SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549


                                    FORM 10-Q

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

                 FOR THE QUARTERLY PERIOD ENDING MARCH 31, 2000

                                       OR

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

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


Commission file number 1-6788

                         THE UNITED ILLUMINATING COMPANY

             (Exact name of registrant as specified in its charter)

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

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

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


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


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

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

     The  number of shares  outstanding  of the  issuer's  only  class of common
stock, as of March 31, 2000, was 14,334,922.


                                     - 1 -
<PAGE>



                                      INDEX

                          PART I. FINANCIAL INFORMATION

                                                                        PAGE
                                                                       NUMBER
                                                                       ------

Item 1.  Financial Statements.                                            3

         Consolidated Statement of Income for the three months
          ended March 31, 2000 and 1999.                                  3
         Consolidated Balance Sheet as of March 31, 2000 and
           December 31, 1999.                                             4
         Consolidated Statement of Cash Flows for the three months
           ended March 31, 2000 and 1999.                                 6

         Notes to Consolidated Financial Statements.                      7
           -   Statement of Accounting Policies                           7
           -   Capitalization                                             7
           -   Short-term Credit Arrangements                             8
           -   Income Taxes                                               9
           -   Supplementary Information                                 10
           -   Commitments and Contingencies                             11
               -  Capital Expenditure Program                            11
               -  Nuclear Insurance Contingencies                        11
               -  Other Commitments and Contingencies                    11
                  - Connecticut Yankee                                   11
                  - Hydro-Quebec                                         12
                  - Environmental Concerns                               12
                  - Site Decontamination, Demolition and Remediation
                     Costs                                               12
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning   13
           -   Segment Information                                       14

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations.                                      15

           -   Major Influences on Financial Condition                   15
           -   Capital Expenditure Program                               18
           -   Liquidity and Capital Resources                           18
           -   Subsidiary Operations                                     19
           -   Results of Operations                                     20
           -   Looking Forward                                           24

Item 3.  Quantitative and Qualitative Disclosure About Market Risk.      26

                           PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.                                              27

Item 4.  Submission of Matters to a Vote of Security Holders.            27

Item 6.  Exhibits and Reports on Form 8-K.                               27

         SIGNATURES                                                      28



                                     - 2 -
<PAGE>
<TABLE>
                          PART I: FINANCIAL INFORMATION
                          ITEM I: FINANCIAL STATEMENTS
                         THE UNITED ILLUMINATING COMPANY
                        CONSOLIDATED STATEMENT OF INCOME
                       (Thousands except per share amounts)
                                   (Unaudited)

<CAPTION>
                                                                      Three Months Ended
                                                                          March 31,
                                                                    2000                1999
                                                                    ----                ----

<S>                                                                <C>                 <C>
OPERATING REVENUES (NOTE G)                                        $180,977            $168,667
                                                               -------------       -------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                 67,469              33,899
     Capacity purchased                                               1,447               9,062
     Other                                                           34,464              38,754
  Maintenance                                                         5,071               9,446
  Depreciation (Note G)                                               7,119              17,739
  Amortization of regulatory assets                                  15,804               7,026
  Income taxes (Note F)                                              13,206              15,525
  Other taxes (Note G)                                               11,741              14,009
                                                               -------------       -------------
       Total                                                        156,321             145,460
                                                               -------------       -------------
OPERATING INCOME                                                     24,656              23,207
                                                               -------------       -------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                   181                  13
  Other-net (Note G)                                                  2,402                (469)
  Non-operating income taxes (Note F)                                  (640)                891
                                                               -------------       -------------
       Total                                                          1,943                 435
                                                               -------------       -------------
INCOME BEFORE INTEREST CHARGES                                       26,599              23,642
                                                               -------------       -------------
INTEREST CHARGES
  Interest on long-term debt                                          9,606              12,227
  Interest on Seabrook obligation bonds owned by the company         (1,618)             (1,711)
  Dividend requirement of mandatorily redeemable securities           1,203               1,203
  Other interest (Note G)                                               391               1,856
  Allowance for borrowed funds used during construction                (411)               (448)
                                                               -------------       -------------
                                                                      9,171              13,127
  Amortization of debt expense and redemption premiums                  563                 614
                                                               -------------       -------------
       Net Interest Charges                                           9,734              13,741
                                                               -------------       -------------

NET INCOME                                                           16,865               9,901
Dividends on preferred stock                                              -                  51
                                                               -------------       -------------
INCOME APPLICABLE TO COMMON STOCK                                    16,865               9,850
                                                               =============       =============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                  14,069              14,042
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                14,072              14,044

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                $1.20               $0.70

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

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

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

                                     ASSETS
                             (Thousands of Dollars)


<CAPTION>
                                                        March 31,        December 31,
                                                          2000              1999*
                                                          ----              -----
                                                       (Unaudited)
<S>                                                     <C>                <C>
Utility Plant at Original Cost
  In service                                              $930,875         $1,007,065
  Less, accumulated provision for depreciation             461,855            532,409
                                                     --------------    ---------------
                                                           469,020            474,656

Construction work in progress                               26,580             25,708
Nuclear fuel                                                21,798             21,101
                                                     --------------    ---------------
     Net Utility Plant                                     517,398            521,465
                                                     --------------    ---------------


Other Property and Investments
   Investment in generation facility                        79,746             83,494
   Nuclear decommissioning trust fund assets                29,568             28,255
   Other                                                    22,030             20,098
                                                     --------------    ---------------
                                                           131,344            131,847
                                                     --------------    ---------------


Current Assets
  Unrestricted cash and temporary cash investments          21,951             39,099
   Restricted cash                                          28,919             29,223
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,800 and $1,800                          52,741             56,057
   Other, less allowance for doubtful accounts
     of  $525  and $508                                     63,278             53,612
  Accrued utility revenues                                  21,068             25,019
  Fuel, materials and supplies, at average cost              9,754              9,259
  Prepayments                                                6,200              3,056
  Other                                                      6,736              4,801
                                                     --------------    ---------------
     Total                                                 210,647            220,126
                                                     --------------    ---------------

Deferred Charges
  Unamortized debt issuance expenses                         8,048              8,688
  Other                                                      5,786              6,099
                                                     --------------    ---------------
     Total                                                  13,834             14,787
                                                     --------------    ---------------

Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
                   THROUGH THE RATEMAKING PROCESS)
  Nuclear plant investments-above market                   513,149            518,268
  Income taxes due principally to book-tax differences     163,599            166,965
  Long-term purchase power contracts-above market          140,387            144,406
  Connecticut Yankee                                        35,671             37,013
  Unamortized redemption costs                              23,143             22,314
  Unamortized cancelled nuclear projects                     8,487              8,780
  Displaced worker protection costs                          5,157              5,746
  Uranium enrichment decommissioning cost                    1,031              1,040
  Other                                                     21,234              5,453
                                                     --------------    ---------------
     Total                                                 911,858            909,985
                                                     --------------    ---------------

                                                        $1,785,081         $1,798,210
                                                     ==============    ===============
</TABLE>

*Derived from audited financial statements

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

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

                         CAPITALIZATION AND LIABILITIES
                             (Thousands of Dollars)


<CAPTION>
                                                              March 31,          December 31,
                                                                2000                 1999*
                                                                ----                 -----
                                                             (Unaudited)
<S>                                                            <C>                 <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                $292,006            $292,006
    Paid-in capital                                                2,320               2,253
    Capital stock expense                                         (2,170)             (2,170)
    Unearned employee stock ownership plan equity                 (9,023)             (9,261)
    Retained earnings                                            182,204             175,470
                                                       ------------------    ----------------
                                                                 465,337             458,298
  Company-obligated mandatorily redeemable securities
   of subsidiary holding solely parent debentures                 50,000              50,000
  Long-term debt
    Long-term debt                                               604,800             605,641
    Investment in Seabrook obligation bonds                      (82,635)            (87,413)
                                                       ------------------    ----------------
      Net long-term debt                                         522,165             518,228
                                                       ------------------    ----------------

          Total                                                1,037,502           1,026,526
                                                       ------------------    ----------------

Noncurrent Liabilities
  Purchase power contract obligation                             140,387             144,406
  Nuclear decommissioning obligation                              29,568              28,255
  Connecticut Yankee contract obligation                          25,565              27,056
  Pensions accrued                                                15,110              19,026
  Obligations under capital leases                                16,032              16,131
  Other                                                           10,646              10,394
                                                       ------------------    ----------------
          Total                                                  237,308             245,268
                                                       ------------------    ----------------

Current Liabilities
  Current portion of long-term debt                                  859              25,000
  Notes payable                                                   14,121              17,131
  Accounts payable                                                33,715              49,069
  Accounts payable - APS customers                                62,069              56,220
  Dividends payable                                               10,130              10,125
  Taxes accrued                                                   11,240               2,570
  Interest accrued                                                12,266               8,433
  Obligations under capital leases                                   383                 375
  Other accrued liabilities                                       42,672              39,421
                                                       ------------------    ----------------
          Total                                                  187,455             208,344
                                                       ------------------    ----------------

Customers' Advances for Construction                               1,873               1,867
                                                       ------------------    ----------------

Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
                        THROUGH THE RATEMAKING PROCESS)
  Accumulated deferred investment tax credits                     15,070              15,157
  Deferred gains on sale of property                              15,901              15,901
  Customer refund                                                 18,554              18,381
  Other                                                            2,924               2,543
                                                       ------------------    ----------------
          Total                                                   52,449              51,982
                                                       ------------------    ----------------

Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
                       TO TAXING AUTHORITIES)                    268,494             264,223
Commitments and Contingencies (Note L)
                                                       ------------------    ----------------
                                                              $1,785,081          $1,798,210
                                                       ==================    ================
</TABLE>

* Derived from audited financial statements

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

                                     - 5 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                             (Thousands of Dollars)
                                   (Unaudited)


<CAPTION>
                                                                          Three Months Ended
                                                                               March 31,
                                                                        2000              1999
                                                                        ----              ----
<S>                                                                    <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                           $16,865           $9,901
                                                                   ------------      -----------
  Adjustments to reconcile net income to net cash provided
   by operating activities:
     Depreciation and amortization                                      16,602           22,466
     Deferred income taxes                                               5,415             (732)
     Deferred investment tax credits - net                                 (87)            (190)
     Amortization of nuclear fuel                                        1,890            3,191
     Allowance for funds used during construction                         (592)            (461)
     CTA and SBC revenue adjustment                                     (9,528)               -
     Amortization of deferred return                                         -            3,147
     Changes in:
                   Accounts receivable - net                            (6,350)          11,113
                   Fuel, material and supplies                            (495)            (427)
                   Prepayments                                          (3,144)          (5,044)
                   Accounts payable                                     (9,505)         (32,481)
                   Interest accrued                                      3,833            3,905
                   Taxes accrued                                         8,670           14,425
                   Other assets and liabilities                          2,500           (9,818)
                                                                   ------------      -----------
     Total Adjustments                                                   9,209            9,094
                                                                   ------------      -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES                               26,074           18,995
                                                                   ------------      -----------

CASH FLOWS FROM FINANCING ACTIVITIES
  Common stock                                                             304              300
  Notes payable                                                         (3,010)          (4,720)
  Securities redeemed and retired:
    Long-term debt                                                     (25,750)         (86,202)
  Lease obligations                                                        (91)             (85)
  Dividends
    Preferred stock                                                          -              (51)
    Common stock                                                       (10,125)         (10,104)
                                                                   ------------      -----------
NET CASH USED IN FINANCING ACTIVITIES                                  (38,672)        (100,862)
                                                                   ------------      -----------

CASH FLOWS FROM INVESTING ACTIVITIES
   Plant expenditures, including nuclear fuel                           (9,632)          (5,784)
   Investment in debt securities                                         4,778            5,447
                                                                   ------------      -----------
NET CASH USED IN INVESTING ACTIVITIES                                   (4,854)            (337)
                                                                   ------------      -----------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                              (17,452)         (82,204)
BALANCE AT BEGINNING OF PERIOD                                          68,322          124,501
                                                                   ------------      -----------
BALANCE AT END OF PERIOD                                                50,870           42,297
LESS: RESTRICTED CASH                                                   28,919           26,503
                                                                   ------------      -----------
BALANCE: UNRESTRICTED CASH AND TEMPORARY CASH INVESTMENTS              $21,951          $15,794
                                                                   ============      ===========

CASH PAID DURING THE PERIOD FOR:
  Interest (net of amount capitalized)                                  $2,608           $6,306
                                                                   ============      ===========
  Income taxes                                                          $2,000           $3,700
                                                                   ============      ===========
</TABLE>



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

                                     - 6 -
<PAGE>


                         THE UNITED ILLUMINATING COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                   (UNAUDITED)

     The consolidated  financial  statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange  Commission.  The statements  reflect
all  adjustments  that are, in the opinion of  management,  necessary  to a fair
statement of the results for the periods presented.  All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial  statements prepared in accordance with generally accepted
accounting  principles have been condensed or omitted pursuant to such rules and
regulations.  The Company believes that the disclosures are adequate to make the
information  presented not misleading.  These consolidated  financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year  ended  December  31,  1999.  Such notes are  supplemented  as
follows:

(A)  STATEMENT OF ACCOUNTING POLICIES

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

     The weighted  average  AFUDC rate applied in the first three months of 2000
and 1999 was 7.5% and 7.0%, respectively, on a before-tax basis.

NUCLEAR DECOMMISSIONING TRUSTS

     External  trust  funds  are   maintained  to  fund  the  estimated   future
decommissioning  costs of the nuclear  generating units in which the Company has
an  ownership  interest.  These  costs are  accrued as a charge to  depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current  basis.  The Company paid  $997,000 and $666,000 in the first three
months of 2000 and 1999, respectively,  into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 2000, the Company's shares of
the trust fund balances,  which included accumulated earnings on the funds, were
$21.7  million  and $7.9  million  for  Seabrook  Unit 1 and  Millstone  Unit 3,
respectively.   These  fund  balances  are  included  in  "Other   Property  and
Investments"  and  the  accrued   decommissioning   obligation  is  included  in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.

(B)  CAPITALIZATION

COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding at March 31, 2000, of which 265,434 shares were  unallocated  shares
held by The United  Illuminating  Company  401(k)/Employee  Stock Ownership Plan
(KSOP) 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.  Options to
purchase  3,500  shares of stock at an  exercise  price of $30 per share,  7,800
shares of stock at an exercise price of $39.5625 per share,  and 5,000 shares of
stock at an exercise  price of $42.375 per share have been  granted by the Board
of  Directors  and  remained  outstanding  at March 31,  2000.  No options  were
exercised during the first quarter ended March 31, 2000.



                                     - 7 -
<PAGE>



                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     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 132,000 shares of
stock at an exercise price of $43.21875 per share and 186,900 shares of stock at
an  exercise  price of  $39.40625  per share  have been  granted by the Board of
Directors  and remained  outstanding  at March 31, 2000.  No options to purchase
shares of the  Company's  common stock can be exercised  without the approval of
the DPUC;  and, as of March 31, 2000, the Company had not requested  approval by
the DPUC.

     The Company has entered  into an  arrangement  under which it loaned  $11.5
million to the KSOP. The trustee for the KSOP used the funds to purchase  shares
of the Company's  common stock in open market  transactions.  The shares will be
allocated to employees' KSOP accounts, as the loan is repaid, to cover a portion
of the  Company's  required KSOP  contributions.  The loan will be repaid by the
KSOP over a twelve-year period, using the Company's  contributions and dividends
paid on the  unallocated  shares of the stock held by the KSOP.  As of March 31,
2000,  265,434  shares,  with a fair  market  value of $10.4  million,  had been
purchased by the KSOP and had not been  committed to be released or allocated to
KSOP participants.

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 March 31, 2000.

LONG-TERM DEBT

     On December  16, 1999,  the Company  borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the  issuance  by the BFA of $25  million  principal  amount of  tax-exempt
Pollution Control  Refunding  Revenue Bonds (PCRRBs).  The Company is obligated,
under its borrowing  agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders  such amounts as will be required to pay, when due, the principal of
and the premium,  if any, and interest on the PCRRBs.  The PCRRBs will mature in
2029, and their interest rate is fixed at 5.4% for the three-year  period ending
December 1, 2002. At December 31,1999, these proceeds were held by a trustee and
were recognized as cash and long-term debt on the Consolidated Balance Sheet. On
January 15, 2000, the Company used the proceeds of this $25 million borrowing to
redeem and repay $25 million of 8.0%,  1989 Series A, Pollution  Control Revenue
Bonds, an outstanding series of tax-exempt bonds on which the Company also had a
payment  obligation to a trustee for the bondholders.  Expenses  associated with
this  transaction,  including  redemption  premiums  totaling $750,000 and other
expenses of approximately $417,000, were paid by the Company.

(E)  SHORT-TERM CREDIT ARRANGEMENTS

     The Company has a revolving credit  agreement with a group of banks,  which
currently  extends to December 7, 2000. The borrowing  limit of this facility is
$60 million.  The facility  permits the Company to borrow funds at a fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London.  If a material  adverse  change in the  business,  operations,  affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries,  on a consolidated  basis,  should occur, the banks may decline to
lend  additional  money to the Company under this  revolving  credit  agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and  payable.  As of March 31,  2000,  the Company had $14 million in
short-term borrowings outstanding under this facility.


                                     - 8 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

(F) INCOME TAXES
<CAPTION>
                                                             Three Months Ended
                                                                  March 31,
                                                           2000               1999
                                                           ----               ----
                                                                   (000's)
<S>                                                         <C>                <C>
Income tax expense consists of:

Income tax provisions:
  Current
           Federal                                           $6,862            $12,337
           State                                              1,656              3,219
                                                       -------------      -------------
              Total current                                   8,518             15,556
                                                       -------------      -------------
  Deferred
           Federal                                            4,651               (154)
           State                                                764               (578)
                                                       -------------      -------------
              Total deferred                                  5,415               (732)
                                                       -------------      -------------

  Investment tax credits                                        (87)              (190)
                                                       -------------      -------------

     Total income tax expense                               $13,846            $14,634
                                                       =============      =============

Income tax components charged as follows:
  Operating expenses                                        $13,206            $15,525
  Other income and deductions - net                             640               (891)
                                                       -------------      -------------

     Total income tax expense                               $13,846            $14,634
                                                       =============      =============


The following table details the components
 of the deferred income taxes:
     Seabrook sale/leaseback transaction                    ($1,997)           ($2,082)
     Pension benefits                                         1,548              1,525
     Accelerated depreciation                                  (353)             1,250
     Tax depreciation on unrecoverable plant investment          23              1,188
     Unit overhaul and replacement power costs                 (454)              (898)
     Conservation and load management                           (27)              (873)
     Postretirement benefits                                    (92)              (433)
     Displaced worker protection costs                         (235)                 -
     Bond redemption costs                                      184               (256)
     Cancelled nuclear plant                                   (117)              (117)
     Restructuring costs                                      2,330                  -
     SBC and CTA accrual                                      3,799                  -
     Other - net                                                806                (36)
                                                       -------------      -------------

Deferred income taxes - net                                  $5,415              ($732)
                                                       =============      =============
</TABLE>

                                     - 9 -
<PAGE>
<TABLE>
                         THE UNITED ILLUMINATING COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION
<CAPTION>

                                                                 Three Months Ended
                                                                      March 31,
                                                                 2000               1999
                                                                 ----               ----
                                                                         (000's)
<S>                                                           <C>                <C>
Operating Revenues
------------------

     Retail                                                    $148,941           $152,391
     Wholesale                                                   18,614             13,593
     CTA and SBC revenue                                          9,528                  -
     Other                                                        3,894              2,683
                                                           -------------      -------------
          Total Operating Revenues                             $180,977           $168,667
                                                           =============      =============

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

    Retail
     Residential                                                537,082            533,768
     Commercial                                                 574,772            553,798
     Industrial                                                 277,019            269,060
     Other                                                       13,325             12,199
                                                           -------------      -------------
                                                              1,402,198          1,368,825
    Wholesale                                                   625,005            652,746
                                                           -------------      -------------
          Total Sales by Class                                2,027,203          2,021,571
                                                           =============      =============

Depreciation
------------

     Plant in Service                                            $6,121            $14,655
     Amortization of Conservation and
              Load Management Costs                                   -              2,418
     Nuclear Decommissioning                                        998                666
                                                           -------------      -------------
                                                                 $7,119            $17,739
                                                           =============      =============

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

    Charged to:
     Operating:
        State gross earnings                                     $6,388             $5,854
        Local real estate and personal property                   3,849              6,326
        Payroll taxes                                             1,504              1,829
                                                           -------------      -------------
                                                                 11,741             14,009
     Nonoperating and other accounts                                120                134
                                                           -------------      -------------
          Total Other Taxes                                     $11,861            $14,143
                                                           =============      =============

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

     Interest income                                               $287               $667
     Equity earnings from Connecticut Yankee                        149                181
     Earnings (Loss) from subsidiary companies-before tax         2,210             (1,206)
     Miscellaneous other income and (deductions) - net             (244)              (111)
                                                           -------------      -------------
          Total Other Income and (Deductions) - net              $2,402              ($469)
                                                           =============      =============

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

     Notes Payable                                                 $312             $1,284
     Other                                                           79                572
                                                           -------------      -------------
          Total Other Interest Charges                             $391             $1,856
                                                           =============      =============
</TABLE>

                                     - 10 -
<PAGE>


                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(L)  COMMITMENTS AND CONTINGENCIES

CAPITAL EXPENDITURE PROGRAM

     The Company's continuing capital expenditure program is presently estimated
at $195.2 million, excluding AFUDC, for 2000 through 2004.

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  Nuclear   Regulatory   Commission   requires  each  operating  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 two operating 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 $3.0 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 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 the  Company.  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


                                     - 11 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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 any return on equity for Connecticut  Yankee. 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 the
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  equity.  On April 7, 2000,  Connecticut  Yankee  reached a
settlement  agreement with the Connecticut  Department of Public Utility Control
and the  Connecticut  Office of Consumer  Counsel (two of the intervenors in the
FERC proceeding).  Under this agreement,  Connecticut Yankee would be allowed by
the FERC to earn a return  on equity  of 6% from the date of  acceptance  of the
settlement  by  the  FERC.  The  settlement  agreement  also  stipulates  a  new
decommissioning  cost estimate for the  Connecticut  Yankee Unit for purposes of
FERC-approved decommissioning cost collections by Connecticut Yankee through the
power contracts with the unit's owners. This agreement has been submitted to the
FERC,  but the  Company is unable to predict,  at this time,  the outcome of the
FERC proceeding.

     The Company's  estimate of its remaining share of Connecticut Yankee costs,
including  decommissioning,  less  return  of  investment  (approximately  $10.1
million)  and return on  investment  (approximately  $3.7  million) at March 31,
2000, is approximately $25.6 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.  The
Company is obligated to furnish a guarantee for its  participating  share of the
debt  financing for the Phase II facility.  As of March 31, 2000,  the Company's
guarantee liability for this debt was approximately $6.0 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. The total amount of these expenditures is not now
determinable.

             SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS

     The  Company  has  estimated  that the total  cost of  decontaminating  and
demolishing  its Steel Point  Station  and  completing  requisite  environmental
remediation  of  the  site  will  be  approximately   $11.3  million,  of  which
approximately  $8.5 million had been incurred as of March 31, 2000, 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


                                     - 12 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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.  In
addition,  the Company is currently  replacing the bulkhead that  surrounds this
site,  at an  estimated  cost of $13.5  million.  Of this  amount,  $4.2 million
represents  the  portion  of the costs to  protect  the  Company's  transmission
facilities and will be capitalized as plant in service.  The remaining estimated
cost of $9.3 million was  expensed in 1999.  The Company has agreed to convey to
an unaffiliated entity,  Quinnipiac Energy, LLC, (QE) the entire English Station
site,  reserving to the Company  permanent  easements  for the  operation of its
transmission  facilities on the site. This transaction is subject to the parties
obtaining various regulatory  approvals,  which are being sought. If the site is
conveyed  to QE,  the  Company  will fund 61%  (approximately  $460,000)  of the
environmental  remediation  costs that will be  incurred by QE to bring the site
into compliance  with applicable  Connecticut  minimum  standards  following the
conveyance.

     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  $565  million  (in  2000  dollars)  as  the
decommissioning  cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $99 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. The Company's share of the decommissioning  payments
made during the first quarter of 2000 was $0.8 million.  The Company's  share of
the fund at March 31, 2000 was approximately $21.7 million.

     Connecticut has enacted a law requiring the operators of nuclear generating
units  to file  periodically  with  the  DPUC  their  plans  for  financing  the
decommissioning  of the units in that state.  The current  decommissioning  cost
estimate for Millstone  Unit 3 is $619 million (in 2000  dollars),  of which the
Company's share would be  approximately  $23 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).  The Company's  share of the Millstone  Unit 3  decommissioning
payments made during the first  quarter of 2000 was $0.2 million.  The Company's
share of the fund at March 31, 2000 was approximately $7.9 million.  The current
decommissioning  cost  estimate for the  Connecticut  Yankee Unit,  assuming the
prompt  removal  and  dismantling  of the unit,  is $498  million,  of which the
Company's  share would be $47 million.  Through March 31, 2000, $183 million has
been expended for decommissioning.  The projected remaining decommissioning cost
is $315  million,  of  which  the  Company's  share  would be $30  million.  The
decommissioning  trust fund for the  Connecticut  Yankee Unit is also managed by
NU.  For  the   Company's   9.5%  equity   ownership  in   Connecticut   Yankee,
decommissioning  costs of $0.6  million  were funded by the  Company  during the
first quarter of 2000, and the Company's share of the fund at March 31, 2000 was
$18.6 million.



                                     - 13 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(P)  SEGMENT INFORMATION

     The  Company  has one  reportable  operating  segment,  that  of  regulated
generation,  distribution and sale of electricity.  The accounting policies used
for that  segment do not differ  from  those  used for  nonreportable  operating
segments.  Revenues from inter-segment  transactions are not material and all of
the Company's revenues are derived in the United States.

     The revenues from external customers, interest income, interest expense and
depreciation  charges of the one reportable segment are identical to the amounts
shown on the  Consolidated  Statement of Income for each year presented.  Income
before taxes of the reportable segment is not materially  different from that of
the Company as a whole.

     The following table  reconciles the total assets of the reportable  segment
with the total assets shown on the Consolidated  Balance Sheet at March 31, 2000
and December 31, 1999:

                                             MARCH 31,          DECEMBER 31,
                                              2000                 1999
                                              ----                 ----
                                                        (000's)
   Total Assets - Regulated Utility         $1,785,651          $1,809,451
   Total Assets - Unregulated Subsidiaries     201,470             194,642
   Total Assets - Elimination                 (202,040)           (205,883)
                                             ---------           ---------
   Total Consolidated Assets                $1,785,081          $1,798,210
                                            ==========          =========



                                     - 14 -
<PAGE>




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

                     MAJOR INFLUENCES ON FINANCIAL CONDITION

     The  Company's  financial  condition  will  continue to be dependent on the
level of its utility retail sales and the Company's ability to control expenses,
as well as on the performance of the  non-regulated  businesses of the Company's
subsidiaries.  The two primary  factors  that affect  utility  sales  volume are
economic  conditions  and  weather.  Total  utility  operation  and  maintenance
expense, excluding one-time items and cogeneration capacity purchases,  declined
by 1.6% annually, on average, during the five years 1995-1999.

     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.

     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  retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and  accelerated  the  amortization  and recovery of  unspecified  assets during
1999-2001 if the  Company's  common stock  equity  return on utility  investment
exceeds 10.5% after recording the amortization.  The Rate Plan also provided for
retail  price  reductions  of about  5%,  compared  to 1996 and  phased-in  over
1997-2001,  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 Company's authorized return on utility common stock equity
during the period is 11.5%.  Earnings above 11.5%, on an annual basis, are to be
utilized  one-third  for  customer  price  reductions,   one-third  to  increase
amortization of assets, and one-third retained as earnings.

     The Rate Plan  includes a provision  that it may be reopened  and  modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999,  the DPUC issued its  decision  establishing  the  Company's
standard offer customer rates,  commencing January 1, 2000, at a level 10% below
1996 rates,  as directed by the  Restructuring  Act  described in detail  below.
These standard  offer customer rates are in effect for the period  2000-2001 and
supercede  the rate  reductions  for this period that were  included in the Rate
Plan. The decision also reduced the required amount of accelerated  amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect  through 2001. The  Connecticut  Office of Consumer
Counsel,  the statutory  representative of consumer  interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.

     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.  As a result of the Act, the business of
generating  and  selling   electricity   directly  to  consumers  is  opened  to
competition.  These  business  activities  are  separated  from the  business of
delivering  electricity  to  consumers,  also  known  as  the  transmission  and
distribution  business.  The business of delivering electricity remains with the
incumbent franchised utility companies  (including the Company),  which continue
to  be  regulated  by  the  DPUC  as  Distribution  Companies.  Since  mid-1999,
Distribution  Companies  have been required to separate on consumers'  bills the
electricity  generation  services  component  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," an "energy  conservation and load management  program charge"
and  a  "renewable  energy  investment   charge."  The  competitive   transition
assessment  represents  costs that have been reasonably  incurred by, or will be
incurred by, Distribution  Companies to meet their public service obligations as


                                     - 15 -
<PAGE>

electric  companies,  and that will likely not  otherwise  be  recoverable  in a
competitive  generation  and supply  market.  These costs  include  above-market
long-term  purchased power contract  obligations,  regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits   charge   represents   public   policy   costs,   such  as  generation
decommissioning  and displaced  worker  protection  costs.  Beginning in 2000, a
Distribution  Company must collect the competitive  transition  assessment,  the
systems benefits  charge,  the energy  conservation and load management  program
charge and the renewable energy investment charge from all Distribution  Company
customers.

     The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs  associated  with its power plants,  the Company must
attempt to divest its  ownership  interests in its  nuclear-fueled  power plants
prior to 2004. On October 1, 1998, in its "unbundling plan" filing with the DPUC
under the Restructuring Act, and in other regulatory dockets, the Company stated
that it plans to divest its nuclear  generation  ownership  interests  (17.5% of
Seabrook  Unit 1 in New  Hampshire  and 3.685% of  Millstone  Station  Unit 3 in
Connecticut)  by the end of 2003, in accordance with the  Restructuring  Act. On
April 19, 2000 the DPUC approved the Company's  plan for divesting its ownership
interest  in  Millstone  Unit 3 by  participation  in an  auction  process to be
conducted by a  consultant  selected by the DPUC.  On April 26,  2000,  the DPUC
selected J. P.  Morgan & Co. to conduct  this  auction,  which is expected to be
concluded by the end of 2000. It is currently estimated that obtaining requisite
regulatory  approvals  of the  auction  results and  consummating  the sale will
require at least an additional six months. The divestiture  process for Seabrook
Unit 1 has not yet been determined.

      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 is to be achieved by a corporate  restructuring
of  the  Company  and  its  unregulated  subsidiaries  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.  As soon as this becomes effective,  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.  In a
decision  dated  May  19,  1999,  the  DPUC  approved  the  proposed   corporate
restructuring.  At a special meeting of the Company's shareowners, held on March
17, 2000, the shareowners voted to approve the restructuring. In an order issued
March 31, 2000, the Federal Energy Regulatory Commission authorized the proposed
corporate restructuring. An application is pending before the Nuclear Regulatory
Commission seeking its consent to the proposed corporate restructuring.

      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,
including the results of the Company's divestiture of its ownership interests in
Millstone Unit 3 and Seabrook Unit 1, in accordance with the Restructuring  Act.
The Connecticut  Office of Consumer  Counsel,  the statutory  representative  of
consumer  interests  in public  utility  matters,  appealed  to the  Connecticut
Superior Court from the DPUC decision,  challenging the DPUC's  determination of
the  minimum  bid  price  to be used in the  auctions  of  Millstone  Unit 3 and
Seabrook Unit 1 ownership interests.  On May 2, 2000, the Company entered into a
settlement  agreement  with the Office of  Consumer  Counsel  and the DPUC staff
resolving the issue raised in this Superior Court appeal;  and the agreement has
been  submitted  to the DPUC for its  consideration  and  approval.  If the DPUC
approves the settlement agreement, the Superior Court appeal will be withdrawn.



                                     - 16 -
<PAGE>

      Under the Restructuring  Act, retail customers  representing a total of up
to 35% of the Company's  retail  customer load became 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 is
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 must  include the  fully-bundled  price of
generation,  transmission and distribution  services, the competitive transition
assessment,  the systems  benefits  charge and the  conservation  and  renewable
energy charges. The fully-bundled standard offer rates must also be at least 10%
below the average fully-bundled prices in 1996.

     In March of 1999,  the DPUC  commenced a proceeding  to determine  what the
Company's standard offer rates would be under the Restructuring Act. On July 27,
1999, the Company and Enron Capital & Trade Resources Corp. (ECTR), an affiliate
of  Enron  Corp.,  of  Houston,  Texas  (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  included an
arrangement  between  the  Company  and  ECTR  whereby  ECTR  would  supply  the
generation services needed by the Company to meet its standard offer obligations
for the four-year standard offer period, and an assumption by ECTR of all of the
Company's long-term purchased power agreement (PPA) obligations. The stipulation
and settlement  proposal also provided for the Company's standard offer rates at
a  fully-bundled  level  complying  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. In its decision, dated October 1, 1999, on the Company's standard offer
rates,  the DPUC approved  elements of the stipulation and settlement  proposal,
including the arrangements with ECTR,  subject to specified  changes,  including
changes in the level of the generation  services  component of customers' rates.
On October 15, 1999,  the Company  filed its standard  offer rates in compliance
with the DPUC's decision,  and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal.  These filings were approved by the DPUC on
December  9, 1999 and,  on  December  28,  1999,  the  Company  and Enron  Power
Marketing,  Inc. (EPMI),  another  affiliate of Enron,  entered into a Wholesale
Power  Supply  Agreement,  a PPA  Entitlements  Transfer  Agreement  and related
agreements  documenting  the  approved  four-year  standard  offer power  supply
arrangement and the assumption of all of the Company's PPAs,  effective  January
1, 2000. The agreements  with EPMI also include a financially  settled  contract
for  differences  related to certain  call  rights of EPMI and put rights of the
Company with respect to the  Company's  entitlements  in Seabrook  Unit 1 and in
Millstone  Unit 3, and the  Company's  provision  to EPMI of  certain  ancillary
products  and  services  associated  with  those  nuclear  entitlements,   which
provisions  terminate  at the earlier of December  31, 2003 or the date that the
Company  sells  its  nuclear  interests.  The  agreements  do not  restrict  the
Company's  right to sell to third parties the Company's  ownership  interests in
those nuclear generation units or the generated energy actually  attributable to
its  ownership  interests.  The Office of Consumer  Counsel has  appealed to the
Connecticut Superior Court from the DPUC's standard offer decision,  challenging
the DPUC's  determination of the Company's average  fully-bundled prices in 1996
rates from which a 10%  reduction  is required  by the  Restructuring  Act.  The
Company and the Connecticut Attorney General are contesting this court challenge
of the DPUC's  decision.  The  Company is unable to predict,  at this time,  the
outcome of this Superior Court appeal.


                                     - 17 -
<PAGE>


                           CAPITAL EXPENDITURE PROGRAM

     The Company's 2000-2004 estimated capital  expenditure  program,  excluding
allowance for funds used during construction, is presently budgeted as follows:

<TABLE>
<CAPTION>
                                     2000         2001         2002        2003         2004         TOTAL
                                     ----         ----         ----        ----         ----         -----
                                                                          (000's)
<S>                                 <C>         <C>          <C>         <C>          <C>          <C>
Nuclear Generation (1)             $ 2,817      $ 3,624      $    -      $    -       $    -       $  6,441
Distribution and Transmission       39,007       31,396       17,240      14,516       31,915       134,074
Other                                3,300           -            -           -            -          3,300
                                    ------       ------       ------      ------       ------       -------
Subtotal                            45,124       35,020       17,240      14,516       31,915       143,815

Nuclear Fuel                         8,920        6,962        2,837       8,274           -         26,993
                                    ------       ------       ------      ------       ------       -------

Total Utility Expenditures          54,044       41,982       20,077      22,790       31,915       170,808

Total Non-Regulated Business
  Expenditures                       7,788        4,564        3,864       4,038        4,167        24,421
                                    ------       ------       ------      ------       ------       -------

   Total                           $61,832      $46,546      $23,941     $26,828      $36,082      $195,229
                                   =======      =======      =======     =======      =======      ========
</TABLE>

(1)  The Connecticut  Restructuring Act and decisions of the Connecticut DPUC do
     not allow for the  capitalization of nuclear  generation costs,  other than
     for nuclear fuel, beyond 2001.

                         LIQUIDITY AND CAPITAL RESOURCES

     At March 31, 2000, the Company had $50.9 million of cash and temporary cash
investments,  a decrease  of $17.4  million  from the  corresponding  balance at
December 31, 1999. The  components of this  decrease,  which are detailed in the
Consolidated Statement of Cash Flows, are summarized as follows:

                                                                 (Millions)

       Balance, December 31, 1999                                   $68.3
                                                                     ----

       Net cash provided by operating activities                     26.1

       Net cash provided by (used in) financing activities:
       -   Financing activities, excluding dividend payments        (28.6)
       -   Dividend payments                                        (10.1)
       Investment in debt securities                                  4.8
       Cash invested in plant, including nuclear fuel                (9.6)
                                                                     ----

             Net Change in Cash                                     (17.4)
                                                                     ----

       Balance, March 31, 2000                                      $50.9
                                                                    =====



                                     - 18 -
<PAGE>


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

<TABLE>
<CAPTION>
                                                          2000       2001      2002       2003       2004
                                                          ----       ----      ----       ----       ----
                                                                            (millions)
<S>                                                       <C>       <C>       <C>        <C>        <C>
Cash on Hand - Beginning of Year  (1)                     $39.1     $ -       $  -       $  -       $  -
Internally Generated Funds less Dividends  (2)             78.2      81.1      83.5       90.9       71.1
                                                           ----      ----      ----       ----       ----
         Subtotal                                         117.3      81.1      83.5       90.9       71.1

Less:
Utility Capital Expenditures  (2)                          54.0      42.0      20.1       22.8       31.9
Non-Regulated Business Capital Expenditures  (2)            7.8       4.6       3.9        4.0        4.2
                                                           ----      ----      ----       ----       ----

Cash Available to pay Debt Maturities and Redemptions      55.5      34.5      59.5       64.1       35.0

Less:
Maturities and Mandatory Redemptions                         -         -      100.0      100.0         -
Optional Redemptions                                       75.0        -         -          -          -
Repayment of Short-Term Borrowings                         17.0        -         -          -          -
                                                           ----      ----     -----      -----       ----

External Financing Requirements (Surplus)  (2)            $36.5    $(34.5)   $ 40.5      $35.9     $(35.0)
                                                           ====      ====      ====       ====       ====
</TABLE>

(1)  Excludes $2.3 million Seabrook Unit 1 operating deposit and restricted cash
     of American Payment Systems, Inc. of $26.9 million.
(2)  Internally  Generated  Funds  less  Dividends,   Capital  Expenditures  and
     External Financing Requirements are estimates based on current earnings and
     cash flow projections.  All of these estimates are subject to change due to
     future events and conditions that may be substantially different from those
     used in developing the projections.

     All of the Company's  capital  requirements that exceed available cash will
have  to be  provided  by  external  financing.  Although  the  Company  has  no
commitment to provide such financing from any source of funds,  other than a $60
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 7, 2000. The borrowing  limit of this facility is
$60 million.  The facility  permits the Company to borrow funds at a fluctuating
interest  rate  determined  by the prime  lending  market in New York,  and also
permits the Company to borrow money for fixed  periods of time  specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London.  If a material  adverse  change in the  business,  operations,  affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries,  on a consolidated  basis,  should occur, the banks may decline to
lend  additional  money to the Company under this  revolving  credit  agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and  payable.  As of March 31,  2000,  the Company had $14 million in
short-term borrowings outstanding under this facility.

                              SUBSIDIARY OPERATIONS

     The Company 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 the Company's  regulated  electric  utility business and provide
long-term rewards to the Company 's shareowners.



                                     - 19 -
<PAGE>

     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 the Company and other companies.  Another subsidiary of URI, United
Capital  Investments,  Inc.,  and  its  subsidiaries,  participate  in  business
ventures  that  complement  the  Company's  business.  A third  URI  subsidiary,
Precision  Power,  Inc.  and its  subsidiaries,  provide  specialty  electrical,
telecommunications  and mechanical contracting and power-related services to the
owners of commercial  buildings and  industrial  and  institutional  facilities.
URI's fourth subsidiary,  United Bridgeport Energy,  Inc., is a participant in a
merchant   wholesale  electric   generating   facility  located  in  Bridgeport,
Connecticut.

                              RESULTS OF OPERATIONS

FIRST QUARTER OF 2000 VS. FIRST QUARTER OF 1999
-----------------------------------------------

GENERAL IMPACTS OF CONNECTICUT'S RESTRUCTURING ACT ON FINANCIAL REPORTS
-----------------------------------------------------------------------

     On  April  16,  1999,  the  Company  completed  the  sale of its  operating
fossil-fueled  generating  plants that was  required by  Connecticut's  electric
utility industry restructuring  legislation.  On October 1, 1999, the Department
of Public Utility Control (DPUC) issued its decision  establishing the Company's
standard offer customer rates,  commencing January 1, 2000, at a level 10% below
1996  rates  (about  6%  below  1999  rates),   as  directed  by   Connecticut's
Restructuring  Act. As a result of these two and other  associated  events,  the
"geography"  of the Company's  costs,  particularly  with respect to comparisons
between  the  first  quarter  of 2000 and the  first  quarter  of 1999,  and the
quarterly pattern of revenues and earnings  comparing 2000 to 1999 have changed.
This  particularly  relates to retail pricing  patterns,  wholesale  revenue and
expense,  other  operating  revenues,  retail  purchased  energy and fossil fuel
expenses,  operation and maintenance  expense,  depreciation and property taxes.
For  example,  increased  purchased  energy  expenses  are more  than  offset by
portions of the decreases in  miscellaneous  operation and maintenance  expense,
depreciation  and property  taxes,  due to the sale of  generating  plants.  The
results of these changes are explained  below,  and in the  "Quarterly  Earnings
Pattern for 2000" portion of the LOOKING FORWARD section.

FIRST QUARTER OF 2000 VS. FIRST QUARTER OF 1999
-----------------------------------------------

     Earnings  for the first  quarter of 2000 were $16.9  million,  or $1.20 per
share (on both a basic and diluted basis),  up $7.0 million,  or $.50 per share,
from the first quarter of 1999.  Excluding a one-time item recorded in the first
quarter of 1999,  earnings from  operations (on both a basic and diluted basis),
were up $7.6 million,  or $.54 per share,  from the first  quarter of 1999.  The
earnings  from  operations  contribution  of utility  operations,  excluding the
Nuclear  Division,  was $.97 per share in the first quarter of 2000. The Nuclear
Division  contributed $.22 per share, for a total utility  contribution of $1.19
per  share,  compared  to $.71  per  share in the  first  quarter  of 1999.  The
Company's non-regulated businesses earned $.01 per share in the first quarter of
2000, compared to a loss of $.05 per share in the first quarter of 1999.

     The utility earnings  increase was  attributable to increased  sales,  both
retail and wholesale,  expense reductions, and a shift in the quarterly earnings
pattern  that is  estimated  to have  added  about  $.20 per  share to the first
quarter of 2000 compared to the first quarter of 1999.

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

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

     Overall,  retail revenue  decreased by $3.5 million in the first quarter of
2000 compared to the first  quarter of 1999.  Retail  revenues  from  operations
decreased  by  $4.5  million  for  the  reasons  shown  below.  Retail  revenues


                                     - 20 -
<PAGE>

applicable  to a  one-time  item  increased  by  $1.0  million  because  of 1999
"sharing"  required  under the current  regulatory  structure  as applied to the
one-time item recorded in the first quarter of 1999.

<TABLE>
<CAPTION>
---------------------------------------------------------------- -------------- ------------- ---------
                                                                     From           From
                   Retail Revenues: $ millions                     Operations      One-time     Total
---------------------------------------------------------------- -------------- ------------- ---------
   <S>                                                               <C>             <C>        <C>
   Revenue from:
---------------------------------------------------------------- -------------- ------------- ---------
     Sharing: for 1999 one-time item                                  0.0            1.0         1.0
---------------------------------------------------------------- -------------- ------------- ---------
     Estimate of operating Distribution Division component of
     "real" retail sales growth, up 1.3%                              0.7            0.0         0.7
---------------------------------------------------------------- -------------- ------------- ---------
     Estimate of operating Distribution Division component of
     "leap year day" retail sales growth, up 1.1%                     0.6            0.0         0.6
---------------------------------------------------------------- -------------- ------------- ---------
     Estimate of operating Distribution Division component of
     weather effect on retail sales                                   1.1            0.0         1.1
---------------------------------------------------------------- -------------- ------------- ---------
     Estimate of operating Distribution Division component o
     price reduction                                                 (2.8)           0.0        (2.8)
---------------------------------------------------------------- -------------- ------------- ---------
     Other retail price reduction, mix of sales and other (see
     other operating revenues)                                       (4.1)           0.0        (4.1)
---------------------------------------------------------------- -------------- ------------- ---------
            TOTAL RETAIL REVENUE                                     (4.5)           1.0        (3.5)
---------------------------------------------------------------- -------------- ------------- ---------
</TABLE>

     Retail  fuel and energy  expense  increased  by $39.6  million in the first
quarter of 2000 compared to the first quarter of 1999.  The Company's  operating
fossil-fueled  generation  units were sold on April 16,  1999,  and the  Company
receives, and will receive through 2003, its standard offer service requirements
through  purchased  power  agreements.  These  costs are  recovered  through the
Generation Service Charge (GSC) portion of unbundled rates.

     Wholesale  sales margin  increased by $13.7 million in the first quarter of
2000  compared to the first quarter of 1999.  Margin from the Nuclear  Division,
which was incorporated in retail rates in 1999,  increased by $14.2 million. The
Company's  operating  nuclear  assets,  Seabrook  and  Millstone 3, supply power
solely to the wholesale market in 2000.  Overall,  the Nuclear Division produced
earnings  of $.22 per  share  in the  first  quarter  of  2000,  reflecting  the
wholesale  sales  margin  less  operations  and  maintenance  and  other  costs,
including  taxes.  See the LOOKING FORWARD  section for more details.  There was
margin of $0.5 million from general wholesale activities in the first quarter of
1999.

     Other operating revenues increased by $10.7 million in the first quarter of
2000 compared to the first quarter of 1999. Accrued revenues for the Competitive
Transition Assessment (CTA) and the System Benefits Charge (SBC) of $8.7 million
and $0.9  million,  respectively,  were  recorded in the first  quarter of 2000.
These  revenues  true-up  the CTA and SBC  equity  returns  to 11.5%  and,  as a
consequence,  compensate  for  variances in other retail  revenues  shown in the
table above.  See the LOOKING FORWARD section for more details.  Other operating
revenues  also include  transmission  revenues  from the New England  Power Pool
(NEPOOL),  which increased by $1.3 million in the first quarter of 2000 compared
to the  first  quarter  of 1999,  and  were  mostly  offset  by an  increase  in
transmission operation expense.



                                     - 21 -
<PAGE>

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
decreased by $16.3  million in the first  quarter of 2000  compared to the first
quarter of 1999. The principal components of these expense changes include:

                                                                      $millions
--------------------------------------------------------------------- ----------
Capacity expense:
--------------------------------------------------------------------- ----------
  Cogeneration  (see Note A)                                             (7.0)
--------------------------------------------------------------------- ----------
  Other purchases                                                        (0.6)
--------------------------------------------------------------------- ----------
        TOTAL CAPACITY EXPENSE                                           (7.6)
--------------------------------------------------------------------- ----------
Operating Distribution Division O&M expense:
--------------------------------------------------------------------- ----------
  1999 fossil generation unit operating and maintenance costs            (5.6)
--------------------------------------------------------------------- ----------
  Pension and other employee benefit costs                               (3.4)
--------------------------------------------------------------------- ----------
  NEPOOL transmission expense                                             0.8
--------------------------------------------------------------------- ----------
  Other                                                                  (3.0)
--------------------------------------------------------------------- ----------
        TOTAL OPERATING DISTRIBUTION DIVISION                           (11.2)
--------------------------------------------------------------------- ----------
Other unbundled components of O&M expense:
--------------------------------------------------------------------- ----------
  Nuclear Division (see Note B)                                          (2.2)
--------------------------------------------------------------------- ----------
  Conservation and Load Management and Renewable Energy
  (see note B)                                                            4.7
--------------------------------------------------------------------- ----------
        TOTAL OTHER COMPONENTS                                            2.5
--------------------------------------------------------------------- ----------
        TOTAL O&M EXPENSE                                                (8.7)
--------------------------------------------------------------------- ----------

     Note A: The Company's  wholesale purchased power agreements were assumed by
     Enron Power  Marketing,  Inc. as part of agreements for Enron to supply the
     power needed by the Company to meet its standard  offer  obligations  until
     the end of the  four-year  standard  offer  period and the power  needed to
     serve the Company's special contract  customers for the remaining  contract
     terms.  The Company has created a regulatory asset and liability to reflect
     this  transaction,  and the  regulatory  asset  is  being  amortized,  on a
     straight  line basis,  as part of the CTA. The  amortization  for the first
     quarter of 2000 of about $6.7 million is included in the  "Amortization  of
     regulatory assets" line of the income statement.

     Note B: Nuclear Division operation and maintenance expenses are incurred in
     the production of energy for the wholesale  market and are reflected in the
     Nuclear  Division  results.  About $1.3 million of the reduction was due to
     the absence of  refueling  outage  costs  incurred in the first  quarter of
     1999.  Conservation  and load  management  and  renewable  energy costs are
     pass-through costs recovered in unbundled rates.

     Other taxes,  primarily  property  taxes,  decreased by $2.8 million in the
first quarter of 2000 compared to the first quarter of 1999, due  principally to
the generating plant sale in April of 1999.

     Depreciation  expense  decreased by $10.6  million in the first  quarter of
2000 compared to the first  quarter of 1999.  About $5.1 million of the decrease
was due to the shifting of  depreciation  on nuclear plant stranded  assets from
depreciation expense to amortization of regulatory assets. About $2.4 million of
the decrease was due to the completion of depreciation of conservation assets in
the first half of 1999, and another $2.4 million was due to the generation asset
sale in 1999. Other depreciation expenses decreased by $0.7 million.

     Amortization  of regulatory  assets  increased by $8.8 million in the first
quarter of 2000  compared to the first quarter of 1999.  With three  exceptions,
these costs,  as recorded in 2000, are associated  solely with either the CTA or
the SBC. The exceptions are described in the following two  paragraphs.  The CTA
and SBC  amortization  components in the first quarter of 2000 amounted to $12.8
million  (pre-tax) and were:  nuclear assets (from


                                     - 22 -
<PAGE>

depreciation)  $5.1 million,  purchased  power  contracts (in place of purchased
power expense) $6.7 million, displaced worker costs $0.6 million, and other $0.4
million.  These were partially offset by the elimination  (completed in 1999) of
$3.1 million  (after-tax) of amortization of Seabrook  Nuclear Station  deferred
return.

     The exceptions noted in the previous paragraph are amortizations that apply
to the operating Distribution Division.  They include the amortization of Retail
Access assets,  $0.4 million  (pre-tax),  and  accelerated  amortizations  (both
scheduled and "sharing"  amortization).  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.  Beginning in 2000, these  accelerated  amortizations are charged to the
operating Distribution  Division,  although they reduce CTA plant costs and rate
base. About $2.2 million (after-tax) of accelerated  amortization was charged in
the first quarter of 2000,  compared to about $3.0 million  (after-tax) in 1999,
for a decrease of $0.8 million.

     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
during the third and fourth  quarters of 1999.  One-time items recorded  against
the return on utility  common  stock  equity,  before the Company  achieves  the
11.5%,  are  recorded  with  an  appropriate  "sharing"  effect  if the  Company
projects, at that time, that there will be total "sharing" for the year adequate
to cover the "sharing" for the one-time item.  Such "sharing"  amortization  was
recorded in the first quarter of 1999, in the amount of $1.0 million  before-tax
($0.6  million  after-tax),  as a result of the one-time  gain  recorded in that
quarter.

     Interest charges for the regulated  business continued on a downward trend,
decreasing  by $6.0 million in the first  quarter of 2000  compared to the first
quarter of 1999,  partly  offset by an  increase  of $2.0  million  in  interest
charges  for  non-regulated  subsidiaries.  Most  of the  reduction  in  utility
interest  charges  occurred after the generation asset sale, which was completed
on April 16, 1999. The Company used proceeds  received from the sale of plant to
pay off $205  million of debt.  The  decrease  in utility  interest  charges was
applied to the various unbundled components in 2000.

Non-regulated Business Earnings from Operations
-----------------------------------------------

     Overall,  the  consolidated  non-regulated  businesses  operating under the
parent United Resources, Inc. (URI), after corporate  parent-allocated interest,
earned approximately $0.1 million, or $.01 per share, in the first quarter 2000,
compared  to losses  of about  $0.7  million,  or $.05 per  share,  in the first
quarter of 1999.

     The  results of each of the  subsidiaries  of URI for the first  quarter of
2000  reflects the  allocation  of debt costs from the parent based on a capital
structure,  including  an equity  component,  and  interest  rate,  deemed to be
appropriate  for that type of business.  American  Payment  Systems,  Inc. (APS)
earned  approximately  $0.7 million,  or $.05 per share, in the first quarter of
2000,  reflecting an increase of $0.6 million, or $.04 per share, over the first
quarter of 1999. Precision Power, Inc. (PPI) lost approximately $0.3 million, or
$.02  per  share,  in  the  first  quarter  of  2000,  compared  to  a  loss  of
approximately $0.5 million, or $.03 per share, in the first quarter of 1999. The
improvement  was the result of cost  reduction  efforts and the  acquisition  of
Allan Electric Company,  Inc., despite expected seasonably low business activity
at Allan.

     On May 11, 1999, the Company's non-regulated subsidiary,  United Bridgeport
Energy, Inc. (UBE), increased its 4% passive investment 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  approximately $1.0
million,  or $.07 per  share,  in the first  quarter  of 2000,  as a result of a
shutdown to repair the steam turbine and to make modifications to the combustion
turbine. These repairs and modifications are expected to be completed by the end
of May. United Capital  Investment,  Inc. earned  approximately $1.0 million, or
$.07 per share,  in the first quarter of 2000,  compared


                                     - 23 -
<PAGE>

to a loss of about  $0.4  million,  or $.03 per share,  in the first  quarter of
1999. The improvement  reflects  unrealized  gains on an investment in a venture
capital fund that is valued at its market value at the end of each quarter.

                                 LOOKING FORWARD

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

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

     On December 31, 1996, the Connecticut  Department of Public Utility Control
(DPUC)  issued an order (the Order)  that  implemented  a  five-year  regulatory
framework  (Rate Plan) to reduce the Company's  retail prices and accelerate the
recovery of certain  "regulatory  assets," beginning with deferred  conservation
costs.  The Company has operated  under the terms of this Order since January 1,
1997. 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.

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

     "Sharing",   in  2000,   will  result  only  if  the  regulated   operating
Distribution  Division  exceeds  its allowed  return of 11.5% on utility  common
stock equity. The operating  Distribution  Division is expected to realize about
40-50% of its  pre-sharing  earnings in the third  quarter of each year. It 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
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."

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

     On  January  1, 2000,  the  Company  completed  the  restructuring  process
required by the Connecticut electric utility industry restructuring  legislation
in 1998 and its regulated business became an electricity delivery business.  All
customers are now seeing at least a 10% reduction in their  electric  rates from
1996 levels.

     The framework of the current Rate Plan,  including the "sharing" mechanism,
is expected to continue through 2001.  Regulatory  decisions during 1999 did not
alter the  Company's  allowed  return of 11.5% on  utility  equity,  and did not
impinge on the Company's ability to achieve that return.

     On January 24, 2000, the Company  estimated its year 2000 earnings would be
in the range of  $3.60-$3.80  per share.  Following  better than expected  first
quarter 2000 earnings from both the regulated and  non-regulated  businesses and
experience  with the new  regulated  pricing  structure  that  became  effective
January  1,  2000,  the  Company  is now  revising  its full year 2000  earnings
estimate upwards, to $3.95-$4.10 per share.

     If the  Company  were to earn  11.5% on  utility  equity  in the  regulated
business,  including the Nuclear Division, that level of earnings would generate
$3.35-$3.45 per share. In addition, continued operation of the Company's nuclear
entitlements at the high availability  rates experienced in the first quarter of
2000 would produce additional earnings.



                                     - 24 -
<PAGE>

     Sharing will be greatly  reduced  from the 1999 levels,  due to mandates in
the restructuring legislation. The Company expects sharing to contribute no more
than $.20-$.25 per share in 2000.

     The Company's non-regulated businesses,  under the parent URI, are expected
to contribute  $.25-$.30 per share to earnings in 2000.  This is an  improvement
from previous  expectations.  URI's  wholly-owned  subsidiary,  American Payment
Systems,  Inc., is expected to contribute  about half of this total,  and United
Bridgeport  Energy,  Inc. should add $.05-$.10 per share.  Precision Power, Inc.
and the  other  URI  subsidiaries  will  contribute  the  rest.  As a result  of
management's   continued  confidence  in  the  potential  of  the  non-regulated
businesses, the Company is evaluating further investments in this area. However,
additional   near-term  losses  could  be  incurred  due  to  these  new  growth
initiatives, if the potential for future benefits warrants such losses.

Quarterly Earnings Pattern for 2000
-----------------------------------

     The quarterly  earnings pattern for 2000 will be somewhat smoother than the
earnings  pattern for 1999.  The  primary  reason is the new  regulated  utility
pricing  structure  set by the  Department  of Public  Utility  Control  (DPUC),
effective January 1, 2000, to implement standard offer customer rates at a level
10% below 1996 rates.

     Overall,  the  implementation  of the new rates will produce a retail price
reduction of about 6% compared to 1999 retail  revenues,  excluding  any further
reduction  resulting from earnings  sharing.  In 2000, all of the unbundled rate
components,  except for the component attributable to the operating Distribution
Division, reflect fixed pricing within each rate class. That is, the seasonality
previously associated with historical underlying costs of those rate components,
the largest of which is the Competitive Transition Assessment (CTA) for recovery
of stranded costs, has been eliminated.  Only the operating Distribution Company
component maintains a seasonal pricing structure, and that component is expected
to produce an average price for the year of about 4.2 cents per kilowatthour.

     The Company  earns the allowed  11.5% return on the equity  portions of CTA
and the System Benefits Charge (SBC) rate base (the latter is minimal).  For the
most part, the regulatory  assets that are being  recovered  through the CTA are
being  amortized on a  straight-line  basis.  If CTA revenues do not produce the
allowed  return,  then  deferred  accounting is used to "true-up" to the allowed
return.  This true-up  adjusts for sales volume  fluctuations as well as pricing
factors. A similar adjustment,  on a much less significant scale, applies to the
SBC component.  The generation service,  conservation and renewables charges are
pass-through charges. The only retail sales volume fluctuations that flow to net
income are those that apply to the operating  Distribution Division component of
rates.  Thus, a 1% sales volume increase will produce additional sales margin of
about $2.4 million in 2000, whereas it produced additional sales margin of about
$6.0 million in 1999.

     The other utility  earnings  component that can vary  significantly  is the
Nuclear Division component. The Company's operating nuclear assets, Seabrook and
Millstone 3, supply power solely to the wholesale  market in 2000. Unit outages,
whether scheduled or unscheduled,  will result in lowered sales, and unscheduled
outages  could  result in higher  maintenance  expenses.  For 2000,  Seabrook is
currently scheduled to be out-of-service for refueling in the fourth quarter for
about 29 days, and will show lower earnings in that period. The Company plans to
divest its nuclear  generation  ownership  interests by the end of 2003,  if not
sooner, in accordance with the restructuring legislation.

     The following is a representation of the possible  quarterly  earnings from
operations pattern for currently expected 2000 results, compared to a normalized
pattern for 1999.  Actual  2000  results  may vary  depending  on changes due to
weather,  economic conditions,  sales mix (the usage pattern of the Distribution
Division's retail  customers) and the Company's ability to control expenses,  as
well as the performance of the non-regulated  businesses and other unanticipated
events.

                                     - 25 -
<PAGE>

     The  Company's   current  overall  estimate  of  earnings  per  share  from
operations for 2000 is  $3.95-$4.10.  Significant  variability  could occur each
quarter and still produce earnings within that range. The Company has made range
estimates of quarterly results for 2000 as follows:

     Earnings per share from operations:
                                         Estimated               Actual
                      Quarter            2000 Range               1999
                      -------            ----------               ----
                         1               $1.20 (Actual)           $ .66
                         2               $ .88 - $1.00              .99
                         3               $1.22 - $1.43             1.78
                         4               $ .50 -   .62              .24
                                                                   ----
                                                                  $3.67

     Quarterly range  estimates are not additive,  that is, adding the low range
numbers  produces a result that is lower than the Company's low estimate for the
year.  The sums of the low and high  range  values  should not be  construed  to
represent any estimate other than the Company's  annual  estimate of $3.95-$4.10
per share.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.

     The Company  believes that it has no material  quantitative  or qualitative
exposure to market risk  associated  with  activities  in  derivative  financial
instruments, other financial instruments or derivative commodity instruments.




                                     - 26 -
<PAGE>

                           PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

     In the arbitration  proceeding and lawsuits against Northeast Utilities and
its  subsidiaries  (NU) with respect to their  operation  of  Millstone  Unit 3,
described in Item 2, "Properties-Nuclear  Generation" of the Registrant's Annual
Report (Form 10-K) for the fiscal year ended December 31, 1999,  four additional
non-NU joint  owners,  who  together own about 1 2/3% of the unit,  have settled
their  claims  against  NU  and  have  withdrawn  from  the  prosecution  of the
arbitration  proceeding and lawsuits.  The Registrant and two other non-NU joint
owners,  who  together own about 6 1/3% of the unit,  continue to prosecute  the
arbitration proceeding and lawsuits.

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

     See the Registrant's Current Report (Form 8-K) filed March 22, 2000.

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

     (a) Exhibits.

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

           <S>                    <C>         <C>
           (10)                   10.8e       Copy of Agreement  for  Extension  of  Transmission  Line  Agreement,
                                              dated February 9,  2000, between The United Illuminating  Company and
                                              National  Railroad  Passenger  Corporation,  regarding  extension  of
                                              Transmission  Line  Agreement,  Exhibit 10.8a*,  as supplemented  and
                                              modified by Exhibit 10.8c**.

          (12), (99)              12          Statement Showing  Computation of Ratios of Earnings to Fixed Charges
                                              and Ratios of Earnings to Combined Fixed Charges and Preferred  Stock
                                              Dividend Requirements (Twelve Months Ended March 31,  2000 and Twelve
                                              Months Ended December 31, 1999, 1998, 1997, 1996 and 1995).

          (27)                    27          Financial Data Schedule.
</TABLE>

*    Filed with  Registration  Statement No.  2-60849,  effective  July 24, 1978
     (Exhibit 5.4)
**   Filed with Annual  Report  (Form 10-K) for fiscal year ended  December  31,
     1991 (Exhibit 10.9c)



     (b) Reports on Form 8-K.

         Item       Financial
         Reported   Statement     Date of Report
         --------   ---------     --------------
             5        None        March 17, 2000



                                     - 27 -
<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   05/12/2000      Signature           /s/ Robert L. Fiscus
     -------------              ------------------------------------------------
                                               Robert L. Fiscus
                                Vice Chairman of the Board of Directors,
                                Chief Financial Officer, Treasurer and Secretary



                                     - 28 -