-tax,  $8.4  million  of pre-tax  equivalent)  was  recorded  in the third
quarter of 1999.  "Sharing"  amortizations  recorded in the first nine months of
1998 were: $0.5 million  (before-tax,  $0.3 million  after-tax) as a result of a
one-time  item,  and $2.1  million  (before-tax,  $1.2 million  after-tax)  from
operations.

     Interest  charges  continued on their  downward  trend,  decreasing by $8.0
million for the regulated  business in the first nine months of 1999 compared to
the first nine months of 1998,  partly  offset by an increase of $2.0 million in
interest charges for unregulated subsidiaries.  Most of the reduction in utility
interest charges  anticipated for 1999 compared to 1998 began accruing after the
generation asset sale, which was completed on April 16, 1999. On April 16, 1999,
the  Company  used  proceeds  received  from  the  sale of plant to pay off $205
million of debt. See the "Looking Forward" section for more details.

Unregulated Business Earnings from Operations
---------------------------------------------

     Overall,  unregulated business income, after parent-allocated  interest but
before income  taxes,  was a loss of about $4.3 million in the first nine months
of 1999  compared  to income of about $0.3  million in the first nine  months of
1998.   American  Payment   Systems,   Inc.  (APS)  earned  about  $1.4  million
(before-tax)  in the first nine months of 1999,  reflecting  an increase of $0.5
million over the first nine months of 1998.  Precision  Power,  Inc.  (PPI) lost
about $4.0 million  (before-tax) in the first nine months of 1999, compared to a
loss of about  $0.4  million


                                     - 30 -
<PAGE>

in the first nine months of 1998, reflecting increased  infrastructure costs and
lower than anticipated contract margins.

     On May 11, 1999, the Company's  unregulated  subsidiary,  United Resources,
Inc.,  increased its 4% passive  investment,  through United Bridgeport  Energy,
Inc.,  in  Bridgeport  Energy  LLC (BE) to 33  1/3%.  The  second  phase of BE's
merchant wholesale electric generating project went into commercial operation in
July 1999,  adding  180  megawatts  of  generation  capacity  for a total of 520
megawatts.  UBE lost about $0.4 million (before-tax) in the first nine months of
1999, as a result of the second quarter shutdown of the first phase generator to
allow  for  construction  of the  second  phase.  Other  unregulated  subsidiary
projects  lost about $1.3  million in the third  quarter of 1999,  reflecting  a
decrease of about $1.1 million compared to the third quarter of 1998.

Note:  Unregulated business before-tax income is reported as part of "Other net"
income;  parent  interest  charges  allocated  to them are  reported  as part of
"Interest  charges";  and  related  income tax  expense is  reported  as part of
"Non-operating income taxes".

                                                           9 mos.
                                                           ended      1st 9 mos.
                                                          Sept. 99    99 vs. 98
Summary of Unregulated Subsidiaries Pre-tax Income:       $millions   $millions
--------------------------------------------------------- ---------- -----------
  American Payment Systems, Inc.                             1.4         0.5
--------------------------------------------------------- ---------- -----------
  Precision Power, Inc.                                     (4.0)       (3.6)
--------------------------------------------------------- ---------- -----------
  United Bridgeport Energy, Inc.                            (0.4)       (0.4)
--------------------------------------------------------- ---------- -----------
  United Resources, Inc. Capital Projects                   (1.3)       (1.1)
--------------------------------------------------------- ---------- -----------

     Subsequent  to the original  filing of its Form 10-Q for the quarter  ended
June 30, 1999, the Company reviewed the periods in which it had recorded certain
loss provisions for shortfalls in APS agent  collections  and other  potentially
uncollectible  receivables  which had  originally  been  recorded  in the second
quarter of 1998 in the amount of $4.9 million.  As a result of this review,  the
Company  has  restated  $2.8  million  of the loss  provisions  to 1997 and $2.1
million to 1996.

     During 1997 and 1996, APS agent bank accounts were not fully  reconciled at
the time APS balance sheet items were prepared to allow for the  identification,
measurement  and enforcement of material claims for recovery from APS agents for
defalcated  amounts or from APS  customers  for checks  returned by banks due to
insufficient funds. As a result,  losses associated with collection agent errors
and defaults went undetected for extended periods of time. In the second quarter
of 1998,  the Company  performed a review of the  accounting  records at APS and
identified  significantly  past due  agent  collections  of $4.9  million  ($2.8
million,  after-tax) that represented agent deposit shortfalls and uncollectible
agent check deposits.  Pursuant to the result of this review,  APS increased its
provision  against  their  receivable  balance by $4.9  million  ($2.8  million,
after-tax) in the second quarter of 1998. The Company applied similar procedures
during 1996 and,  based on the results,  recorded a $4.5 million ($2.6  million,
after-tax)  increase in its provision in the fourth  quarter of 1996. Due to the
fact that these adjustments related to losses incurred in both current and prior
periods,  the Company has restated the effects of these  adjustments back to the
periods in which the losses occurred as shown below.

     The following  table  summarizes the effect of the  restatements  described
above to the provision for APS losses:
<TABLE>
<CAPTION>
                                                                  9 MOS.
                                                                 TO DATE
                                                                  1998       1997     1996
                                                                  ----       ----     ----
                                                                        (In Thousands)
<S>                                                              <C>        <C>      <C>
Provision for APS losses (before-tax), as originally reported    $4,900     $   -    $   -
     Effect of restatement, described above                      (4,900)     2,825    2,075
                                                                  -----      -----    -----
Provision for APS losses (before-tax), as restated               $  -       $2,825   $2,075
                                                                  =====      =====    =====
</TABLE>




                                     - 31 -
<PAGE>

                                 LOOKING FORWARD

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

Five-year Rate Plan
-------------------

     On December 31, 1996, the Connecticut  Department of Public Utility Control
(DPUC)  issued an order (the Order)  that  implemented  a  five-year  regulatory
framework to reduce the Company's  retail prices and  accelerate the recovery of
certain  "regulatory  assets," beginning with deferred  conservation  costs. The
Company  operated under the terms of this Order in 1998. The Order's schedule of
price  reductions and  accelerated  amortizations  was based on a DPUC pro-forma
financial  analysis that anticipated the Company would be able to implement such
changes and earn an allowed  annual  return on common stock  equity  invested in
utility assets of 11.5% over the period 1997 through 2001. The Order established
a set formula to share (see "Sharing  Implementation"  below) any utility income
that would  produce a return above the 11.5%  level:  one-third to be applied to
customer price reductions, one-third to be applied to additional amortization of
regulatory assets,  and one-third to be retained by shareowners.  Utility income
is inclusive of earnings from operations and one-time  items.  The Order remains
in effect  through  2001,  although it does  include a provision  that it may be
modified as a result of the restructuring  legislation passed by the Connecticut
legislature in 1998. Please see Note (C), "Rate-Related Regulatory Proceedings -
Five-year  Rate Plan" for a more  extensive  description  of the five-year  Rate
Plan.

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

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

An early look at 2000; continued growth of non-regulated business value
-----------------------------------------------------------------------

     On January 1, 2000,  the Company will  complete the  restructuring  process
initiated by the Connecticut electric utility industry restructuring legislation
in 1998. The Company's  regulated  business will become an electricity  delivery
                                                                        --------
business.  Many  changes  will occur in the  revenue and cost  structure  of the
regulated business,  although the framework of the current Rate Plan,  including
the  "sharing"   mechanism,   will  continue   through  2001.   The   regulatory
restructuring  decisions have not altered the Company's  allowed return of 11.5%
on  utility  equity,  and they have been  crafted  in a manner  that  should not
impinge on the Company's ability to achieve that return.

     If the Company were to earn 11.5% on equity in the regulated business, that
level of earning should  generate  $3.25 - $3.35 per share in earnings.  Sharing
will be greatly reduced from 1999 levels,  due to mandates in the  restructuring
legislation; and the Company expects it will contribute no more than $.05 - $.10
per share.

     Unregulated  businesses are expected to make  significant  contributions to
earnings  in 2000.  As a result  of  management's  continued  confidence  in the
potential  of the  unregulated  businesses,  the Company is  evaluating  further
investments in this area.  American Payment Systems and United Bridgeport Energy
should each  contribute  $.10 - $.15 per share in 2000,  while  Precision  Power
should break even. The other  unregulated  businesses  should,


                                     - 32 -
<PAGE>

in the  aggregate,  lose up to $.05 per  share,  although  investments  in other
growth  initiatives  could increase  losses in the near term in  anticipation of
higher future earnings. Total earnings for 2000, contingent upon normal weather,
current  interest rates,  and current expense levels,  would now be estimated to
fall in the range of $3.45 to $3.75.

Year 2000
---------

     The Company's  planning and  operations  functions,  and its cash flow, are
dependent  on the  timely  flow of  electronic  data to and from its  customers,
suppliers and other electric utility system managers and operators.  In order to
assure that this data flow will not be disturbed by the problems  emanating from
the fact that many existing computer programs were designed without  considering
the impact of the year 2000 and use only two digits to identify  the year in the
date field of the  programs  (the Year 2000  Issue),  the Company  initiated  in
mid-1997,  and is  pursuing,  an  aggressive  program to  identify  and  correct
deficiencies in its computer systems.  This  comprehensive  program includes all
information   technology  systems  and  encompasses   systems  critical  to  the
generation,  transmission  and  distribution  of  electric  energy  as  well  as
traditional  business  systems.  Critical  systems  have been  defined  as those
business processes,  including embedded technology,  which if not remediated may
have  a  significant  impact  on  safety,   customers,   revenue  or  regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged and has been 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 393 affected  business  processes  have been  identified and all of them have
been verified as Year 2000 compliant through testing,  remediation,  replacement
or retirement.  The remediation  methodology  utilized has been Fixed Windowing,
and totally  independent  platforms  have been  installed for testing all of the
applications.  Necessary  upgrades  to  mainframe  hardware  and  software  were
completed and tested by June 30, 1999. This included a  "destructive"  mainframe
test performed at an independent site in Ponca City, Oklahoma.

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

     By June 30 1999, the Company's Year 2000 program for all critical  business
processes,  with the  exception  of two systems in the  Controller's  department
(Materials  Management and General Ledger), was complete.  Those exceptions were
awaiting  compliant  vendor  releases  prior to testing.  As of October 30, 1999
those two systems,  as well as all of UI's remaining  business  processes,  were
determined  to be Year 2000 ready.  This  reflects the  completion  of Year 2000
readiness  acceptance of all  identified and  prioritized  processes by testing,
remediation, retirement or replacement.

     Priority one processes are those defined as affecting safety,  reliability,
regulatory compliance or having a significant financial impact. The priority one
Customer  Services process relates to the Customer  Information  System that has
been 100% tested, but it is under continuous change due to the electric industry
restructuring in Connecticut.  The Year 2000 readiness  acceptance was completed
for all priority  one systems as of October 30, 1999.  Priority two implies that
failure of this  software or hardware  will present a  disruption  of service at
current budget levels, but work-arounds are available, if needed. Priority three
implies that failure of this  software or hardware may present an  inconvenience
to  occasional  work  requirements  or an impediment  to  achievement  of higher
service or lower cost levels,  but  alternative  work-arounds  can be pursued if
deemed necessary at some future date. Priority four implies that failure of this
software or hardware  may produce a nuisance or  confusion  but will not present
any direct negative business consequence.  As of August 3, 1999, the Company had
completed  the  assessment  and  remediation  phases  of its  program  for these
non-priority one business processes,  and the Year 2000 readiness acceptance for
the process has now been completed.  A stabilization  period was put into effect
on October  15, 1999 to minimize  any risk of  contamination  of the current Y2K
ready environment.



                                     - 33 -
<PAGE>

     UI  has  successfully  complied  with  all  regulatory  requirements.  Most
recently, UI successfully  completed a Connecticut  Department of Public Utility
Control  audit  along with eight  other  utilities  in the  state.  The  Company
provides  monthly  updates to the DPUC on all Y2K  progress.  The  Company  also
provided  monthly  reports to the North American  Electric  Reliability  Council
(NERC) on the Year 2000  compliance  status of its  transmission,  distribution,
telecommunication and system control and data acquisition assets.

     Requests  for  documented  compliance  information  have  been  sent to all
critical suppliers,  data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed.  While failure to achieve Year 2000  compliance by any one of a number
of critical  suppliers  and data sharers  could have some adverse  effect on the
success of the Company's  implementation  program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications  providers,  the other  participants in the New England Power
Pool  (NEPOOL),  and the  Independent  System  Operator  (ISO) that operates the
NEPOOL bulk power supply system.  Year 2000 compliance  failures by any of these
entities could have a material effect on electricity  delivery and telemetering.
In its efforts to mitigate these risks,  the Company has taken several  actions.
UI has  communicated its concerns to its principal  telecommunications  provider
and a joint  effort to design and plan  appropriate  testing to insure  that all
critical  telecommunications  functions will be operational is ongoing. 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
also in progress and on  schedule.  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 NERC.
Several tests at the ISO and NERC levels were completed  successfully,  the most
recent being a nationwide NERC test on September 8 and 9, 1999.

     Aside from  telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant   risk  to  the  success  of  the  Company's  Year  2000  compliance
implementation  program.  In order to minimize these risks, the Company has been
and will be  actively  involved in  contingency  planning.  While the  Company's
knowledge and experience in electric system recovery  planning and execution has
been  demonstrated  in the  past,  the  Company  recognizes  the need  for,  and
importance  of, Year  2000-specific  contingency  planning,  because the complex
interaction of today's computing and communications  systems precludes certainty
that all critical system remediation will be successful.  High level contingency
planning for essential business  processes has been completed.  These plans will
be continually  reviewed,  revised and modified  throughout the remainder of the
year  as  appropriate.   As  a  part  of  the  contingency   planning   process,
consideration will be given to potential frequency and duration of interruptions
in  the  generating,   financial  and  communications   infrastructures.   Since
contingency  planning  is, by nature,  a  speculative  process,  there can be no
assurance  that this  planning  will  completely  eliminate the risk of material
impacts  to the  Company's  business  due to Year 2000  problems.  However,  the
Company  recognizes  the  importance  to its  customers of a reliable  supply of
electricity, and it intends to devote whatever resources are necessary to assure
that both the program and its implementation are successful.

     The Company  believes that the  successful  implementation  of this program
should  ultimately  cost  approximately  $6.1 million for  existing  information
systems and embedded technology. A total of $5.6 million had been expended as of
September 30, 1999. As systems testing  progresses and more embedded  technology
vendor product  information is forthcoming,  business decisions made and testing
results verified,  the need for increased  expenditures,  if necessary,  will be
determined.  The Company believes these actions will preclude any adverse impact
of the Year 2000 Issue on its operations or financial condition.



                                     - 34 -
<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



                                     - 35 -