SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549


                                    FORM 10-Q

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

                  FOR THE QUARTERLY PERIOD ENDING JUNE 30, 2000

                                       OR

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

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


         Commission    Registrant; State of Incorporation;   I. R. S. Employer
         File Number   Address; and Telephone Number         Identification No.

          1-6788       THE UNITED ILLUMINATING COMPANY           06-0571640
                       (a Connecticut Corporation)
                       157 Church Street
                       New Haven, Connecticut 06506
                       Telephone: (203) 499-2000

          1-15995      UIL HOLDINGS CORPORATION                  06-1541045
                       (a Connecticut Corporation)
                       157 Church Street
                       New Haven, Connecticut 06506
                       Telephone: (203) 499-2000

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


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

                                    YES  X   NO
                                        ---    ---

     The  number of shares  outstanding  of the  issuer's  only  class of common
stock, as of June 30, 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 and
           six months ended June 30, 2000 and 1999.                          3
         Consolidated Balance Sheet as of June 30, 2000 and
           December 31, 1999.                                                4
         Consolidated Statement of Cash Flows for the three and
           six months ended June 30, 2000 and 1999.                          6

         Notes to Consolidated Financial Statements.                         7

           -   Statement of Accounting Policies                              7
           -   Capitalization                                                8
           -   Short-term Credit Arrangements                                9
           -   Income Taxes                                                 10
           -   Supplementary Information                                    11
           -   Commitments and Contingencies                                12
               -  Capital Expenditure Program                               12
               -  Nuclear Insurance Contingencies                           12
               -  Other Commitments and Contingencies                       12
                  - Connecticut Yankee                                      12
                  - Hydro-Quebec                                            13
                  - Environmental Concerns                                  13
                  - Site Decontamination, Demolition and Remediation Costs  13
           -   Nuclear Fuel Disposal and Nuclear Plant Decommissioning      14
           -   Segment Information                                          15

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

           -   Major Influences on Financial Condition                      16
           -   Capital Expenditure Program                                  19
           -   Liquidity and Capital Resources                              19
           -   Subsidiary Operations                                        21
           -   Results of Operations                                        21
           -   Looking Forward                                              28

Item 3.  Quantitative and Qualitative Disclosure About Market Risk.         30

                           PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.                                                 31

Item 4.  Submission of Matters to a Vote of Security Holders.               31

Item 6.  Exhibits and Reports on Form 8-K.                                  32

         SIGNATURES                                                         33


                                     - 2 -
<PAGE>
<TABLE>
                          PART I: FINANCIAL INFORMATION
                          ITEM I: FINANCIAL STATEMENTS
                         THE UNITED ILLUMINATING COMPANY
                        CONSOLIDATED STATEMENT OF INCOME
                      (THOUSANDS EXCEPT PER SHARE AMOUNTS)
                                   (UNAUDITED)

<CAPTION>
                                                                        Three Months Ended            Six Months Ended
                                                                             June 30,                     June 30,
                                                                        2000          1999           2000          1999
                                                                        ----          ----           ----          ----
<S>                                                                     <C>           <C>            <C>           <C>
OPERATING REVENUES (NOTE G)                                             $164,012      $164,533       $344,989      $333,200
                                                                     ------------  ------------   ------------  ------------
OPERATING EXPENSES
  Operation
     Fuel and energy                                                      72,870        38,483        140,339        72,382
     Capacity purchased                                                    1,457         8,678          2,904        17,740
     Other                                                                33,535        36,761         67,999        75,515
  Maintenance                                                              5,748         6,013         10,819        15,459
  Depreciation (Note G)                                                    7,127        15,618         14,246        33,357
  Amortization (deferral) of regulatory assets                            (9,211)        6,464          6,593        13,490
  Income taxes (Note F)                                                   15,692        15,851         28,898        31,376
  Other taxes (Note G)                                                    10,128        11,472         21,869        25,481
                                                                     ------------  ------------   ------------  ------------
       Total                                                             137,346       139,340        293,667       284,800
                                                                     ------------  ------------   ------------  ------------
OPERATING INCOME                                                          26,666        25,193         51,322        48,400
                                                                     ------------  ------------   ------------  ------------
OTHER INCOME AND (DEDUCTIONS)
  Allowance for equity funds used during construction                        244           254            425           267
  Other-net (Note G)                                                        (709)       (2,380)         1,693        (2,849)
  Non-operating income taxes  (Note F)                                     1,574         1,748            934         2,639
                                                                     ------------  ------------   ------------  ------------
       Total                                                               1,109          (378)         3,052            57
                                                                     ------------  ------------   ------------  ------------
INCOME BEFORE INTEREST CHARGES                                            27,775        24,815         54,374        48,457
                                                                     ------------  ------------   ------------  ------------
INTEREST CHARGES
  Interest on long-term debt                                               9,513        10,163         19,119        22,390
  Interest on Seabrook obligation bonds owned by the company              (1,617)       (1,711)        (3,235)       (3,422)
  Dividend requirement of mandatorily redeemable securities                1,203         1,203          2,406         2,406
  Other interest (Note G)                                                    635           820          1,026         2,676
  Allowance for borrowed funds used during construction                     (331)         (323)          (742)         (771)
                                                                     ------------  ------------   ------------  ------------
                                                                           9,403        10,152         18,574        23,279
  Amortization of debt expense and redemption premiums                       576           677          1,139         1,291
                                                                     ------------  ------------   ------------  ------------
       Net Interest Charges                                                9,979        10,829         19,713        24,570
                                                                     ------------  ------------   ------------  ------------


NET INCOME                                                                17,796        13,986         34,661        23,887
Premium on preferred stock redemptions                                         -            53              -            53
Dividends on preferred stock                                                   -            15              -            66
                                                                     ------------  ------------   ------------  ------------
INCOME APPLICABLE TO COMMON STOCK                                        $17,796       $13,918        $34,661       $23,768
                                                                     ============  ============   ============  ============

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC                       14,076        14,049         14,073        14,045
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED                     14,079        14,050         14,075        14,047

EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED                     $1.26         $0.99          $2.46         $1.69

CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK                          $0.72         $0.72          $1.44         $1.44
</TABLE>


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


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

                                     ASSETS
                             (Thousands of Dollars)

                                                   June 30,        December 31,
                                                     2000              1999*
                                                     ----              -----
                                                 (Unaudited)
Utility Plant at Original Cost
  In service                                         $933,194        $1,007,065
  Less, accumulated provision for depreciation        467,627           532,409
                                                 -------------    --------------
                                                      465,567           474,656

Construction work in progress                          29,128            25,708
Nuclear fuel                                           24,157            21,101
                                                 -------------    --------------
     Net Utility Plant                                518,852           521,465
                                                 -------------    --------------


Other Property and Investments
   Investment in generation facility                   91,361            83,494
   Nuclear decommissioning trust fund assets           31,265            28,255
   Other                                               15,735            20,098
                                                 -------------    --------------
                                                      138,361           131,847
                                                 -------------    --------------


Current Assets
  Unrestricted cash and temporary cash investments      5,330            39,099
   Restricted cash                                     26,615            29,223
  Accounts receivable
   Customers, less allowance for doubtful
     accounts of $1,500 and $1,800                     56,329            56,057
   Other, less allowance for doubtful accounts
     of $709 and $508                                  77,986            53,612
  Accrued utility revenues                             23,327            25,019
  Fuel, materials and supplies, at average cost         9,682             9,259
  Prepayments                                           3,453             3,056
  Other                                                 7,068             4,801
                                                 -------------    --------------
     Total                                            209,790           220,126
                                                 -------------    --------------

Deferred Charges
  Goodwill                                             15,181             4,827
  Unamortized debt issuance expenses                    7,760             8,688
  Other                                                   613             1,272
                                                 -------------    --------------
     Total                                             23,554            14,787
                                                 -------------    --------------

Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
                   THROUGH THE RATEMAKING PROCESS)
  Nuclear plant investments-above market              508,029           518,268
  Income taxes due principally to book-tax
    differences                                       160,221           166,965
  Long-term purchase power contracts-above market     136,367           144,406
  Connecticut Yankee                                   34,125            37,013
  Unamortized redemption costs                         22,855            22,314
  Unamortized cancelled nuclear projects                8,194             8,780
  Displaced worker protection costs                     4,585             5,746
  Uranium enrichment decommissioning cost               1,011             1,040
  Other                                                31,018             5,453
                                                 -------------    --------------
     Total                                            906,405           909,985
                                                 -------------    --------------

                                                   $1,796,962        $1,798,210
                                                 =============    ==============
*Derived from audited financial statements

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


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

                         CAPITALIZATION AND LIABILITIES
                             (Thousands of Dollars)

<CAPTION>
                                                                   June 30,         December 31,
                                                                     2000              1999*
                                                                     ----              -----

                                                                 (Unaudited)
<S>                                                                  <C>                <C>
Capitalization (Note B)
  Common stock equity
    Common stock                                                      $292,006           $292,006
    Paid-in capital                                                      2,344              2,253
    Capital stock expense                                               (2,170)            (2,170)
    Unearned employee stock ownership plan equity                       (8,785)            (9,261)
    Retained earnings                                                  189,866            175,470
                                                                ---------------    ---------------
                                                                       473,261            458,298
  Company-obligated mandatorily redeemable securities of
   subsidiary holding solely parent company debentures                  50,000             50,000
  Long-term debt
    Long-term debt                                                     604,819            605,641
    Investment in Seabrook obligation bonds                            (82,635)           (87,413)
                                                                ---------------    ---------------
      Net long-term debt                                               522,184            518,228
                                                                ---------------    ---------------

          Total                                                      1,045,445          1,026,526
                                                                ---------------    ---------------

Noncurrent Liabilities
  Purchase power contract obligation                                   136,365            144,406
  Nuclear decommissioning obligation                                    31,265             28,255
  Connecticut Yankee contract obligation                                23,925             27,056
  Pensions accrued                                                      11,196             19,026
  Obligations under capital leases                                      15,932             16,131
  Other                                                                 10,689             10,394
                                                                ---------------    ---------------
          Total                                                        229,372            245,268
                                                                ---------------    ---------------

Current Liabilities
  Current portion of long-term debt                                        859             25,000
  Notes payable                                                         14,262             17,131
  Accounts payable                                                      36,203             49,069
  Accounts payable - APS customers                                      59,105             56,220
  Dividends payable                                                     10,135             10,125
  Taxes accrued                                                         12,488              2,570
  Interest accrued                                                      16,204              8,433
  Obligations under capital leases                                         390                375
  Other accrued liabilities                                             55,928             39,421
                                                                ---------------    ---------------
          Total                                                        205,574            208,344
                                                                ---------------    ---------------

Customers' Advances for Construction                                     1,872              1,867
                                                                ---------------    ---------------

Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
                        THROUGH THE RATEMAKING PROCESS)
  Accumulated deferred investment tax credits                           14,984             15,157
  Deferred gains on sale of property                                    15,901             15,901
  Customer refund                                                       12,640             18,381
  Other                                                                  3,623              2,543
                                                                ---------------    ---------------
          Total                                                         47,148             51,982
                                                                ---------------    ---------------

Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
                       TO TAXING AUTHORITIES)                          267,551            264,223
Commitments and Contingencies (Note L)
                                                                ---------------    ---------------
                                                                    $1,796,962         $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          Six Months Ended
                                                                      June 30,                    June 30,
                                                                 2000          1999          2000          1999
                                                                 ----          ----          ----          ----
<S>                                                              <C>          <C>           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                                     $17,796       $13,986       $34,661       $23,887
                                                            -------------  ------------  ------------  ------------
  Adjustments to reconcile net income
     to net cash provided by operating activities:
     Depreciation and amortization                                17,024        19,252        33,626        41,718
     Deferred income taxes                                           211         4,547         5,626         3,815
     Deferred income taxes - generation asset sale                     -       (70,222)            -       (70,222)
     Deferred investment tax credits - net                           (86)         (191)         (173)         (381)
     Amortization of nuclear fuel                                  1,903         1,489         3,793         4,680
     Allowance for funds used during construction                   (575)         (577)       (1,167)       (1,038)
     CTA and SBC expense deferral                                (15,488)            -       (25,016)            -
     Amortization of deferred return                                   -         3,146             -         6,293
     Changes in:
            Accounts receivable - net                            (18,296)        2,532       (24,646)       15,344
            Fuel, materials and supplies                              72           639          (423)          212
            Prepayments                                            2,747         8,806          (397)        3,762
            Accounts payable                                        (476)       12,509        (9,981)      (21,671)
            Interest accrued                                       3,938         2,508         7,771         6,413
            Taxes accrued                                          1,248        (9,615)        9,918         4,810
            Taxes accrued - generation asset sale                      -        35,111             -        35,111
            Other assets and liabilities                          (6,060)      (26,915)       (3,560)      (36,733)
                                                            -------------  ------------  ------------  ------------
     Total Adjustments                                           (13,838)      (16,981)       (4,629)       (7,887)
                                                            -------------  ------------  ------------  ------------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES                3,958        (2,995)       30,032        16,000
                                                            -------------  ------------  ------------  ------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Common stock                                                      262           269           566           569
   Notes payable                                                     141       (33,488)       (2,869)      (38,208)
   Securities redeemed and retired:
     Preferred stock                                                   -        (4,299)            -        (4,299)
     Long-term debt                                                    -      (125,000)      (25,750)     (211,202)
   Premium on preferred stock redemptions                              -           (53)            -           (53)
   Lease obligations                                                 (93)          (86)         (184)         (171)
   Dividends
     Preferred stock                                                   -           (65)            -          (116)
     Common stock                                                (10,130)      (10,111)      (20,255)      (20,215)
                                                            -------------  ------------  ------------  ------------
NET CASH USED IN FINANCING ACTIVITIES                             (9,820)     (172,833)      (48,492)     (273,695)
                                                            -------------  ------------  ------------  ------------

CASH FLOWS FROM INVESTING ACTIVITIES
    Investment in unregulated businesses                               -       (75,092)            -       (75,092)
    Net cash received from sale of generation assets                   -       270,590             -       270,590
    Plant expenditures, including nuclear fuel                   (13,063)      (10,742)      (22,695)      (16,526)
    Investment in debt securities                                      -             -         4,778         5,447
                                                            -------------  ------------  ------------  ------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES              (13,063)      184,756       (17,917)      184,419
                                                            -------------  ------------  ------------  ------------

CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD                                        (18,925)        8,928       (36,377)      (73,276)
BALANCE AT BEGINNING OF PERIOD                                    50,870        42,297        68,322       124,501
                                                            -------------  ------------  ------------  ------------
BALANCE AT END OF PERIOD                                          31,945        51,225        31,945        51,225
LESS: RESTRICTED CASH                                             26,615        28,045        26,615        28,045
                                                            -------------  ------------  ------------  ------------
BALANCE: UNRESTRICTED CASH                                        $5,330       $23,180        $5,330       $23,180
                                                            =============  ============  ============  ============
CASH PAID DURING THE PERIOD FOR:
   Interest (net of amount capitalized)                           $5,951        $8,177        $8,559       $14,483
                                                            =============  ============  ============  ============
   Income taxes                                                  $10,600       $54,250       $12,600       $57,950
                                                            =============  ============  ============  ============
</TABLE>

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


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


                                     - 6 -
<PAGE>


                         THE UNITED ILLUMINATING COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


HOLDING COMPANY FORMATION

     On July 20, 2000, the corporate  restructuring  of The United  Illuminating
Company (the Company) and its non-regulated  subsidiaries into a holding company
structure  was  completed.  In the holding  company  structure,  the Company has
become a wholly-owned subsidiary of UIL Holdings Corporation,  and each share of
the common stock of the Company has been  converted into a share of common stock
of UIL Holdings Corporation. All of the Company's interests in all of its direct
and indirect  non-regulated  subsidiaries  have been transferred to UIL Holdings
Corporation  and,  to the extent new  businesses  are  subsequently  acquired or
commenced, they will also be financed and owned by UIL Holdings Corporation.

BASIS OF PRESENTATION

     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 six months of 2000 and
1999 was 7.6% 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 $1,995,000 and $1,950,000 in the first six
months of 2000 and 1999, respectively,  into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 2000, the Company's  shares of
the trust fund balances,  which included accumulated earnings on the funds, were
$23.0  million  and $8.3  million  for  Seabrook  Unit 1 and  Millstone  Unit 3,
respectively.   These  fund  balances  are  included  in  "Other   Property  and
Investments"  and  the  accrued   decommissioning   obligation  is  included  in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.

COMPREHENSIVE INCOME

     Comprehensive  income  for the six months  ended June 30,  2000 and 1999 is
equal to net income as reported.




                                     - 7 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

 (B)  CAPITALIZATION

COMMON STOCK

     The  Company  had  14,334,922  shares of its  common  stock,  no par value,
outstanding  at June 30, 2000, of which 258,449 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 June 30,  2000.  No  options  were
exercised  during  the six  months  ended  June  30,  2000.  Effective  with the
formation of the holding  company  structure on July 20, 2000,  all  outstanding
options were converted  into options to purchase an equivalent  number of shares
of UIL Holdings Corporation common stock.

     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 June 30,  2000.  No options to purchase
shares of the  Company's  common stock can be exercised  without the approval of
the DPUC;  and, as of June 30, 2000,  the Company had not requested  approval by
the DPUC.  Effective with the formation of the holding company structure on July
20, 2000,  all  outstanding  options were  converted into options to purchase an
equivalent  number of shares of UIL  Holdings  Corporation  common  stock.  As a
result, no approval by the DPUC is required for the exercise of these options as
of that date.

     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 June 30,
2000,  258,449  shares,  with a fair  market  value of $11.3  million,  had been
purchased by the KSOP and had not been  committed to be released or allocated to
KSOP participants. On July 20, 2000, effective with the formation of the holding
company  structure,  shares held in  employees'  KSOP  accounts and  unallocated
shares held by the KSOP were converted  into shares of UIL Holdings  Corporation
common stock.

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
$131.7 million were free from such limitations at June 30, 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


                                     - 8 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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.

     On August 9, 2000,  the Company  initiated the  redemption  process for $50
million  of 9 5/8%  Preferred  Capital  Securities,  Series A, due  2025.  These
securities were issued by United Capital  Funding  Partnership L. P., a Delaware
limited partnership, in April 1995. The securities will be redeemed on September
25, 2000 at 100% of par value.

(E)  SHORT-TERM CREDIT ARRANGEMENTS

     The Company's $60 million  revolving credit agreement with a group of banks
was  terminated  on August 4, 2000.  As of June 30,  2000,  the  Company  had no
short-term borrowings outstanding under this facility.

     On August 4, 2000, UIL Holdings Corporation entered into a revolving credit
agreement with the same group of banks.  The borrowing limit of this facility is
$97.5 million.  The facility permits UIL Holdings Corporation to borrow funds at
a fluctuating  interest rate determined by the prime lending market in New York,
and also permits UIL Holdings  Corporation  to borrow money for fixed periods of
time specified by UIL Holdings Corporation 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 UIL Holdings  Corporation and its  subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to UIL
Holdings Corporation under this revolving credit agreement,  although borrowings
outstanding  at the time of such an  occurrence  would not then  become  due and
payable.

     On June 26, 2000, the Company entered into a Money Market Loan  arrangement
with  Chase  Manhattan  Bank.  This  is  an  uncommitted   short-term  borrowing
arrangement  under which Chase Manhattan Bank may make loans totaling up to $125
million to the Company for fixed maturities from one day up to six months. Chase
Securities,  Inc. acts as an agent and sells the loans to  investors.  The fixed
interest rates on the loans are determined  based on conditions in the financial
markets at the time of each loan.  As of June 30,  2000,  the  Company had loans
totaling $6.5 million outstanding under this arrangement.



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

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<CAPTION>
                                                                     Three Months Ended              Six Months Ended
(F) INCOME  TAXES                                                         June 30,                      June 30,
                                                                      2000           1999           2000           1999
                                                                      ----           ----           ----           ----
                                                                     (000's)       (000's)         (000's)       (000's)
<S>                                                                  <C>           <C>             <C>            <C>
Income tax expense consists of:

Income tax provisions:
  Current
              Federal                                                $11,333        $63,457        $18,195        $75,794
              State                                                    2,660         16,512          4,316         19,731
                                                                   ------------   ------------   ------------   ------------
                 Total current                                        13,993         79,969         22,511         95,525
                                                                   ------------   ------------   ------------   ------------
  Deferred
              Federal                                                    427        (51,490)         5,078        (51,644)
              State                                                     (216)       (14,185)           548        (14,763)
                                                                   ------------   ------------   ------------   ------------
                 Total deferred                                          211        (65,675)         5,626        (66,407)
                                                                   ------------   ------------   ------------   ------------

  Investment tax credits                                                 (86)          (191)          (173)          (381)
                                                                   ------------   ------------   ------------   ------------

     Total income tax expense                                        $14,118        $14,103        $27,964        $28,737
                                                                   ============   ============   ============   ============

Income tax components charged as follows:
  Operating expenses                                                 $15,692        $15,851        $28,898        $31,376
  Other income and deductions - net                                   (1,574)        (1,748)          (934)        (2,639)
                                                                   ------------   ------------   ------------   ------------

     Total income tax expense                                        $14,118        $14,103        $27,964        $28,737
                                                                   ============   ============   ============   ============


The following table details the components
 of the deferred income taxes:
     Tax gain on sale of generation assets                                 -       ($70,222)             -       ($70,222)
     Seabrook sale/leaseback transaction                              (1,998)        (2,082)        (3,995)        (4,164)
     Pension benefits                                                  1,547            580          3,095          2,105
     Accelerated depreciation                                           (352)         1,250           (705)         2,500
     Tax depreciation on unrecoverable plant investment                   23          1,186             46          2,374
     Unit overhaul and replacement power costs                          (455)         3,116           (909)         2,218
     Conservation and load management                                    (26)          (872)           (53)        (1,745)
     Postretirement benefits                                             (92)          (265)          (184)          (698)
     Loss from disposition of property                                (1,420)             -         (1,420)             -
     Displaced worker protection costs                                  (228)         2,215           (463)         2,215
     Bond redemption costs                                              (257)          (252)           (73)          (508)
     Cancelled nuclear plant                                            (116)          (116)          (233)          (233)
     Restructuring costs                                                 335              -          2,665              -
     SBC and CTA expense deferral                                      6,176              -          9,975              -
     Other - net                                                      (2,926)          (213)        (2,120)          (249)
                                                                   ------------   ------------   ------------   ------------

Deferred income taxes - net                                             $211       ($65,675)       $ 5,626       ($66,407)
                                                                   ============   ============   ============   ============
</TABLE>


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

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(G)  SUPPLEMENTARY INFORMATION


<CAPTION>
                                                              Three Months Ended             Six Months Ended
                                                                    June 30,                      June 30,
                                                             2000          1999            2000           1999
                                                             ----          ----            ----           ----
                                                            (000's)       (000's)         (000's)       (000's)

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

     Retail                                                  $148,728      $155,538        $297,669       $307,929
     Wholesale                                                 19,958         5,676          38,572         19,269
     Other                                                     (4,674)        3,319           8,748          6,002
                                                         ------------- -------------   -------------  -------------
          Total Operating Revenues                           $164,012      $164,533        $344,989       $333,200
                                                         ============= =============   =============  =============

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

    Retail
     Residential                                              471,211       443,304       1,008,293        977,072
     Commercial                                               575,849       591,114       1,150,621      1,144,912
     Industrial                                               294,177       292,199         571,196        561,259
     Other                                                     10,175        11,850          23,500         24,049
                                                         ------------- -------------   -------------  -------------
                                                            1,351,412     1,338,467       2,753,610      2,707,292
    Wholesale                                                 644,291       205,837       1,269,296        858,583
                                                         ------------- -------------   -------------  -------------
          Total Sales by Class                              1,995,703     1,544,304       4,022,906      3,565,875
                                                         ============= =============   =============  =============


Depreciation
------------
    Plant in Service                                           $6,130       $11,916         $12,251        $26,571
    Amortization of Conservation and
            Load Management Costs                                   -         2,418               -          4,836
    Nuclear Decommissioning                                       997         1,284           1,995          1,950
                                                         ------------- -------------   -------------  -------------
                                                               $7,127       $15,618         $14,246        $33,357
                                                         ============= =============   =============  =============
Other Taxes
-----------

    Charged to:
     Operating:
        State gross earnings                                   $5,167        $5,898         $11,555        $11,752
        Local real estate and personal property                 3,805         4,349           7,654         10,675
        Payroll taxes                                           1,156         1,225           2,660          3,054
                                                         ------------- -------------   -------------  -------------
                                                               10,128        11,472          21,869         25,481
     Nonoperating and other accounts                              159           158             279            292
                                                         ------------- -------------   -------------  -------------
          Total Other Taxes                                   $10,287       $11,630         $22,148        $25,773
                                                         ============= =============   =============  =============

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

     Interest income                                             $324          $462            $611         $1,129
     Equity earnings from Connecticut Yankee                       94           143             243            324
     Earnings (Loss) from subsidiary companies-before tax       2,614        (2,314)          4,824         (3,520)
     Miscellaneous other income and (deductions) - net         (3,741)         (671)         (3,985)          (782)
                                                         ------------- -------------   -------------  -------------
          Total Other Income and (Deductions) - net             ($709)      ($2,380)         $1,693        ($2,849)
                                                         ============= =============   =============  =============

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

     Notes Payable                                               $203          $359            $515         $1,643
     Other                                                        432           461             511          1,033
                                                         ------------- -------------   -------------  -------------
          Total Other Interest Charges                           $635          $820          $1,026         $2,676
                                                         ============= =============   =============  =============
</TABLE>


                                     - 11 -
<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 $277.6 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


                                     - 12 -
<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). This agreement was submitted to the FERC, which approved it in
all respects on July 26, 2000;  and it became  effective on August 1, 2000.  The
agreement  allows  Connecticut  Yankee  to earn a  return  on  equity  of 6% and
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.

     The Company's  estimate of its remaining share of Connecticut Yankee costs,
including  decommissioning,  less  return  of  investment  (approximately  $10.2
million) and return on investment (approximately $3.6 million) at June 30, 2000,
is  approximately  $23.9  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 June 30, 2000,  the Company's
guarantee liability for this debt was approximately $5.9 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 June 30, 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 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.



                                     - 13 -
<PAGE>

                         THE UNITED ILLUMINATING COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     The Company has been  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.  The  excavation  of
contaminated soils and post-remediation monitoring is complete. 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. The Connecticut Department of Public Utility Control and
the Federal  Energy  Regulatory  Commission  have issued  orders  approving  the
transaction  and it is expected to close when these orders have become final. If
the site is  conveyed  to QE,  the  Company  will fund 61%  (approximately  $1.2
million) 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  closed on the sale of its  Bridgeport  Harbor  Station and New
Haven Harbor Station generating plants in compliance with Connecticut's electric
utility  industry  restructuring  legislation  on April 16, 1999.  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 six months of 2000 was $1.7 million.  The Company's  share
of the fund at June 30, 2000 was approximately $23.0 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  six  months  of 2000 was $0.3  million.  The
Company's share of the fund at June 30, 2000 was approximately $8.3 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 June 30, 2000,  $196 million has
been expended for decommissioning.  The projected remaining decommissioning cost
is $302  million,  of  which  the  Company's  share  would be $29  million.  The
decommissioning  trust fund for the  Connecticut  Yankee Unit is also managed by
NU.  For  the   Company's   9.5%  equity   ownership  in   Connecticut   Yankee,
decommissioning  costs of $1.2  million  were funded by the  Company  during the
first six months of 2000,  and the Company's  share of the fund at June 30, 2000
was $18.7 million.



                                     - 14 -
<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 June 30, 2000
and December 31, 1999:

                                                   JUNE 30,        DECEMBER 31,
                                                    2000              1999
                                                    ----              ----
                                                            (000's)
   Total Assets - Regulated Utility              $1,781,132         $1,809,451
   Total Assets - Non-regulated Subsidiaries        222,502            194,642
   Total Assets - Elimination                      (206,672)          (205,883)
                                                  ---------          ---------
   Total Consolidated Assets                     $1,796,962         $1,798,210
                                                  =========          =========




                                     - 15 -
<PAGE>




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

                     MAJOR INFLUENCES ON FINANCIAL CONDITION

     The  Company's  financial  condition  will  continue to be dependent on the
level of its 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


                                     - 16 -
<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  participating  in an auction  process for all
three  of the  generating  units  at  Millstone  Station  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 was concluded on August 7, 2000 when
the DPUC and J. P. Morgan & Co.  announced  that  Dominion  Resources,  Inc. had
agreed to purchase  Millstone  Units 1 and 2, and 93.47% of Millstone Unit 3 for
$1.298  billion.  The  purchase  price  agreed  to for the  Company's  ownership
interest  in Unit 3,  which is  subject  to  adjustments  for  expenditures  and
eventualities  prior to the date of closing on the sale,  is  approximately  $31
million,  exclusive of nuclear fuel.  The  Company's  share of the payment to be
made for the projected nuclear fuel inventory at the date of closing on the sale
is approximately  $2.5 million.  It is currently  estimated that obtaining other
requisite  regulatory approvals of the auction results and consummating the sale
may require an additional  eight months.  The  divestiture  process for Seabrook
Unit 1 has not yet been determined.

      The Company's  unbundling plan also proposed a corporate  restructuring to
separate its ongoing  regulated  transmission  and  distribution  operations and
functions, that is, the Distribution Company assets and operations,  from all of
its non-regulated  operations and activities.  In a decision dated May 19, 1999,
the DPUC  approved  the  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 corporate  restructuring;  and on July 19,
2000, the Nuclear Regulatory Commission authorized the corporate  restructuring.
On  July  20,  2000,  the  corporate   restructuring  of  the  Company  and  its
non-regulated  subsidiaries into a holding company  structure was completed.  In
the holding company structure,  the Company has become a wholly-owned subsidiary
of UIL Holdings  Corporation,  and each share of the common stock of the Company
has been converted into a share of common stock of UIL Holdings Corporation. All
of the  Company's  interests  in all of its  direct and  indirect  non-regulated
subsidiaries  have been  transferred  to UIL  Holdings  Corporation  and, to the
extent new businesses are subsequently acquired or commenced,  they will also be
financed and owned by UIL Holdings Corporation.

      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 Company has  amortized  less than the expected  level of  regulatory  assets
related to  stranded  costs  during the first six months of 2000,  due to timing
differences and higher than anticipated costs associated with providing standard
offer service to  customers.  Since  stranded  costs are intended to be trued-up
annually,  the Company continues to anticipate  recovery through the competitive
transition  assessment of these  unamortized  costs.  The Connecticut


                                     - 17 -
<PAGE>

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.  This settlement  agreement was approved by the DPUC
on July 5, 2000; and the Office of Consumer  Counsel's Superior Court appeal has
been withdrawn.

      Under the Restructuring  Act, effective July 1, 2000, all of the Company's
customers are able to choose their power supply providers.  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.




                                     - 18 -
<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)                  $ 2,930      $ 2,855      $  -        $  -         $  -         $  5,785
Distribution and Transmission            44,520       37,386       20,313      16,395       32,496       151,110
                                        -------       ------       ------      ------       ------       -------
Subtotal                                 47,450       40,241       20,313      16,395       32,496       156,895

Nuclear Fuel                             11,167        6,962        2,837       8,274         -           29,240
                                        -------       ------       ------      ------       ------       -------

Total Utility Expenditures               58,617       47,203       23,150      24,669       32,496       186,135

Total Non-Regulated Business
  Expenditures                           64,679       14,309        3,749       4,323        4,452        91,512
                                        -------       ------       ------      ------       ------       -------

   Total                               $123,296      $61,512      $26,899     $28,992      $36,948      $277,647
                                       ========      =======      =======     =======      =======      ========
</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 June 30, 2000,  the Company had $31.9 million of cash and temporary cash
investments,  a decrease  of $36.4  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                  30.0

       Net cash provided by (used in) financing activities:
       -   Financing activities, excluding dividend payments     (28.2)
       -   Dividend payments                                     (20.3)
       Investment in debt securities                               4.8
       Cash invested in plant, including nuclear fuel            (22.7)
                                                                 ------

             Net Change in Cash                                  (36.4)
                                                                 ------

       Balance, June 30, 2000                                    $31.9
                                                                 =====


                                     - 19 -
<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)                   74.9       91.5       95.0       89.9       94.2
                                                                -----       ----       ----       ----       ----
         Subtotal                                               114.0       91.5       95.0       89.9       94.2

Less:
Utility Capital Expenditures (excluding Nuclear Fuel)  (2)       47.4       40.2       20.3       16.4       32.5
Utility Nuclear Fuel Expenditures  (2)                           11.2        7.0        2.8        8.3        -
Non-Regulated Business Capital Expenditures  (2)                 64.7       14.3        3.7        4.3        4.5
                                                                -----      -----       ----       ----       ----
         Total                                                  123.3       61.5       26.8       29.0       37.0

Cash Available to pay Debt Maturities and Redemptions            (9.3)      30.0       68.2       60.9       57.2

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)                 $101.3     $(30.0)     $31.8      $39.1     $(57.2)
                                                                =====      =====       ====       ====      =====
</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  capital  requirements  that  exceed  available  cash  will  have to be
provided by external financing.  Although there is no commitment to provide such
financing from any source of funds,  other than a $97.5 million revolving credit
agreement with a group of banks,  described  below,  future  external  financing
needs are expected to be satisfied by the issuance of 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 future income and cash flow.

     The Company's $60 million  revolving credit agreement with a group of banks
was  terminated  on August 4, 2000.  As of June 30,  2000,  the  Company  had no
short-term borrowings outstanding under this facility.

     On August 4, 2000, UIL Holdings Corporation entered into a revolving credit
agreement with the same group of banks.  The borrowing limit of this facility is
$97.5 million.  The facility permits UIL Holdings Corporation to borrow funds at
a fluctuating  interest rate determined by the prime lending market in New York,
and also permits UIL Holdings  Corporation  to borrow money for fixed periods of
time specified by UIL Holdings Corporation 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 UIL Holdings  Corporation and its  subsidiaries,  on a consolidated
basis,  should  occur,  the banks may  decline to lend  additional  money to UIL
Holdings Corporation under this revolving credit agreement,  although borrowings
outstanding  at the time of such an  occurrence  would not then  become  due and
payable.

     On June 26, 2000, the Company entered into a Money Market Loan  arrangement
with  Chase  Manhattan  Bank.  This  is  an  uncommitted   short-term  borrowing
arrangement  under which Chase Manhattan Bank may make loans


                                     - 20 -
<PAGE>

totaling up to $125 million to the Company for fixed  maturities from one day up
to six months.  Chase  Securities,  Inc. acts as an agent and sells the loans to
investors.  The  fixed  interest  rates on the  loans  are  determined  based on
conditions  in the  financial  markets at the time of each loan.  As of June 30,
2000,  the  Company  had loans  totaling  $6.5  million  outstanding  under this
arrangement.

                              SUBSIDIARY OPERATIONS

     United Resources,  Inc. (URI), serves as the parent corporation for several
non-regulated   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.  On July 20, 2000, the corporate  restructuring  of the Company and
its  non-regulated  subsidiaries into a holding company structure was completed.
In the  holding  company  structure,  the  Company  has  become  a  wholly-owned
subsidiary of UIL Holdings  Corporation,  and the Company's interests in URI and
all of its direct and indirect non-regulated  subsidiaries have been transferred
to UIL Holdings Corporation.

     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,
Xcelecom,  Inc., and its subsidiaries,  provide electrical and  voice-data-video
design,  construction,  systems  integration  and  services to  customers in New
England and the neighboring Mid-Atlantic region. 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

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 quarters of 2000 and the quarters 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  in 2000 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.

SECOND QUARTER OF 2000 VS. SECOND QUARTER OF 1999
-------------------------------------------------

     Earnings for the second  quarter of 2000 were $17.8  million,  or $1.26 per
share (on both a basic and diluted basis),  up $3.9 million,  or $.27 per share,
from the second  quarter of 1999.  Excluding  a one-time  item  recorded  in the
second  quarter of 2000,  earnings from  operations (on both a basic and diluted
basis)  were  $19.9  million or $1.41 per share,  up $6.0  million,  or $.42 per
share,   from  the  second  quarter  of  1999.  The  earnings  from   operations
contribution of utility  operations,  excluding the Nuclear Division,  was $1.23
per share in the second quarter of 2000. The Nuclear  Division  contributed $.17
per share,  for a total  utility  contribution  of $1.40 per share,  compared to
$1.11 per share in the  second  quarter  of 1999.  The  Company's  non-regulated
businesses  earned $.01 per share in the second  quarter of 2000,  compared to a
loss of $.12 per share in the second quarter of 1999.

                                     - 21 -
<PAGE>


     The one-time item recorded in the second quarter of 2000 was:       EPS
   -------------------- --------------------------------------------- --------
   2000 Quarter 2       Impairment loss on property in North Haven    $ (.15)
   -------------------- --------------------------------------------- --------

     On June 14, 2000,  the  Connecticut  Department of Public  Utility  Control
approved a sale of property by the Company to  Souwestcon  Properties,  Inc., an
indirect  wholly-owned  subsidiary.  The  sale  price of the  property  was $1.2
million,  and the property had a book value of $4.7 million.  As a result of the
transaction,   the  Company  recognized  an  impairment  loss  of  $3.5  million
(before-tax) or $1.4 million (after-tax) in June 2000.

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

     Overall,  retail revenue decreased by $6.8 million in the second quarter of
2000 compared to the second quarter of 1999.

   ------------------------------------------------------------  ---------------
                                                                     Total From
                     Retail Revenues: $ millions                     Operations
   ------------------------------------------------------------  ---------------
   Revenue from:
   ------------------------------------------------------------  ---------------
     Estimate of operating Distribution Division component of
     "weather corrected" retail sales growth, up 1.1%                   0.6
   ------------------------------------------------------------  ---------------
     Estimate of operating Distribution Division component of
     weather effect on retail sales                                    (1.4)
   ------------------------------------------------------------  ---------------
     Estimate of operating Distribution Division component of
     price reduction                                                   (3.3)
   ------------------------------------------------------------  ---------------
     Other retail price reduction, mix of sales and other (see
     other operating revenues)                                         (2.7)
   ------------------------------------------------------------  ---------------
            TOTAL RETAIL REVENUE                                       (6.8)
   ------------------------------------------------------------  ---------------

     Retail fuel and energy  expense  increased  by $33.5  million in the second
quarter of 2000 compared to the second 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 $13.4 million in the second quarter of
2000 compared to the second quarter of 1999.  Margin from the Nuclear  Division,
which was incorporated in retail rates in 1999,  increased by $14.3 million. The
Company's operating nuclear assets, Seabrook Unit 1 and Millstone Unit 3, supply
power solely to the  wholesale  market in 2000.  Overall,  the Nuclear  Division
produced  earnings of $.17 per share in the second  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
wholesale sales margin of $0.9 million from general wholesale  activities in the
second quarter of 1999.

     Other operating revenues decreased by $8.0 million in the second quarter of
2000  compared  to  the  second  quarter  of  1999.  Accrued  revenues  for  the
Competitive  Transition  Assessment  (CTA) and the System  Benefits Charge (SBC)
decreased by $9.6 million in the second  quarter of 2000  compared to the second
quarter of 1999. See the paragraph on amortization  of regulatory  assets below,
and 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 $1.4 million in the second  quarter of 2000  compared to the
second  quarter of 1999,  and were mostly offset by an increase in  transmission
operation expense.



                                     - 22 -
<PAGE>

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
decreased by $10.7 million in the second  quarter of 2000 compared to the second
quarter of 1999. The principal components of these expense changes include:

                                                                      $millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Cogeneration  (see Note A)                                            (7.1)
--------------------------------------------------------------------- ----------
   Other purchases                                                       (0.1)
--------------------------------------------------------------------- ----------
          TOTAL CAPACITY EXPENSE                                         (7.2)
--------------------------------------------------------------------- ----------
 Operating Distribution Division O&M expense:
--------------------------------------------------------------------- ----------
   1999 fossil generation unit operating and maintenance costs           (1.4)
--------------------------------------------------------------------- ----------
   Pension and other employee benefit costs                              (2.3)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                            1.1
--------------------------------------------------------------------- ----------
   Other                                                                 (3.7)
--------------------------------------------------------------------- ----------
          TOTAL OPERATING DISTRIBUTION DIVISION                          (6.3)
--------------------------------------------------------------------- ----------
 Other unbundled components of O&M expense:
--------------------------------------------------------------------- ----------
   Nuclear Division (see Note B)                                         (1.3)
--------------------------------------------------------------------- ----------
   Conservation and Load Management and Renewable Energy
   (see note B)                                                           4.1
--------------------------------------------------------------------- ----------
          TOTAL OTHER COMPONENTS                                          2.8
--------------------------------------------------------------------- ----------
          TOTAL O&M EXPENSE                                             (10.7)
--------------------------------------------------------------------- ----------

               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 second  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 $1.0 million
               of the  reduction  was due to the absence,  in 2000, of refueling
               outage costs incurred in the second 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 $0.6 million in the
second quarter of 2000 compared to the second  quarter of 1999, due  principally
to the generating plant sale in April of 1999.

     Depreciation  expense  decreased by $8.5  million in the second  quarter of
2000 compared to the second 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 $0.4 million was due to the generation asset
sale in 1999. Other depreciation expenses decreased by $0.6 million.

     Amortization of regulatory  assets decreased by $15.7 million in the second
quarter of 2000 compared to the second 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  paragraph.  The CTA and
SBC  amortization


                                     - 23 -
<PAGE>

components in the second quarter of 2000 amounted to $12.8 million (pre-tax) and
were: nuclear assets (from 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.   However,  because  the  result  of  these
amortizations  produced  returns on both the CTA and SBC below the 11.5%  return
allowed,  about $24.9 million  (before-tax) of amortization was deferred for the
second  quarter of 2000,  including  about $8.9  million  (before-tax)  that was
offset by the other operating  accrued revenue  decrease  mentioned  above.  The
elimination  (completed in 1999) of $3.1 million  (after-tax) of amortization of
Seabrook  Nuclear Station deferred return also reduced  amortization  expense in
the second quarter of 2000 compared to the second quarter of 1999.

     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 second quarter of 2000,  compared to about $3.0 million (after-tax) in 1999,
for a decrease of $0.8 million.

     Interest charges for the regulated  business continued on a downward trend,
decreasing by $2.5 million in the second  quarter of 2000 compared to the second
quarter of 1999,  partly  offset by an  increase  of $1.7  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  $0.2 million,  or $.01 per share,  in the second  quarter
2000, compared to losses of about $1.7 million, or $.12 per share, in the second
quarter of 1999.

     The results of each of the  subsidiaries  of URI for the second  quarter of
2000  reflect 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. earned
approximately  $0.6 million,  or $.04 per share,  in the second quarter of 2000,
reflecting  an  increase  of $0.4  million,  or $.03 per share,  over the second
quarter of 1999.  Xcelecom,  Inc. earned approximately $0.2 million, or $.01 per
share, in the second quarter of 2000,  compared to a loss of approximately  $1.2
million,  or $.08 per share,  in the second quarter of 1999. The improvement was
the result of cost reduction  efforts and the acquisitions of the Allan Electric
Co., Inc. and the DataStore Incorporated.

     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 $0.1
million, or $.01 per share, in the second quarter of 2000, compared to a loss of
about $0.6 million, or $.05 per share, in the second quarter of 1999. The second
quarter  2000 loss was the result of a shutdown to repair the steam  turbine and
to make modifications to the combustion turbine. These repairs and modifications
were  partly  completed  in June and partial  service was resumed in June.  Full
service  was resumed in  mid-July.  United  Capital  Investments,  Inc.  did not
contribute  significantly  to earnings in either second  quarter.  The remaining
non-regulated  businesses loss of $.03 per share


                                     - 24 -
<PAGE>

comparing  the  second  quarter  of 2000 to the  second  quarter of 1999 was the
result of higher interest charges at the parent URI.

FIRST SIX MONTHS OF 2000 VS. FIRST SIX MONTHS OF 1999
-----------------------------------------------------

     Earnings for the first six months of 2000 were $34.7 million,  or $2.46 per
share (on both a basic and diluted basis), up $10.9 million,  or $.77 per share,
from the first six months of 1999.  Excluding  one-time  items  recorded in both
periods,  earnings from  operations  (on both a basic and diluted basis) were up
$13.6  million,  or $.96 per  share,  from the  first six  months  of 1999.  The
earnings  from  operations  contribution  of utility  operations,  excluding the
Nuclear  Division,  was $2.20 per  share in the  first six  months of 2000.  The
Nuclear Division contributed $.39 per share, for a total utility contribution of
$2.59 per  share,  compared  to $1.86 per share in the first six months of 1999.
The Company's  non-regulated  businesses  earned $.02 per share in the first six
months of 2000,  compared to a loss of $.17 per share in the first six months of
1999.

     The one-time item recorded in the first six months of 2000 was:     EPS
-------------------- ------------------------------------------------ ----------
   2000 Quarter 2       Impairment loss on property in North Haven     $(.15)
-------------------- ------------------------------------------------ ----------

     The one-time item recorded in the first six months 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 $10.3 million in the first six months
of 2000 compared to the first six months 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                                     -             1.0         1.0
   ---------------------------------------------------------------- ------------ ------------- -----------
     Estimate of  operating  Distribution  Division  component  of
     "real" retail sales growth, up 1.2%                                1.3             -          1.3
   ---------------------------------------------------------------- ------------ ------------- -----------
     Estimate of  operating  Distribution  Division  component  of
     "leap year day" retail sales growth, up 0.6%                       0.6             -          0.6
   ---------------------------------------------------------------- ------------ ------------- -----------
     Estimate of  operating  Distribution  Division  component  of
     weather effect on retail sales                                    (0.3)            -         (0.3)
   ---------------------------------------------------------------- ------------ ------------- -----------
     Estimate of  operating  Distribution  Division  component  of
     price reduction                                                   (6.3)            -         (6.3)
   ---------------------------------------------------------------- ------------ ------------- -----------
     Other  retail  price  reduction,  mix of sales and other (see
     other operating revenues)                                         (6.6)            -         (6.6)
   ---------------------------------------------------------------- ------------ ------------- -----------
            TOTAL RETAIL REVENUE                                      (11.3)           1.0       (10.3)
   ---------------------------------------------------------------- ------------ ------------- -----------
</TABLE>

     Retail fuel and energy expense  increased by $73.1 million in the first six
months of 2000 compared to the first six months 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 $27.1 million in the first six months
of 2000  compared  to the first  six  months of 1999.  Margin  from the  Nuclear
Division,  which was  incorporated  in retail rates in 1999,  increased by $28.5
million.  The Company's operating nuclear assets,  Seabrook Unit 1 and Millstone
Unit 3, supply power solely

                                     - 25 -
<PAGE>

to the wholesale market in 2000. Overall, the Nuclear Division produced earnings
of $.39 per share in the first six  months  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 $1.4
million from general wholesale activities in the first six months of 1999.

     Other operating  revenues increased by $2.7 million in the first six months
of 2000  compared  to the first six  months of 1999.  Other  operating  revenues
include  transmission  revenues from the New England Power Pool (NEPOOL),  which
increased by $2.7 million in the first six months of 2000  compared to the first
six  months of 1999,  and were  mostly  offset by an  increase  in  transmission
operation expense.

     Operating  expenses for  operations,  maintenance  and  purchased  capacity
decreased by $27.0 million in the first six months of 2000 compared to the first
six months of 1999. The principal components of these expense changes include:

                                                                      $millions
--------------------------------------------------------------------- ----------
 Capacity expense:
--------------------------------------------------------------------- ----------
   Cogeneration  (see Note A)                                           (14.1)
--------------------------------------------------------------------- ----------
   Other purchases                                                       (0.7)
--------------------------------------------------------------------- ----------
           TOTAL CAPACITY EXPENSE                                       (14.8)
--------------------------------------------------------------------- ----------
 Operating Distribution Division O&M expense:
--------------------------------------------------------------------- ----------
   1999 fossil generation unit operating and maintenance costs           (7.1)
--------------------------------------------------------------------- ----------
   Pension and other employee benefit costs                              (5.0)
--------------------------------------------------------------------- ----------
   NEPOOL transmission expense                                            1.9
--------------------------------------------------------------------- ----------
   Other                                                                 (8.3)
--------------------------------------------------------------------- ----------
           TOTAL OPERATING DISTRIBUTION DIVISION                        (18.5)
--------------------------------------------------------------------- ----------
 Other unbundled components of O&M expense:
--------------------------------------------------------------------- ----------
   Nuclear Division (see Note B)                                         (3.5)
--------------------------------------------------------------------- ----------
   Conservation  and Load  Management,  Renewable  Energy  and  System
   Benefits (see note B)                                                  9.8
--------------------------------------------------------------------- ----------
           TOTAL OTHER COMPONENTS                                         6.3
--------------------------------------------------------------------- ----------
           TOTAL O&M EXPENSE                                            (27.0)
--------------------------------------------------------------------- ----------

               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 six months of 2000 of about  $13.3  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 $2.5 million
               of the reduction was due to the absence of refueling outage costs
               incurred in the first six months 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 $3.4 million in the
first  six  months  of 2000  compared  to the  first  six  months  of 1999,  due
principally to the generating plant sale in April of 1999.



                                     - 26 -
<PAGE>

     Depreciation  expense decreased by $19.1 million in the first six months of
2000  compared  to the first six  months of 1999.  About  $11.0  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
$4.8  million of the  decrease  was due to the  completion  of  depreciation  of
conservation  assets in the first half of 1999, and another $2.8 million was due
to the generation asset sale in 1999. Other  depreciation  expenses decreased by
$0.5 million.

     Amortization  of regulatory  assets  decreased by $6.9 million in the first
six  months  of 2000  compared  to the  first six  months  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 six months of
2000  amounted  to $25.7  million  (pre-tax)  and  were:  nuclear  assets  (from
depreciation)  $10.2 million,  purchased  power contracts (in place of purchased
power  expense) $13.3 million,  displaced  worker costs $1.3 million,  and other
$0.9  million.  However,  because  the  result of these  amortizations  produced
returns on both the CTA and SBC below the 11.5% return  allowed,  $25.0  million
(before-tax) of amortization  was deferred for the first six months of 2000. The
elimination  (completed in 1999) of $3.1 million  (after-tax) of amortization of
Seabrook  Nuclear Station deferred return also reduced  amortization  expense in
the first six months of 2000 compared to the first six months of 1999.

     The exceptions noted in the previous paragraph are amortizations that apply
to the operating Distribution Division.  They include the amortization of Retail
Access assets,  $0.9 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 $4.4 million (after-tax) of accelerated  amortization was charged in
the first six months of 2000,  compared  to about $6.0  million  (after-tax)  in
1999, for a decrease of $1.6 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  six  months  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 period.

     Interest charges for the regulated  business continued on a downward trend,
decreasing by $8.6 million in the first six months of 2000 compared to the first
six months of 1999,  partly  offset by an increase  of $3.7  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 $0.3 million, or $.02 per share, in the first six months of
2000,  compared to losses of about $2.4 million, or $.17 per share, in the first
six months of 1999.

     The results of each of the  subsidiaries of URI for the first six months 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


                                     - 27 -
<PAGE>

appropriate for that type of business.  American  Payment  Systems,  Inc. earned
approximately $1.3 million,  or $.09 per share, in the first six months of 2000,
reflecting  an increase of $1.0 million,  or $.07 per share,  over the first six
months of 1999.  Xcelecom,  Inc. lost  approximately  $0.2 million,  or $.01 per
share, in the first six months of 2000, compared to a loss of approximately $1.6
million, or $.12 per share, in the first six months of 1999. The improvement was
the result of cost reduction  efforts and the acquisitions of the Allan Electric
Co., Inc. and the DataStore Incorporated.

     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 $1.1
million,  or $.08 per share, in the first six months of 2000, compared to a loss
of about $0.6 million,  or $.05 per share,  in the first six months of 1999. The
2000 loss was the result of a shutdown  to repair the steam  turbine and to make
modifications to the combustion  turbine.  These repairs and modifications  were
partly  completed in June and partial  service was resumed in June. Full service
was resumed in mid-July.  United Capital Investments,  Inc. earned approximately
$1.0 million,  or $.07 per share, in the first six months of 2000, compared to a
loss of approximately  $0.4 million,  or $.03 per share, in the first six months
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.  The
remaining  non-regulated  businesses loss of $.06 per share comparing the second
quarter of 2000 to the second quarter of 1999 was the result of higher  interest
charges at the non-regulated parent URI.

                                 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.  Utility  earnings  will not likely ever exceed the sharing level
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  earnings in the third  quarter  that  exceed  that level and all  positive
utility earnings  recorded in the fourth quarter of that year will be subject to
"sharing."

                                     - 28 -
<PAGE>

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
enacted  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 at least 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 April 24, 2000, the Company estimated its year 2000 earnings would be in
the range of  $3.95-$4.10  per share.  Following  better than expected first and
second  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 $4.25-$4.35 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 and second
quarters  of 2000  would  produce  additional  earnings,  although  a  four-week
refueling  outage is scheduled for the Seabrook  nuclear  generating unit in the
fourth quarter of 2000.

     Sharing will be significantly reduced from the 1999 levels, due to mandates
in the restructuring  legislation.  The Company expects sharing to contribute no
more than $.30-$.35 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 the same level as
previously expected.  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 about $.05 per share.  Xcelecom,  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.  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


                                     - 29 -
<PAGE>

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
Unit 1 and  Millstone  Unit 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,  the  Seabrook  unit  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.

     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.

     The  Company's   current  overall  estimate  of  earnings  per  share  from
operations for 2000 is $4.25-$4.35 and the estimates of quarterly results are as
follows:

     Earnings per share from operations:
                                      Estimated               Actual
                   Quarter            2000 Range                1999
                   -------            ----------                ----
                      1               $1.20 (Actual)           $ .66
                      2               $1.41 (Actual)             .99
                      3               $1.10 - $1.25             1.78
                      4               $ .44 - $ .59              .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 same is true for the high range numbers.  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 $4.25-$4.35 per share.

A look at 2001; continued growth of non-regulated businesses value
------------------------------------------------------------------

     Currently,  the Company is  estimating  earnings for 2001 to be in the same
range  expected for 2000,  $4.25-$4.35  per share.  Continued  strong  growth is
forecast in the non-regulated businesses sector, which is expected to contribute
9-11 percent of total earnings for the year. About one-half of the non-regulated
businesses  earnings  should be contributed by Xcelecom,  Inc., with the balance
spread among the other URI subsidiaries.  The growth in the non-regulated sector
will be offset by a  reduction  of  regulated  business  earnings  in 2001.  The
largest single influence on the forecasted downturn in utility earnings for 2001
is  additional  scheduled  non-cash  amortization.  The  Company's  current  and
anticipated performance is underscored by its continuing strong cash flow.

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.



                                     - 30 -
<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 Part I, Item 2, "Properties - Nuclear  Generation" of the Company's
Annual  Report  (Form 10-K) for the fiscal year ended  December  31,  1999,  the
Company  and the two other  minority,  non-NU  joint  owners that  continued  to
prosecute  the  arbitration   proceeding  and  lawsuits   against  NU  following
settlements  by the seven other  minority,  non-NU  joint owners of their claims
against NU, have settled their claims against NU and stipulated to the dismissal
of all claims in the  arbitration  proceeding  and  lawsuits.  The July 24, 2000
settlement  agreement  between the Company and NU involves  the payment by NU to
the Company of approximately $15 million and certain  contingent  payments,  and
provided for the inclusion of the Company's  Millstone Unit 3 ownership interest
in NU's Millstone  Station  nuclear auction sale conducted by J. P. Morgan & Co.
pursuant to Connecticut's Restructuring Act.

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

     The Annual  Meeting of the  Shareowners of the Company was held on June 26,
2000,  for the purpose of electing a Board of Directors for the ensuing year and
voting on approval of the employment of  PricewaterhouseCoopers  LLP as the firm
of independent  public accountants to audit the books and affairs of the Company
for the fiscal year 2000.

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

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

       Thelma R. Albright                    12,524,540                 166,772
       Marc C. Breslawsky                    12,525,354                 165,957
       David E. A. Carson                    12,523,453                 167,858
       Arnold L. Chase                       12,518,955                 172,355
       John F. Croweak                       12,523,905                 167,407
       Robert L. Fiscus                      12,522,379                 168,934
       Betsy Henley-Cohn                     12,515,915                 175,398
       John L. Lahey                         12,522,300                 169,012
       F. Patrick McFadden, Jr.              12,523,844                 167,470
       Daniel J. Miglio                      12,514,398                 176,913
       James A. Thomas                       12,522,505                 168,806
       Nathaniel D. Woodson                  12,520,827                 170,486

     The  employment of  PricewaterhouseCoopers  LLP as the firm of  independent
public  accountants to audit the books and affairs of the Company for the fiscal
year 2000 was approved by the following vote:

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

                           12,544,129            60,397              86,782



                                     - 31 -
<PAGE>

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

     (a) Exhibits.

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

          <S>                    <C>          <C>
           (3)                    3.2a        Copy of Article III,  Section 2 of Bylaws of The United  Illuminating
                                              Company, amending Exhibit 3.2.*

          (10)                   10.2f        Copy of 2000  Amendatory  Agreement  between The United  Illuminating
                                              Company and Connecticut  Yankee Atomic Power Company,  dated July 28,
                                              2000, amending Exhibits 10.2b** and 10.2c***.

          (12), (99)             12           Statement Showing  Computation of Ratios of Earnings to Fixed Charges
                                              and Ratios of Earnings to Combined Fixed Charges and Preferred  Stock
                                              Dividend  Requirements (Twelve Months Ended June 30,  2000 and Twelve
                                              Months Ended December 31, 1999, 1998, 1997, 1996 and 1995).

          (21)                   21a          List of subsidiaries of The United Illuminating Company,  superseding
                                              Exhibit 21****.

          (27)                   27           Financial Data Schedule.

</TABLE>


*    Filed with Quarterly Report on Form 10-Q for fiscal quarter ended March 31,
     1999.
**   Filed with Annual Report on Form 10-K for fiscal year ended December 31,
     1995.
***  Filed with Annual Report on Form 10-K for fiscal year ended December 31,
     1996.
**** Filed with Annual Report on Form 10-K for fiscal year ended December 31,
     1999.


     (b) Reports on Form 8-K.

         None



                                     - 32 -
<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  08/14/2000            Signature          /s/ Robert L. Fiscus
    --------------                   -------------------------------------------
                                                   Robert L. Fiscus
                                        Vice Chairman of the Board of Directors
                                              and Chief Financial Officer



                                     - 33 -
<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.

                            UIL HOLDINGS CORPORATION




Date   08/14/2000            Signature         /s/ Robert L. Fiscus
    -----------------                 ------------------------------------------
                                                   Robert L. Fiscus
                                       Vice Chairman of the Board of Directors,
                                       Chief Financial Officer, Treasurer and
                                       Secretary



                                     - 34 -
<PAGE>