EXHIBIT 13.2
                               1996 Annual Report

            The Connecticut Light and Power Company and Subsidiaries

                                     Index


Contents                                                                  Page


Consolidated Balance Sheets.............................................  2-3

Consolidated Statements of Income.......................................   4

Consolidated Statements of Cash Flows...................................   5

Consolidated Statements of Common Stockholder's Equity..................   6

Notes to Consolidated Financial Statements..............................   7

Report of Independent Public Accountants................................   37

Management's Discussion and Analysis of Financial
  Condition and Results of Operations...................................   38

Selected Financial Data.................................................   50

Statements of Quarterly Financial Data..................................   50

Statistics..............................................................   51



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------
At December 31,                                                 1996           1995
-----------------------------------------------------------------------------------
                                                                (Thousands of Dollars)
<S>                                                            <C>            <C>
ASSETS
------

Utility Plant, at original cost:
  Electric................................................  $  6,283,736   $  6,147,961

    Less: Accumulated provision for                         
           depreciation (Note 1F).........................     2,665,519      2,418,557
                                                            -------------  -------------
                                                               3,618,217      3,729,404
  Construction work in progress...........................        95,873        103,026
  Nuclear fuel, net.......................................       133,050        138,203
                                                            -------------  -------------
    Total net utility plant...............................     3,847,140      3,970,633
                                                            -------------  -------------

Other Property and Investments:                             
  Nuclear decommissioning trusts, at market...............       296,960        238,023
  Investments in regional nuclear generating                
   companies, at equity (Note 1E).........................        56,925         54,624
  Other, at cost..........................................        16,565         16,241
                                                            -------------  -------------
                                                                 370,450        308,888
                                                            -------------  -------------
Current Assets:                                             
  Cash....................................................           404            337
  Notes receivable from affiliated companies..............       109,050           -
  Receivables, less accumulated provision for
   uncollectible accounts of $13,240,000 in 1996          
   and $10,567,000 in 1995................................       226,112        231,574
  Accounts receivable from affiliated companies...........         3,481          3,069
  Taxes receivable........................................        40,134           -
  Accrued utility revenues................................        78,451         91,157
  Fuel, materials, and supplies, at average cost..........        79,937         68,482
  Recoverable energy costs, net--current portion..........        25,436         78,108
  Prepayments and other...................................        63,344         42,894
                                                            -------------  -------------
                                                                 626,349        515,621
                                                            -------------  -------------
Deferred Charges:                                           
  Regulatory assets (Note 1H).............................     1,370,781      1,225,280
  Unamortized debt expense................................        17,033         14,977
  Other...................................................        12,283         10,232
                                                            -------------  -------------
                                                               1,400,097      1,250,489
                                                            -------------  -------------

   





      Total Assets........................................  $  6,244,036   $  6,045,631
                                                            =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------
At December 31,                                                  1996           1995
----------------------------------------------------------------------------------------
                                                                (Thousands of Dollars)
<S>                                                            <C>            <C>
CAPITALIZATION AND LIABILITIES
------------------------------

Capitalization:                                             
  Common stock--$10 par value. Authorized                   
   24,500,000 shares; outstanding 12,222,930                
   shares in 1996 and 1995................................  $    122,229   $    122,229
  Capital surplus, paid in................................       639,657        637,981
  Retained earnings.......................................       551,410        785,476
                                                            -------------  -------------
           Total common stockholder's equity..............     1,313,296      1,545,686
  Cumulative preferred stock--
   $50 par value - authorized 9,000,000 shares;
   outstanding 5,424,000 shares in 1996 and 1995
   $25 par value - authorized 8,000,000 shares;
   outstanding no shares in 1996 and 1995
   Not subject to mandatory redemption....................       116,200        116,200
   Subject to mandatory redemption........................       155,000        155,000
  Long-term debt..........................................     1,834,405      1,812,646
                                                            -------------  -------------
           Total capitalization...........................     3,418,901      3,629,532
                                                            -------------  -------------
Minority Interest in Consolidated 
  Subsidiary (Note 13)....................................       100,000        100,000
                                                            -------------  -------------
Obligations Under Capital Leases (Note 2).................       143,347        108,408
                                                            -------------  -------------
Current Liabilities:                                                      
  Notes payable to banks..................................          -            41,500
  Notes payable to affiliated company.....................          -            10,250
  Long-term debt--current portion.........................       204,116          9,372
  Obligations under capital leases--current                               
   portion (Note 2).......................................        12,361         63,856
  Accounts payable........................................       160,945        110,798
  Accounts payable to affiliated companies................        78,481         44,677
  Accrued taxes...........................................        28,707         52,268
  Accrued interest........................................        31,513         30,854
  Nuclear compliance (Note 11B)...........................        50,500           -
  Other...................................................        34,433         20,027
                                                            -------------  -------------
                                                                 601,056        383,602
                                                            -------------  -------------
Deferred Credits:                                           
  Accumulated deferred income taxes (Note 1I).............     1,365,641      1,486,873
  Accumulated deferred investment tax credits.............       135,080        142,447
  Deferred contractual obligations (Note 3)...............       305,627         65,847
  Other...................................................       174,384        128,922
                                                            -------------  -------------
                                                               1,980,732      1,824,089
                                                            -------------  -------------

Commitments and Contingencies (Note 11)


           Total Capitalization and Liabilities...........  $  6,244,036   $  6,045,631
                                                            =============  =============
</TABLE>                                                   
The accompanying notes are an integral part of these financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>

---------------------------------------------------------------------------------------
For the Years Ended December 31,                        1996        1995        1994
---------------------------------------------------------------------------------------
                                                           (Thousands of Dollars)

<S>                                                  <C>         <C>         <C>
Operating Revenues................................. $2,397,460  $2,387,069  $2,328,052
                                                    ----------- ----------- -----------
Operating Expenses:                                 
  Operation --                                      
     Fuel, purchased and net interchange power.....    830,924     608,600     568,394
     Other.........................................    778,329     614,382     593,851
  Maintenance......................................    300,005     192,607     207,003
  Depreciation.....................................    247,109     242,496     231,155
  Amortization of regulatory assets, net...........     57,432      54,217      77,384
  Federal and state income taxes (Note 8)..........    (20,174)    178,346     190,249
  Taxes other than income taxes....................    174,062     172,395     173,068
                                                    ----------- ----------- -----------
        Total operating expenses...................  2,367,687   2,063,043   2,041,104
                                                    ----------- ----------- -----------
Operating Income...................................     29,773     324,026     286,948
                                                    ----------- ----------- -----------
                                                    
Other Income:                                       
  Deferred nuclear plants return--other funds......      1,268       4,683      13,373
  Equity in earnings of regional nuclear            
    generating companies...........................      6,619       6,545       7,453
  Other, net.......................................     19,442       9,902       5,136
  Minority interest in income of 
    subsidiary (Note 13)...........................     (9,300)     (8,732)       -
  Income taxes.....................................        160      (2,978)      4,248
                                                    ----------- ----------- -----------
        Other income, net..........................     18,189       9,420      30,210
                                                    ----------- ----------- -----------
        Income before interest charges.............     47,962     333,446     317,158
                                                    ----------- ----------- -----------

Interest Charges:                                   
  Interest on long-term debt.......................    127,198     124,350     119,927
  Other interest...................................      1,147       5,596       6,378
  Deferred nuclear plants return--borrowed funds...       (146)     (1,716)     (7,435)
                                                    ----------- ----------- -----------
        Interest charges, net......................    128,199     128,230     118,870
                                                    ----------- ----------- -----------

Net (Loss) Income.................................. $  (80,237) $  205,216  $  198,288
                                                    =========== =========== ===========

</TABLE>
The accompanying notes are an integral part of these financial statements.



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
For the Years Ended December 31,                                   1996        1995        1994
--------------------------------------------------------------------------------------------------
                                                                      (Thousands of Dollars)
<S>                                                              <C>         <C>         <C>
Operating Activities:                                            
  Net(Loss)Income............................................. $  (80,237) $  205,216  $  198,288
  Adjustments to reconcile to net cash                                       
   from operating activities:
    Depreciation..............................................    247,109     242,496     231,155
    Deferred income taxes and investment tax credits, net.....    (60,773)     49,520      37,664
    Deferred nuclear plants return, net of amortization.......      7,746      95,559      82,651
    Deferred demand-side-management costs, net of amortization     26,941        (937)     (4,691)
    Recoverable energy costs, net of amortization.............    (35,567)    (16,169)      3,975
    Deferred cogeneration costs, net of amortization..........     25,957     (55,341)    (36,821)
    Nuclear compliance, net (Note 11B)........................     50,500        -           -
    Deferred nuclear refueling outage, net of amortization ...     45,643     (20,712)     (4,653)
    Other sources of cash.....................................     75,552      86,956      47,791
    Other uses of cash........................................    (23,862)    (53,745)     (4,697)
  Changes in working capital:                                  
    Receivables and accrued utility revenues..................    (22,378)    (33,032)     45,386
    Fuel, materials and supplies..............................    (11,455)     (4,479)     (3,756)
    Accounts payable..........................................     83,951       9,605     (24,167)
    Accrued taxes.............................................    (23,561)     25,855      (9,726)
    Other working capital (excludes cash).....................     (5,385)     (1,869)    (18,403)
                                                               ----------- ----------- -----------
Net cash flows from operating activities......................    300,181     528,923     539,996
                                                               ----------- ----------- -----------


Financing Activities:
  Issuance of long-term debt..................................    222,000        -        535,000
  Issuance of Monthly Income
   Preferred Securities.......................................       -        100,000        -
  Net (decrease) increase in short-term debt..................    (51,750)   (127,000)     82,500
  Reacquisitions and retirements of long-term debt............    (14,329)    (10,866)   (774,020)
  Reacquisitions and retirements of preferred stock...........       -       (125,000)       -
  Cash dividends on preferred stock...........................    (15,221)    (21,185)    (23,895)
  Cash dividends on common stock..............................   (138,608)   (164,154)   (159,388)
                                                               ----------- ----------- -----------
Net cash flows from (used for) financing activities...........      2,092    (348,205)   (339,803)
                                                               ----------- ----------- -----------
Investment Activities:                                         
  Investment in plant:                                         
    Electric utility plant....................................   (140,086)   (131,858)   (149,889)
    Nuclear fuel..............................................        553      (1,543)    (20,905)
                                                               ----------- ----------- -----------
  Net cash flows used for investments in plant................   (139,533)   (133,401)   (170,794)
  Investment in NU system money pool..........................   (109,050)       -           -
  Investment in nuclear decommissioning trusts................    (50,998)    (47,826)    (28,129)
  Other investment activities, net............................     (2,625)        581      (1,565)
                                                               ----------- ----------- -----------
Net cash flows used for investments...........................   (302,206)   (180,646)   (200,488)
                                                               ----------- ----------- -----------
Net Increase (Decrease) In Cash For The Period................         67          72        (295)
Cash - beginning of period....................................        337         265         560
                                                               ----------- ----------- -----------
Cash - end of period.......................................... $      404  $      337  $      265
                                                               =========== =========== ===========

                                                              
Supplemental Cash Flow Information:
Cash paid during the year for:                                 
  Interest, net of amounts capitalized........................ $  114,458  $  117,074  $  115,120
                                                               =========== =========== ===========
  Income taxes................................................ $   77,790  $  137,706  $  161,513
                                                               =========== =========== ===========
Increase in obligations:                                       
  Niantic Bay Fuel Trust and other capital leases............. $    2,855  $   33,537  $   52,353
                                                               =========== =========== ===========

</TABLE>                                                       
The accompanying notes are an integral part of these financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
                                                   Capital    Retained
                                         Common    Surplus,   Earnings
                                         Stock     Paid In       (a)        Total
------------------------------------------------------------------------------------
                                                       (Thousands of Dollars)


<S>                                     <C>        <C>        <C>         <C>
Balance at January 1, 1994..........   $122,229   $630,271   $ 750,719   $1,503,219


    Net income for 1994.............                           198,288      198,288
    Cash dividends on preferred     
      stock.........................                           (23,895)     (23,895)
    Cash dividends on common stock..                          (159,388)    (159,388)
    Capital stock expenses, net.....                 1,846                    1,846
                                       ---------  ---------  ----------  -----------
Balance at December 31, 1994........    122,229    632,117     765,724    1,520,070
                                    

    Net income for 1995.............                           205,216      205,216
    Cash dividends on preferred     
      stock.........................                           (21,185)     (21,185)
    Cash dividends on common stock..                          (164,154)    (164,154)
    Loss on the retirement of
      preferred stock...............                              (125)        (125)
    Capital stock expenses, net.....                 5,864                    5,864
                                       ---------  ---------  ----------  -----------
Balance at December 31, 1995........    122,229    637,981     785,476    1,545,686


    Net loss for 1996...............                           (80,237)     (80,237)
    Cash dividends on preferred     
      stock.........................                           (15,221)     (15,221)
    Cash dividends on common stock..                          (138,608)    (138,608)
    Capital stock expenses, net.....                 1,676                    1,676
                                       ---------  ---------  ----------  -----------
Balance at December 31, 1996........   $122,229   $639,657   $ 551,410   $1,313,296
                                       =========  =========  ==========  ===========

</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt 
    agreements.  At December 31, 1996, these restrictions totaled 
    approximately $540 million.


The accompanying notes are an integral part of these financial statements.





1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

   A.  ABOUT THE CONNECTICUT LIGHT AND POWER COMPANY
       The Connecticut Light and Power Company and Subsidiaries (the company or
       CL&P), Western Massachusetts Electric Company (WMECO), Holyoke Water
       Power Company (HWP), Public Service Company of New Hampshire (PSNH), and
       North Atlantic Energy Corporation (NAEC) are the operating subsidiaries
       comprising the Northeast Utilities system (the system) and are wholly
       owned by Northeast Utilities (NU).

       The system furnishes retail electric service in Connecticut, New
       Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP.
       A fifth subsidiary, NAEC, sells all of its capacity to PSNH.  In
       addition to its retail service, the system furnishes firm and other
       wholesale electric services to various municipalities and other
       utilities.  The system serves about 30 percent of New England's electric
       needs and is one of the 20 largest electric utility systems in the
       country as measured by revenues.

       Other wholly owned subsidiaries of NU provide support services for the
       system companies and in some cases, for other New England utilities.
       Northeast Utilities Service Company (NUSCO) provides centralized
       accounting, administrative, information resources, engineering,
       financial, legal, operational, planning, purchasing, and other services
       to the system companies.  Northeast Nuclear Energy Company (NNECO) acts
       as agent for the system companies in operating the Millstone nuclear
       generating facilities. North Atlantic Energy Service Corporation
       (NAESCO) acts as agent for CL&P and NAEC and has operational
       responsibilities for the Seabrook nuclear generating facility.


    B. PRESENTATION
       The consolidated financial statements of CL&P include the accounts of
       all wholly owned subsidiaries. Significant intercompany transactions
       have been eliminated in consolidation.

       The preparation of financial statements in conformity with generally
       accepted accounting principles requires management to make estimates and
       assumptions that affect the reported amounts of assets and liabilities
       and disclosure of contingent liabilities at the date of the financial
       statements and the reported amounts of revenues and expenses during the
       reporting period.  Actual results could differ from those estimates.

       Certain reclassifications of prior years' data have been made to conform
       with the current year's presentation.

       All transactions among affiliated companies are on a recovery of cost
       basis which may include amounts representing a return on equity, and are
       subject to approval by various federal and state regulatory agencies.


   C.  PUBLIC UTILITY REGULATION
       NU is registered with the Securities and Exchange Commission (SEC) as a
       holding company under the Public Utility Holding Company Act of 1935
       (1935 Act), and it and its subsidiaries, including the company, are
       subject to the provisions of the 1935 Act.  Arrangements among the
       system companies, outside agencies and other utilities covering
       interconnections, interchange of electric power and sales of utility
       property are subject to regulation by the Federal Energy Regulatory
       Commission (FERC) and/or the SEC.  The company is subject to further
       regulation for rates, accounting and other matters by the FERC and/or
       the Connecticut Department of Public Utility Control (DPUC).

   D.  NEW ACCOUNTING STANDARDS
       The Financial Accounting Standards Board (FASB) has issued Statement of
       Financial Accounting Standards (SFAS) 121, "Accounting for the
       Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
       Of," which established accounting standards for evaluating and recording
       asset impairment.  The company adopted SFAS 121 as of January 1, 1996.
       See Note 1H, "Summary of Significant Accounting Policies - Regulatory
       Accounting and Assets" for further information on the regulatory impacts
       of the company's adoption of SFAS 121.

       See Note 10, "Sale of Customer Receivables," and Note 11C, "Commitments
       and Contingencies-Environmental Matters," for information on newly
       issued accounting and reporting standards related to those specific
       areas.

   E.  INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
       Regional Nuclear Generating Companies:  CL&P owns common stock of four
       regional nuclear generating companies (Yankee companies).  The Yankee
       companies, with the company's ownership interests are:


       Connecticut Yankee Atomic Power Company (a) (CY) ............... 34.5%
       Yankee Atomic Electric Company (a) (YAEC) ...................... 24.5
       Maine Yankee Atomic Power Company (MY) ......................... 12.0
       Vermont Yankee Nuclear Power Corporation (VY) ..................  9.5


      (a)  YAEC's and CY's nuclear power plants were shut down permanently on
           February 26, 1992 and December 4, 1996, respectively.

       CL&P's investments in the Yankee companies are accounted for on the
       equity basis due to the company's ability to exercise significant
       influence over their operating and financial policies.


       CL&P's investments in the Yankee companies at December 31, 1996 are:


                                           (Thousands of Dollars)

       Connecticut Yankee Atomic Power Company  .................    $36,954
       Yankee Atomic Electric Company ...........................      5,854
       Maine Yankee Atomic Power Company ........................      8,956
       Vermont Yankee Nuclear Power Corporation .................      5,161

                                                                     $56,925


       The electricity produced by MY and VY is committed substantially on the
       basis of ownership interests and is billed pursuant to contractual
       agreements.  Under ownership agreements with the Yankee companies, CL&P
       may be asked to provide direct or indirect financial support for one or
       more of the companies.  For more information on these agreements, see
       Note 11F, "Commitments and Contingencies - Long-Term Contractual
       Arrangements."  For more information on the Yankee companies, see Note
       3, "Nuclear Decommissioning" and Note 11B, "Commitments and
       Contingencies-Nuclear Performance."

       Millstone 1:  CL&P has an 81.0 percent joint ownership interest in
       Millstone 1, a 660-megawatt (MW) nuclear generating unit.  As of
       December 31, 1996 and 1995, plant-in-service included approximately
       $384.5 million and $372.6 million, respectively, and the accumulated
       provision for depreciation included approximately $159.4 million and
       $148.4 million, respectively, for CL&P's share of Millstone 1. CL&P's
       share of Millstone 1 expenses is included in the corresponding operating
       expenses on the accompanying Consolidated Statements of Income.

       Millstone 2:  CL&P has an  81.0 percent joint ownership interest in
       Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1996
       and 1995, plant-in-service included approximately $690.4 million and
       $684.5 million, respectively, and the accumulated provision for
       depreciation included approximately $224.1 million and $198.5 million,
       respectively, for CL&P's share of Millstone 2.  CL&P's share of
       Millstone 2 expenses is included in the corresponding operating expenses
       on the accompanying Consolidated Statements of Income.

       Millstone 3:  CL&P has a 52.93 percent joint ownership interest in
       Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1996
       and 1995, plant-in-service included approximately $1.9 billion, and the
       accumulated provision for depreciation included approximately $504.1
       million and $455.1 million, respectively, for CL&P's share of Millstone
       3. CL&P's share of Millstone 3 expenses is included in the corresponding
       operating expenses on the accompanying Consolidated Statements of
       Income.


       For more information regarding the Millstone units, see Note 11B,
       "Commitments and Contingencies-Nuclear Performance."

       Seabrook 1:  CL&P has a 4.06 percent joint ownership interest in
       Seabrook 1, a 1,148-MW nuclear generating unit.  As of December 31, 1996
       and 1995, plant-in-service included approximately $173.7 million and
       $173.3 million, respectively, and the accumulated provision for
       depreciation included approximately $29.7 million and $24.8 million,
       respectively, for CL&P's share of Seabrook 1.  CL&P's share of Seabrook
       1 expenses is included in the corresponding operating expenses on the
       accompanying Consolidated Statements of Income.

   F.  DEPRECIATION
       The provision for depreciation is calculated using the straight-line
       method based on estimated remaining lives of depreciable utility plant-
       in-service, adjusted for salvage value and removal costs, as approved by
       the appropriate regulatory agency.  Except for major facilities,
       depreciation rates are applied to the average plant-in-service during
       the period.  Major facilities are depreciated from the time they are
       placed in service.  When plant is retired from service, the original
       cost of plant, including costs of removal, less salvage, is charged to
       the accumulated provision for depreciation.  The depreciation rates for
       the several classes of electric plant-in-service are equivalent to a
       composite rate of 4.0 percent in 1996 and 1995, and 3.9 percent in 1994.
       See Note 3, "Nuclear Decommissioning," for information on nuclear plant
       decommissioning.

       CL&P's nonnuclear generating facilities have limited service lives.
       Plant may be retired in place or dismantled based upon expected future
       needs, the economics of the closure and environmental concerns.  The
       costs of closure and removal are incremental costs and, for financial
       reporting purposes, are accrued over the life of the asset as part of
       depreciation.  At December 31, 1996, the accumulated provision for
       depreciation included approximately $43 million accrued for the cost of
       removal, net of salvage for nonnuclear generation property.

   G.  REVENUES
       Other than revenues under fixed-rate agreements negotiated with certain
       wholesale, industrial and commercial customers and limited pilot retail
       access programs, utility revenues are based on authorized rates applied
       to each customer's use of electricity.  In general, rates can be changed
       only through a formal proceeding before the appropriate regulatory
       commission. At the end of each accounting period, CL&P accrues an
       estimate for the amount of energy delivered but unbilled.

   H.  REGULATORY ACCOUNTING AND ASSETS
       The accounting policies of CL&P and the accompanying consolidated
       financial statements conform to generally accepted accounting principles
       applicable to rate regulated enterprises and reflect the effects of the
       ratemaking process in accordance with SFAS 71, "Accounting for the
       Effects of Certain Types of Regulation." Assuming a cost-of-service
       based regulatory structure, regulators may permit incurred costs,
       normally treated as expenses, to be deferred and recovered through
       future revenues.  Through their actions, regulators may also reduce or
       eliminate the value of an asset, or create a liability.  If any portion
       of the company's operations were no longer subject to the provisions of
       SFAS 71, as a result of a change in the cost-of-service based regulatory
       structure or the effects of competition, the company would be required
       to write off related regulatory assets and liabilities. The company
       continues to believe that its use of regulatory accounting remains
       appropriate.

       SFAS 121 requires the evaluation of long-lived assets, including
       regulatory assets, for impairment when certain events occur or when
       conditions  exist that indicate the carrying amounts of assets may not
       be recoverable.  SFAS 121 requires that any long-lived assets which are
       no longer probable of recovery through future revenues be revalued based
       on estimated future cash flows.  If the revaluation is less than the
       book value of the asset, an impairment loss would be charged to
       earnings. The implementation of SFAS 121 did not have a material impact
       on the company's financial position or results of operations as of
       December 31, 1996.  Management continues to believe that it is probable
       that the company will recover its investments in long-lived assets
       through future revenues. This conclusion may change in the future as
       competitive factors influence wholesale and retail pricing in the
       electric utility industry or if the cost-of-service based regulatory
       structure were to change.

       The components of CL&P's regulatory assets are as follows:


       At December 31,                                    1996          1995
                                                       (Thousands of Dollars)

       Income taxes, net (Note 1I) ..................  $  753,390   $  863,521
       Recoverable energy costs,
         net (Note 1J) ..............................      97,900        9,662
       Deferred demand side management
         costs (Note 1K) ............................      90,129      117,070
       Cogeneration costs (Note 1L) .................      66,205       92,162
       Unrecovered contractual
         obligations (Note 3) .......................     300,627       65,847
       Other ........................................      62,530       77,018

                                                       $1,370,781   $1,225,280



       For more information on the company's regulatory environment and the
       potential impacts of restructuring, see Note 11A, "Commitments and
       Contingencies-Restructuring" and Management's Discussion and Analysis of
       Financial Condition and Results of Operations (MD&A).


   I.  INCOME TAXES
       The tax effect of temporary differences (differences between the periods
       in which transactions affect income in the financial statements and the
       periods in which they affect the determination of taxable income) is
       accounted for in accordance with the ratemaking treatment of the
       applicable regulatory commissions.  The adoption of SFAS 109,
       "Accounting for Income Taxes," in 1993 increased the company's net
       deferred tax obligation.  As it is probable that the increase in
       deferred tax liabilities will be recovered from customers through rates,
       CL&P established a regulatory asset.  See Note 8, "Income Tax Expense"
       for the components of income tax expense.



       The tax effect of temporary differences, including timing differences
       accrued under previously approved accounting standards, which give rise
       to the accumulated deferred tax obligation is as follows:



       At December 31,                                     1996         1995
                                                         (Thousands of Dollars)

       Accelerated depreciation and other
         plant-related differences .....................$1,032,857   $1,074,242
                                                        
       Regulatory assets - income tax
         gross up .....................................    313,420      347,673

       Other ..........................................     19,364       64,958

                                                        $1,365,641   $1,486,873



    J.  RECOVERABLE ENERGY COSTS
       Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for
       its proportionate share of the costs of decontaminating and
       decommissioning uranium enrichment plants owned by the United States
       Department of Energy (D&D assessment).  The Energy Act requires that
       regulators treat D&D assessments as a reasonable and necessary current
       cost of fuel, to be fully recovered in rates, like any other fuel cost.
       CL&P is currently recovering these costs through rates. As of December
       31, 1996, the company's total D&D deferrals were approximately $49.2
       million.

       During 1996, retail electric rates included a fuel adjustment clause
       (FAC) under which fossil fuel prices above or below base-rate levels are
       charged or credited to customers. In addition, CL&P also utilized a
       generation utilization adjustment clause (GUAC), which deferred the
       effect on fuel costs caused by variations from a specified composite
       nuclear generation capacity factor embedded in base rates.

       At December 31, 1996, CL&P's net recoverable energy costs, excluding
       current net recoverable energy costs, were approximately $97.9 million,
       which includes the D&D assessment. For additional information, see Note
       11B, "Commitments and Contingencies - Nuclear Performance."

       On October 8, 1996, the DPUC issued an order establishing an Energy
       Adjustment Clause (EAC) effective January 1, 1997.  The EAC will replace
       CL&P's existing FAC and GUAC.  For further information regarding the
       EAC, see the MD&A.

    K. DEMAND SIDE MANAGEMENT (DSM)
       CL&P's DSM costs are recovered in base rates through a Conservation
       Adjustment Mechanism (CAM).  The $90.1 million of costs on CL&P's books
       as of December 31, 1996, will be fully recovered by 2000.  During
       November, 1996, CL&P filed its 1997 DSM program and forecasted CAM for
       1997 with the DPUC.  The filing proposes expenditures of $36 million in
       1997, with recovery over 1.9 years and a zero CAM rate.

    L. COGENERATION COSTS
       Beginning on July 1, 1996, the deferred cogeneration balance of
       approximately $86 million is being amortized over a five year period.
       An additional $9 million of amortization will be applied to the deferred
       balance in 1997, as required under a settlement agreement which CL&P
       reached with the DPUC.  CL&P will continue to apply any savings
       associated with the renegotiation of a certain contract with a
       cogeneration facility to the deferred balance.  Under current
       expectations, CL&P expects complete amortization of the deferred balance
       by December 31, 1998.

    M. SPENT NUCLEAR FUEL DISPOSAL COSTS
       Under the Nuclear Waste Policy Act of 1982,  CL&P must pay the United
       States Department of Energy (DOE) for the disposal of spent nuclear fuel
       and high-level radioactive waste.  Fees for nuclear fuel burned on or
       after April 7, 1983 are billed currently to customers and paid to the
       DOE on a quarterly basis. For nuclear fuel used to generate electricity
       prior to April 7, 1983 (prior-period fuel), payment must be made prior
       to the first delivery of spent fuel to the DOE.  The DOE was originally
       scheduled to begin accepting delivery of spent fuel in 1998.  However,
       delays in identifying a permanent storage site have continually
       postponed plans for the DOE's long-term storage and disposal site.  The
       DOE's current estimate for an available site is 2010.

       Until such payment is made, the outstanding balance will continue to
       accrue interest at the three-month Treasury Bill Yield Rate.  At
       December 31, 1996, fees due to the DOE for the disposal of prior-period
       fuel were approximately $158.0 million, including interest costs of
       $91.5 million.  As of December 31, 1996, all fees had been collected
       through rates.


    N. FUEL PRICE MANAGEMENT
       The company utilizes fuel-price management instruments to manage well
       defined fuel price risks. Amounts receivable or payable under fuel-price
       management instruments are recognized in income when realized. Any
       material unrealized gains or losses on fuel-price management instruments
       will be deferred until realized. For further information, see Note 12,
       "Fuel Price Management."

2. LEASES

     CL&P and WMECO finance up to $450 million of nuclear fuel for Millstone 1
     and 2 and their respective shares of the nuclear fuel for Millstone 3 under
     the Niantic Bay Fuel Trust (NBFT) capital lease agreement.  CL&P and WMECO
     make quarterly lease payments for the cost of nuclear fuel consumed in the
     reactors, based on a units-of-production method at rates which reflect
     estimated kilowatt-hours of energy provided, plus financing costs
     associated with the fuel in the reactors.  Upon permanent discharge from
     the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO.

     CL&P has also entered into lease agreements, some of which are capital
     leases, for the use of data processing and office equipment, vehicles, gas
     turbines, nuclear control room simulators and office space.  The provisions
     of these lease agreements generally provide for renewal options.  The
     following rental payments have been charged to expense:

     Year            Capital Leases   Operating Leases


     1996   ..........$17,993,000       $22,032,000
     1995   ...........56,307,000        23,793,000
     1994   ...........60,975,000        24,192,000

     Interest included in capital lease rental payments was $10,144,000 in 1996,
     $10,587,000 in 1995, and $10,228,000 in 1994.

     Substantially all of the capital lease rental payments were made pursuant
     to the nuclear fuel lease agreement. Future minimum lease payments under
     the nuclear fuel capital lease cannot be reasonably estimated on an annual
     basis due to variations in the usage of nuclear fuel.


     Future minimum rental payments, excluding annual nuclear fuel lease
     payments and executory costs, such as property taxes, state use taxes,
     insurance and maintenance, under long-term noncancelable leases, as of
     December 31, 1996 are:

     Year                Capital Leases      Operating Leases
                                  (Thousands of Dollars)

     1997   .................$ 2,800       $26,100
     1998   ...................2,900        21,500
     1999   ...................2,900        19,900
     2000   ...................2,900        18,800
     2001   ...................3,000        13,700
     After 2001...............66,400        46,400

     Future minimum lease
       payments...............80,900      $146,400

     Less amount representing
        interest..............61,900

     Present value of future
       minimum lease payments
       for other than
       nuclear fuel...........19,000

     Present value of future
       nuclear fuel lease
       payments..............136,800


     Total  ................$155,800



     It is possible that certain operating lease payments related to NUSCO
     leases will be accelerated from future years into 1997.  See Note 11G, "The
     Rocky River Realty Company - Obligations" for additional information.

3.   NUCLEAR DECOMMISSIONING
     CL&P's nuclear power plants have service lives that are expected to end
     during the years 2010 through 2026.  Upon retirement, these units must be
     decommissioned.  Decommissioning studies prepared in 1996 concluded that
     complete and immediate dismantlement at retirement continues to be the most
     viable and economic method of decommissioning the three Millstone units and
     Seabrook 1. Decommissioning studies are reviewed and updated periodically
     to reflect changes in decommissioning requirements, costs, technology and
     inflation.

     The estimated cost of decommissioning CL&P's ownership share of Millstone 1
     and 2, in year-end 1996 dollars, is $316.0 million and $279.0 million,
     respectively.  CL&P's ownership share of the estimated cost of
     decommissioning Millstone 3 and Seabrook 1 in year-end 1996 dollars, is
     $244.9 million and $18.3 million, respectively. The Millstone units and
     Seabrook 1 decommissioning costs will be increased annually by their
     respective escalation rates.  Nuclear decommissioning costs are accrued
     over the expected service life of the units and are included in
     depreciation expense on the Consolidated Statements of Income.  Nuclear
     decommissioning costs amounted to $37.8 million in 1996, $30.5 million in
     1995, and $25.6 million in 1994.  Nuclear decommissioning, as a cost of
     removal, is included in the accumulated provision for depreciation on the
     Consolidated Balance Sheets.  At December 31, 1996, the balance in the
     accumulated reserve for decommissioning amounted to $329.1 million.

     CL&P has established external decommissioning trusts through a trustee for
     its portion of the costs of decommissioning Millstone 1, 2, and 3.  CL&P's
     portion of the cost of decommissioning Seabrook 1 is paid to an independent
     decommissioning financing fund managed by the state of New Hampshire.
     Funding of the estimated decommissioning costs assume levelized collections
     for the Millstone units and escalated collections for Seabrook 1 and after-
     tax earnings on the Millstone and Seabrook decommissioning funds of 5.8
     percent and 6.5 percent, respectively.
                                                                               
     As of December 31, 1996, CL&P has collected, through rates, $240.8 million
     toward the future decommissioning costs of its share of the Millstone
     units, of which $209.1 million has been transferred to external
     decommissioning trusts.  As of December 31, 1996, CL&P has paid
     approximately $2.4 million into Seabrook 1's decommissioning financing
     fund.  Earnings on the decommissioning trusts and financing fund increase
     the decommissioning trust balance and the accumulated reserve for
     decommissioning.  Unrealized gains and losses associated with the
     decommissioning trusts and financing fund also impact the balance of the
     trusts and financing fund and the accumulated reserve for decommissioning.

     Changes in requirements or technology, the timing of funding or
     dismantling, or adoption of a decommissioning method other than immediate
     dismantlement would change decommissioning cost estimates and the amounts
     required to be recovered.  CL&P attempts to recover sufficient amounts
     through its allowed rates to cover its expected decommissioning costs.
     Only the portion of currently estimated total decommissioning costs that
     has been accepted by regulatory agencies is reflected in CL&P's rates.
     Based on present estimates and assuming its nuclear units operate to the
     end of their respective license periods, CL&P expects that the
     decommissioning trusts and financing fund will be substantially funded when
     the units are retired from service.

     MY and VY: Each Yankee company owns a single nuclear generating unit.  MY
     and VY have service lives that are expected to end in 2008 and 2012,
     respectively.  The estimated cost, in year-end 1996 dollars, of
     decommissioning CL&P's ownership share of units owned and operated by MY
     and VY are $44.3 million and $34.8 million, respectively.  Under the terms
     of the contracts with the Yankee companies, the shareholders-sponsors are
     responsible for their proportionate share of the operating costs of each
     unit, including decommissioning.  The nuclear decommissioning costs of the
     Yankee companies are included as part of the cost of power purchased by
     CL&P.

     CY and YAEC:  On December 4, 1996, the board of directors of CY voted
     unanimously to cease permanently the production of power at its nuclear
     plant.  The system companies relied on CY for approximately three percent
     of their capacity.

     CY has undertaken a number of regulatory filings intended to implement the
     decommissioning and the recovery of remaining assets of CY.  During late
     December, 1996, CY filed an amendment to its power contracts to clarify the
     obligations of its purchasing utilities following the decision to cease
     power production.  At December 31, 1996, the estimated obligation,
     including decommissioning, amounted to $762.8 million of which CL&P's share
     was approximately $263.2 million.

     YAEC is in the process of decommissioning its nuclear facility. At December
     31, 1996, the estimated remaining costs, including decommissioning,
     amounted to $173.3 million of which CL&P's share was approximately $42.5
     million.

     Management expects that CL&P will continue to be allowed to recover these
     costs from its customers.  Accordingly, CL&P has recognized these costs as
     regulatory assets, with corresponding obligations, on its Consolidated
     Balance Sheets.

     Proposed Accounting:  The staff of the SEC has questioned certain of the
     current accounting practices of the electric utility industry, including
     the company, regarding the recognition, measurement and classification of
     decommissioning costs for nuclear generating units in the financial
     statements.  In response to these questions, FASB agreed to review the
     accounting for removal costs, including decommissioning, and issued a
     proposed statement entitled "Accounting for Liabilities  Related to Closure
     or Removal of Long-Lived Assets," in February, 1996.  If current electric
     utility industry accounting practices for decommissioning are changed in
     accordance with the proposed statement: (1) annual provisions for
     decommissioning could increase, (2) the estimated cost for decommissioning
     could be recorded as a liability with an offset to plant rather than as
     part of accumulated depreciation, and (3) trust fund income from the
     external decommissioning trusts could be reported as investment income
     rather than as a reduction to decommissioning expense.


4.   SHORT-TERM DEBT

     Limits: The amount of short-term borrowings that may be incurred by CL&P is
     subject to periodic approval by either the SEC under the 1935 Act or by its
     state regulator.  In addition, the charter of CL&P contains provisions
     restricting the amount of short-term debt borrowings.  Under the SEC and/or
     charter restrictions, the company was authorized, as of January 1, 1997, to
     incur short-term borrowings up to a maximum of $375 million.

     Credit Agreements:  In November, 1996, NU entered into a three-year
     revolving credit agreement (New Credit Agreement) with a group of 12 banks.
     Under the terms of the New Credit Agreement, NU, CL&P and WMECO will be
     able to borrow up to $150 million, $313.75 million, and $150 million,
     respectively.  The overall limit for all of the borrowing system companies
     under the entire New Credit Agreement is $313.75 million.  The system
     companies are obligated to pay a facility fee of .30 percent per annum of
     each bank's total commitment under the new credit facility which will
     expire November 21, 1999.  At December 31, 1996, there were $27.5 million
     in borrowings under this agreement, all of which were borrowed by other
     system companies.

     Access to the New Credit Agreement is contingent upon certain financial
     tests being met.  NU is currently renegotiating these restrictions so that
     the financial impacts of the current nuclear outages do not impact the
     ability to access these facilities. Through February 21, 1997, CL&P and
     WMECO have satisfied all financial covenants required under their
     respective borrowing facilities, but NU needed and obtained a limited
     waiver of an interest coverage covenant that had to be satisfied for NU to
     borrow under the New Credit Agreement.  NU, CL&P, and WMECO are currently
     maintaining their access to the New Credit Agreement under an interim
     written arrangement, under which NU agreed not to borrow more than $27.5
     million against the facility.

     In addition to the New Credit Agreement, NU, CL&P, WMECO, HWP, NNECO and
     The Rocky River Realty Company (RRR) have various revolving credit lines
     through separate bilateral credit agreements.  Under the remaining three-
     year portion of the facility, four banks maintain commitments to the
     respective system companies totaling $56.25 million.  NU, CL&P and WMECO
     may borrow up to the aggregate $56.25 million, whereas HWP, NNECO and RRR
     may borrow up to their short-term debt limit of $5 million, $50 million and
     $22 million, respectively.  Under the terms of the agreement, the system
     companies are obligated to pay a facility fee of .15 percent per annum of
     each bank's total commitment under the three-year portion of the facility.
     These commitments will expire December 3, 1998.  At December 31, 1996 and
     1995, there were $11.3 million and $42.5 million in borrowings,
     respectively, under the facility, of which CL&P had no borrowings in 1996
     and $10 million in borrowings in 1995.

     Under both credit facilities above, the company may borrow funds on a
     short-term revolving basis under the remaining portion of its agreement,
     using either fixed-rate loans or standby loans.  Fixed rates are set using
     competitive bidding.  Standby loans are based upon several alternative
     variable rates.

     The weighted average annual interest rate on CL&P's notes payable to banks
     outstanding at December 31, 1995 was 6.0 percent.  Maturities of CL&P's
     short-term debt obligations are for periods of three months or less.

     Money Pool:  Certain subsidiaries of NU, including CL&P, are members of the
     Northeast Utilities System Money Pool (Pool).  The Pool provides a more
     efficient use of the cash resources of the system, and reduces outside
     short-term borrowings.  NUSCO administers the Pool as agent for the member
     companies.  Short-term borrowing needs of the member companies are first
     met with available funds of other member companies, including funds
     borrowed by NU parent. NU parent may lend to the Pool but may not borrow.
     Funds may be withdrawn from or repaid to the Pool at any time without prior
     notice. Investing and borrowing subsidiaries receive or pay interest based
     on the average daily Federal Funds rate. However, borrowings based on loans
     from NU parent bear interest at NU parent's cost and must be repaid based
     upon the terms of NU parent's original borrowing. At December 31, 1996,
     CL&P had no borrowings outstanding from the Pool.  At December 31, 1995,
     CL&P had $10.3 million of borrowings outstanding from the Pool.  The
     interest rate on borrowings from the Pool on December 31, 1996 and 1995
     were 6.3 percent and 4.7 percent, respectively.

     For further information on short-term debt see the MD&A.



5.   PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION

     Details of preferred stock not subject to mandatory redemption are:

                          December 31,    Shares
                             1996       Outstanding
                          Redemption    December 31,     December 31,
Description                 Price         1996       1996      1995   1994
                                                     (Thousands of Dollars)

$1.90  Series of 1947.....   $52.50     163,912   $  8,196   $  8,196   $  8,196
$2.00  Series of 1947.....    54.00     336,088     16,804     16,804     16,804
$2.04  Series of 1949.....    52.00     100,000      5,000      5,000      5,000
$2.06  Series E of 1954...    51.00     200,000     10,000     10,000     10,000
$2.09  Series F of 1955...    51.00     100,000      5,000      5,000      5,000
$2.20  Series of 1949.....    52.50     200,000     10,000     10,000     10,000
$3.24  Series G of 1968...    51.84     300,000     15,000     15,000     15,000
 3.90% Series of 1949.....    50.50     160,000      8,000      8,000      8,000
 4.50% Series of 1956.....    50.75     104,000      5,200      5,200      5,200
 4.50% Series of 1963.....    50.50     160,000      8,000      8,000      8,000
 4.96% Series of 1958.....    50.50     100,000      5,000      5,000      5,000
 5.28% Series of 1967.....    51.43     200,000     10,000     10,000     10,000
 6.56% Series of 1968.....    51.44     200,000     10,000     10,000     10,000
 1989 Adjustable
   Rate DARTS.............     -          -           -          -        50,000
Total preferred stock
  not subject to
  mandatory redemption                            $116,200   $116,200   $166,200



     All or any part of each outstanding series of such preferred stock may be
     redeemed by the company at any time at established redemption prices plus
     accrued dividend to the date of redemption.


6.   PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION

     Details of preferred stock subject to mandatory redemption are:

                         December 31,   Shares
                             1996     Outstanding
                          Redemption  December 31,           December 31,
Description                 Price*       1996        1996      1995      1994
                                                      (Thousands of Dollars)

9.00%  Series of 1989....     -            -       $   -     $   -      $ 75,000
7.23%  Series of 1992....   $52.41    1,500,000      75,000    75,000     75,000
5.30%  Series of 1993....   $51.00    1,600,000      80,000    80,000     80,000
                                                   $155,000  $155,000   $230,000
Less preferred stock
  to be redeemed
  within one year.........                             -         -         3,750

Total preferred stock
  subject to mandatory
  redemption..............                         $155,000  $155,000   $226,250

*Each of these series is subject to certain refunding limitations for the
 first five years after they were issued.  Redemption prices reduce in future
 years.

The following table details redemption and sinking fund activity for preferred
stock subject to mandatory redemption:

                                    Minimum
                                     Annual
                                  Sinking-Fund                Shares Reacquired
Series                            Requirement          1996      1995      1994
                             (Thousand of Dollars)
9.00%  Series of 1989               $ -                 -     3,000,000        -
7.23%  Series of 1992  (1)           3,750              -        -             -
5.30%  Series of 1993  (2)          16,000              -        -             -

(1)  Sinking fund requirements commence September 1, 1998.
(2)  Sinking fund requirements commence October 1, 1999.

     The minimum sinking-fund provisions of the series subject to mandatory
     redemption, for the years 1998 through 2001, aggregate approximately $3.8
     million in 1998, and $19.8 million in 1999, 2000 and 2001.  There were no
     minimum sinking-fund provisions in 1997.  In case of default on sinking-
     fund payments or the payment of dividends, no payments may be made on any
     junior stock by way of dividends or otherwise (other than in shares of
     junior stock) so long as the default continues. If the company is in
     arrears in the payment of dividends on any outstanding shares of preferred
     stock, the company would be prohibited from redemption or purchase of less
     than all of the preferred stock outstanding.  All or part of each of the
     series named above may be redeemed by the company at any time at
     established redemption prices plus accrued dividends to the date of
     redemption, subject to certain refunding limitations.

7.   LONG-TERM DEBT

     Details of long-term debt outstanding are:
                                                              December 31,
                                                           1996         1995
                                                        (Thousands of Dollars)
     First Mortgage Bonds:

      7 5/8%   Series UU     due 1997................. $  193,288    $  197,245
      6 1/2%   Series T      due 1998.................     20,000        20,000
      7 1/4%   Series VV     due 1999.................     99,000       100,000
      5 1/2%   Series A      due 1999.................    140,000       140,000
      5 3/4%   Series XX     due 2000.................    200,000       200,000
      7 7/8%   Series A      due 2001.................    160,000             -
      6 1/8%   Series B      due 2004.................    140,000       140,000
      7 3/8%   Series TT     due 2019.................     20,000        20,000
      7 1/2%   Series YY     due 2023.................    100,000       100,000
      8 1/2% Series C due 2024........................    115,000       115,000
      7 7/8% Series D due 2024........................    140,000       140,000
      7 3/8% Series ZZ       due 2025.................    125,000       125,000

               Total First Mortgage Bonds.............  1,452,288     1,297,245

      Pollution Control Notes:
        Variable rate, due 2016-2022..................     46,400        46,400
        Tax exempt, due 2028-2031.....................    377,500       315,500
      Fees and interest due for spent
        fuel disposal costs (Note 1M).................    157,968       149,978
      Other...........................................     10,915        20,286
      Less amounts due within one year................    204,116         9,372
      Unamortized premium and discount, net...........     (6,550)       (7,391)

        Long-term debt, net........................... $1,834,405    $1,812,646



     Long-term debt and cash sinking-fund requirements on debt outstanding at
     December 31, 1996 for the years 1997 through 2001 are approximately $204.1
     million, $20.0 million, $239.0 million, $200.0 million, and $160.0 million,
     respectively.  In addition, there are annual one-percent sinking- and
     improvement-fund requirements, currently amounting to $14.5 million for
     1997, $12.6 million for 1998, $12.4 million for 1999, $10.0 million for
     2000, and $8.0 million for 2001. Such sinking- and improvement-fund
     requirements may be satisfied by the deposit of cash or bonds or by
     certification of property additions.

     All or any part of each outstanding series of first mortgage bonds may be
     redeemed by the company at any time at established redemption prices plus
     accrued interest to the date of redemption, except certain series which are
     subject to certain refunding limitations during their respective initial
     five-year redemption periods.

     Essentially all of the company's utility plant is subject to the lien of
     its first mortgage bond indenture.  As of December 31, 1996 and 1995, the
     company has secured $315.5 million of pollution control notes with second
     mortgage liens on Millstone 1, junior to the lien of its first mortgage
     bond indenture.  The average effective interest rate on the variable-rate
     pollution control notes ranged from 3.4 percent to 3.6 percent for 1996 and
     from 3.8 percent to 4.0 percent for 1995.

     On January 23, 1997, the letter of credit associated with CL&P's $62
     million tax-exempt PCRBs, issued on May 21, 1996, was replaced with a bond
     insurance and liquidity facility secured by First Mortgage Bonds.  The
     bonds were originally backed by a five-year letter of credit and secured by
     a second mortgage on CL&P's interest in Millstone 1.

8.   INCOME TAX EXPENSE
     The components of the federal and state income tax provisions charged to
     operations are:


     For the Years Ended December 31,          1996        1995           1994
                                                   (Thousands of Dollars)

      Current income taxes:
        Federal............................ $ 30,650      $ 93,906     $108,371
        State..............................    9,789        37,898       39,966

          Total current....................   40,439       131,804      148,337


      Deferred income taxes, net:
        Federal............................  (38,680)       52,075       44,180
        State..............................  (14,726)        5,085          842

          Total deferred...................  (53,406)       57,160       45,022
      Investment tax credits, net..........   (7,367)       (7,640)      (7,358)

          Total income tax expense......... $(20,334)     $181,324     $186,001



      The components of total income tax expense are classified as
      follows:

      Income taxes charged to
        operating expenses................. $(20,174)     $178,346     $190,249
      Other income taxes...................     (160)        2,978       (4,248)

      Total income tax expense............. $(20,334)     $181,324     $186,001


     Deferred income taxes are comprised of the tax effects of   temporary
     differences as follows:


     For the Years Ended December 31,             1996         1995      1994
                                                   (Thousands of Dollars)

     Depreciation, leased nuclear fuel,
       settlement credits and
       disposal costs...................       $  3,981      $44,278   $ 38,874
     Energy adjustment clauses..........         (1,654)      23,302     14,465
     Demand-side management.............        (17,099)       1,310        203
     Nuclear plant deferrals............        (18,861)      (8,055)   (20,452)
     Bond redemptions...................         (1,789)      (2,255)     6,826
     Contractual settlements............          2,513       (9,496)       109
     Nuclear compliance reserves........        (21,131)        -          -
     Other..............................            634        8,076      4,997

     Deferred income taxes, net.........       $(53,406)     $57,160   $ 45,022



     A reconciliation between income tax expense and the expected tax expense at
     the applicable statutory rate is as follows:



    For the Years Ended December 31,              1996        1995      1994
                                                     (Thousands of Dollars)

     Expected federal income tax at
       35 percent of pretax income......       $(35,931)    $135,289   $134,501
     Tax effect of differences:
       State income taxes, net of
         federal benefit................         (3,209)      27,939     26,526
       Depreciation.....................         21,313       23,517     18,602
       Deferred nuclear plants return...           (444)      (1,639)    (4,681)
       Amortization of
         regulatory assets .............          8,601       20,218     19,755
       Property tax.....................           -            (159)     5,286
       Investment tax credit
         amortization...................         (7,367)      (7,640)    (7,358)
       Adjustment for prior years'
         taxes..........................           -         (10,442)    (2,706)
       Other, net.......................         (3,297)      (5,759)    (3,924)
                                       
     Total income tax expense...........       $(20,334)    $181,324   $186,001



9.   EMPLOYEE BENEFITS

     A.   PENSION BENEFITS

          The company participates in a uniform noncontributory defined benefit
          retirement plan covering all regular system employees.  Benefits are
          based on years of service and the employees' highest eligible
          compensation during 60 consecutive months of employment.  The
          company's direct portion of the system's pension income, part of which
          was credited to utility plant, approximated $8.8 million in 1996,
          $10.4 million in 1995 and $2.3 million in 1994.  The company's pension
          costs for 1996, 1995, and 1994 included approximately $2.8 million,
          $0.1 million, and $4.8 million, respectively, related to workforce
          reduction programs.

          Currently, the company funds annually an amount at least equal to that
          which will satisfy the requirements of the Employee Retirement Income
          Security Act and the Internal Revenue Code.  Pension costs are
          determined using market-related values of pension assets.  Pension
          assets are invested primarily in domestic and international equity
          securities and bonds.

          The components of net pension cost for CL&P are:

          For the Years Ended December 31,     1996          1995        1994
                                                   (Thousands of Dollars)

          Service cost....................   $ 11,896     $  7,543    $ 13,072
          Interest cost...................     37,226       37,110      36,103
          Return on plan assets...........   (103,248)    (138,582)      1,020
          Net amortization................     45,300       83,516     (52,536)

          Net pension income..............   $ (8,826)    $(10,413)   $ (2,341)

          For calculating pension cost, the following assumptions were used:

          For the Years Ended December 31,      1996        1995        1994


          Discount rate...................      7.50%       8.25%       7.75%
          Expected long-term
            rate of return................      8.75        8.50        8.50
          Compensation/progression
            rate..........................      4.75        5.00        4.75


          The following table represents the plan's funded status reconciled to
          the Consolidated Balance Sheets:



          At December 31,                            1996           1995
                                                   (Thousands of Dollars)

          Accumulated benefit obligation,
            including vested benefits at
            December 31, 1996 and 1995 of
            $405,340,000 and $404,540,000,
            respectively......................    $434,473         $432,987



          Projected benefit obligation........    $514,989         $515,121
          Market value of plan assets.........     736,448          668,929

          Market value in excess of projected
            benefit obligation................     221,459          153,808
          Unrecognized transition amount......      (7,365)          (8,285)
          Unrecognized prior service costs....       3,818            1,293
          Unrecognized net gain...............    (198,088)        (135,817)
          
          Prepaid pension asset...............    $ 19,824         $ 10,999


          The following actuarial assumptions were used in calculating the
          plan's year-end funded status:



          At December 31,                              1996          1995


          Discount rate..........................     7.75%           7.50%
          Compensation/progression rate..........     4.75            4.75


     B.  POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

       The company provides certain health care benefits, primarily medical
       and dental, and life insurance benefits through a benefit plan to
       retired employees (referred to as SFAS 106 benefits).  These benefits
       are available for employees retiring from the company who have met
       specified service requirements.  For current employees and certain
       retirees, the total SFAS 106 benefit is limited to two times the 1993
       per-retiree health care costs.  The SFAS 106 obligation has been
       calculated based on this assumption.  CL&P's direct portion of SFAS
       106 benefits, part of which were deferred or charged to utility plant,
       approximated $17.9 million in 1996, $20.7 million in 1995 and $22.3
       million in 1994.

       During 1996 and 1995, the company funded SFAS 106 postretirement costs
       through external trusts. The company is funding, on an annual basis,
       amounts that have been rate-recovered and which also are tax
       deductible under the Internal Revenue Code.  The trust assets are
       invested primarily in equity securities and bonds.


       The components of health care and life insurance cost are:



       For the Years Ended December 31,         1996        1995       1994
                                                  (Thousands of Dollars)

       Service cost .......................    $ 2,270     $ 2,248     $ 2,371
       Interest cost ......................     10,211      11,510      12,157
       Return on plan assets ..............     (2,904)     (1,015)          2
       Amortization of unrecognized
         transition obligation ............      7,344       7,344       7,344
       Other amortization, net ............        956         602         430

       Net health care and life
         insurance costs ..................    $17,877     $20,689     $22,304


       For calculating SFAS 106 benefit costs, the following assumptions were
       used:


       For the Years Ended December 31,          1996        1995        1994


       Discount rate ......................      7.50%       8.00%       7.75%
       Long-term rate of return -        
       Health assets, net of tax ..........      5.25        5.00        5.00
         Life assets ......................      8.75        8.50        8.50


       The following table represents the plan's funded status reconciled to
       the Consolidated Balance Sheets:

       At December 31,                                      1996          1995
                                                        (Thousands of Dollars)
       Accumulated postretirement
         benefit obligation of:
        Retirees ....................................     $109,299     $126,624
        Fully eligible active employees .............          165          198
        Active employees not eligible
          to retire .................................       27,913       29,798

       Total accumulated postretirement
         benefit obligation .........................      137,377      156,620

       Market value of plan assets ..................       38,783       11,378

       Accumulated postretirement benefit
         obligation in excess of
         plan assets ................................      (98,594)    (145,242)

       Unrecognized transition amount ...............      117,506      124,850

       Unrecognized net (gain)/loss .................      (18,912)       1,260

       Accrued postretirement benefit
         liability ..................................     $      0     $(19,132)


       The following actuarial assumptions were used in calculating the plan's
       year-end funded status:

       At December 31,                                       1996         1995

       Discount rate ...........................              7.75%       7.50%
       Health care cost trend rate (a) .........              7.23        8.40

       (a)  The annual growth in per capita cost of covered health care
            benefits was assumed to decrease to 4.91 percent by 2001.

       The effect of increasing the assumed health care cost trend rate by one
       percentage point in each year would increase the accumulated
       postretirement benefit obligation as of December 31, 1996, by $7.6
       million and the aggregate of the service and interest cost components
       of net periodic postretirement benefit cost for the year then ended by
       $600,000. The trust holding the health plan assets is subject to
       federal income taxes at a 39.6 percent tax rate.  CL&P is currently
       recovering SFAS 106 costs.

10.  SALE OF CUSTOMER RECEIVABLES

   CL&P has entered into an agreement to sell up to $200 million of eligible
   customer billed and unbilled accounts receivable. The eligible receivables
   are sold with limited recourse.  The agreement was entered into during
   July, 1996 and will expire in five years. The company has retained
   collection responsibilities for receivables which have been sold under the
   agreement. The agreement provides for a loss reserve determined by a
   formula which reflects credit exposure.  As of February 21, 1997, CL&P has
   sold approximately $10 million of their accounts receivable under this
   agreement.
 
   The FASB issued SFAS 125, "Accounting for Transfers and Servicing of
   Financial Assets and Extinguishments of Liabilities," in June, 1996.  SFAS
   125 became effective on January 1, 1997, and establishes, in part, criteria
   for concluding whether a transfer of financial assets in exchange for
   consideration should be accounted for as a sale or as a secured borrowing.
   CL&P is in the process of restructuring its receivables program to comply
   with the requirements of SFAS 125.  Management believes that the adoption
   of SFAS 125 will not have a material impact on the company's financial
   position or results of operations.

11.  COMMITMENTS AND CONTINGENCIES

     A.RESTRUCTURING
       Although CL&P continues to operate under cost-of-service based
       regulation, various restructuring initiatives in its jurisdiction have
       created uncertainty with respect to future rates and the recovery of
       strandable investments and certain future costs such as purchase power
       obligations.  Strandable investments are regulatory assets or other
       assets that would not be economical in a competitive environment.
       Management is unable to predict the ultimate outcome of restructuring
       initiatives; however, it believes that it is entitled to full recovery
       of its prudently incurred costs, including regulatory assets and
       strandable investments based on the general nature of public utility
       cost of service regulation. For further information on restructuring,
       see the MD&A.

     B.NUCLEAR PERFORMANCE
       Millstone:  The three Millstone units are managed by NNECO. Millstone
       1, 2, and 3 have been out of service since November 4, 1995, February
       21, 1996 and March 30, 1996, respectively, and are on the Nuclear
       Regulatory Commission's (NRC) watch list.  The company has restructured
       its nuclear organization and is currently implementing comprehensive
       plans to restart the units.

       According to the plans, each unit's recovery team will be working
       towards restart of its respective unit on a parallel basis with the
       other two units.  Based upon management's current plans, it is
       estimated that one of the units will be ready for restart in the third
       quarter of 1997 with the other two units being ready for restart during
       the fourth quarter of 1997 and the first quarter of 1998, respectively.

       The NRC has also issued two orders affecting the Millstone units on the
       subjects of independent corrective action verification and employee
       concerns.  Independent third parties have been retained by NNECO and
       are awaiting NRC approval.

       Prior to and following notification to the NRC that the units are ready
       to resume operations, the NRC staff will conduct extensive reviews and
       inspections and, prior to such notification, independent corrective
       action verification teams will also inspect each unit.  The units will
       not be allowed to restart without an affirmative vote of the NRC
       commissioners following completion of these reviews and inspections.
       Management cannot estimate when the NRC will allow any of the units to
       restart, but hopes to have at least one unit operating in the second
       half of 1997.

       The company is currently incurring substantial costs, including
       replacement power costs, while the three Millstone units are not
       operating.  Management does not expect to recover a substantial portion
       of these costs.  CL&P expensed approximately $143 million of
       incremental nonfuel nuclear operation and maintenance costs (O&M) in
       1996, including a reserve of $50 million against 1997 expenditures.
       Management estimates CL&P will expense approximately $309 million of
       nonfuel O&M costs in 1997.

       As discussed above, management cannot predict when the NRC will allow
       any of the Millstone units to return to service and thus cannot
       estimate the total replacement power costs the companies will
       ultimately incur. Replacement power costs for CL&P are expected to
       average approximately $30 million per month during 1997 while all three
       Millstone units remain out of service. Management believes the system
       has sufficient resources to fund the restoration of the Millstone units
       to service under its present timetable.

       MY:  The system companies rely on MY for approximately two percent of
       their capacity.  The MY nuclear generating plant has been limited to
       operating at 90 percent of capacity since early 1996, pending the
       resolution of issues related to investigations initiated by the NRC,
       and on December 6, 1996, was taken off line to resolve cable-separation
       and associated issues. The NRC has notified MY that the NRC staff has
       placed the MY plant on its watch list.  Returning the plant to service
       will require NRC approval. Management cannot predict when MY's plant
       will be allowed to return to service and expects there will be
       substantial costs associated with the NRC's actions that cannot be
       accurately estimated at this time.

       Potential Litigation:  The non-NU owners of Millstone 3 have been
       paying their share of the monthly costs for Millstone 3 since the unit
       went out of service in March, 1996, but have reserved their rights to
       contest whether the NU system companies have any responsibility for the
       additional costs the non-NU owners have borne as a result of the
       current outage.  No formal claims have been made, but management
       believes that it is possible that some or all of the non-NU owners will
       assert liability on the part of the NU system.  CL&P and WMECO, through
       NNECO as  agent, operate Millstone 3 at cost, and without profit, under
       a Sharing Agreement that obligates them to utilize good utility
       operating practice and requires the joint owners to share the risk of
       employee negligence and other risks pro rata in accordance with their
       ownership shares.  The Sharing Agreement provides that CL&P and WMECO
       would only be liable for damages to the non-NU owners for a deliberate
       breach of the Sharing Agreement.  At December 31, 1996, the costs
       related to this potential litigation were estimated to be $10.5 million
       for incremental O&M costs and between $32 million and $40 million for
       replacement power costs.  These costs are likely to increase as long as
       Millstone 3 remains out of service.  NU will vigorously contest such
       suits if they are brought.

     C.ENVIRONMENTAL MATTERS
       CL&P is subject to regulation by federal, state and local authorities
       with respect to air and water quality, the handling and disposal of
       toxic substances and hazardous and solid wastes, and the handling and
       use of chemical products.  CL&P has an active environmental auditing
       and training program and believes that it is in substantial compliance
       with current environmental laws and regulations.

       Environmental requirements could hinder the construction of new
       generating units, transmission and distribution lines, substations, and
       other facilities. Changing environmental requirements could also
       require extensive and costly modifications to CL&P's existing
       generating units and transmission and distribution systems, and could
       raise operating costs significantly.  As a result, CL&P may incur
       significant additional environmental costs, greater than amounts
       included in cost of removal and other reserves, in connection with the
       generation and transmission of electricity and the storage,
       transportation and disposal of by-products and wastes.  CL&P may also
       encounter significantly increased costs to remedy the environmental
       effects of prior waste handling activities. The cumulative long-term
       cost impact of increasingly stringent environmental requirements cannot
       accurately be estimated.

       CL&P has recorded a liability based upon currently available
       information for what it believes are its estimated environmental
       remediation costs for waste disposal sites.  In most cases, additional
       future environmental cleanup costs are not reasonably estimable due to
       a number of factors, including the unknown magnitude of possible
       contamination, the appropriate remediation methods, the possible
       effects of future legislation or regulation and the possible effects of
       technological changes.  At December 31, 1996, the net liability
       recorded by CL&P for its estimated environmental remediation costs,
       excluding any possible insurance recoveries or recoveries from third
       parties, amounted to approximately $7.5 million, which management has
       determined to be the most probable amount within the range of $7.5
       million to $14.0 million.

       CL&P cannot estimate the potential liability for future claims,
       including environmental remediation costs, that may be brought against
       it. However, considering known facts, existing laws and regulatory
       practices, management does not believe the matters disclosed above will
       have a material effect on CL&P's financial position or future results
       of operations.

       On October 10, 1996, the American Institute of Certified Public
       Accountants issued Statement of Position 96-1, "Environmental
       Remediation Liabilities" (SOP).  The principal objective of the SOP is
       to improve the manner in which existing authoritative accounting
       literature is applied by entities to specific situations of
       recognizing, measuring and disclosing environmental remediation
       liabilities.  The SOP became effective January 1, 1997.  The company
       believes that the adoption of this SOP will not have a material impact
       on the company's financial position or results of operations.


     D.NUCLEAR INSURANCE CONTINGENCIES
       Under certain circumstances, in the event of a nuclear incident at one
       of the nuclear facilities covered by the federal government's third-
       party liability indemnification program, the company could be assessed
       in proportion to its ownership interest in each nuclear unit up to $75.5
       million, not to exceed $10.0 million per nuclear unit in any one year.
       Based on its ownership interest in Millstone 1, 2, and 3 and in Seabrook
       1, CL&P's maximum liability, including any additional potential
       assessments, would be $173.6 million per incident.  In addition, through
       power purchase contracts with MY, VY and CY, CL&P would be responsible
       for up to an additional $44.4 million per incident.  Payments for CL&P's
       ownership interest in nuclear generating facilities would be limited to
       a maximum of $27.5 million per incident per year.

       Insurance has been purchased to cover the primary cost of repair,
       replacement or decontamination of utility property resulting from
       insured occurrences.  CL&P is subject to retroactive assessments if
       losses exceed the accumulated funds available to the insurer.  The
       maximum potential assessment against CL&P with respect to losses arising
       during the current policy year is approximately $10.4 million under the
       primary property insurance program.

       Insurance has been purchased to cover certain extra costs incurred in
       obtaining replacement power during prolonged accidental outages and the
       excess cost of repair, replacement, or decontamination or premature
       decommissioning of utility property resulting from insured occurrences.
       CL&P is subject to retroactive assessments if losses exceed the
       accumulated funds available to the insurer.  The maximum potential
       assessments against the company with respect to losses arising during
       current policy years are approximately $9 million under the replacement
       power policies and $20.4 million under the excess property damage,
       decontamination and decommissioning policies. The cost of a nuclear
       incident could exceed available insurance proceeds.

       Insurance has been purchased aggregating $200 million on a industry
       basis for coverage of worker claims.  All participating reactor
       operators insured under this coverage are subject to retrospective
       assessments of $3 million per reactor.  The maximum potential assessment
       against CL&P with respect to losses arising during the current policy
       period is approximately $8.9 million.

     E.  CONSTRUCTION PROGRAM
       The construction program is subject to periodic review and revision by
       management.  CL&P currently forecasts construction expenditures of
       approximately $842 million for the years 1997-2001, including $165
       million for 1997.  In addition, the company estimates that nuclear fuel
       requirements, including nuclear fuel financed through the NBFT, will be
       approximately $238.4 million for the years 1997-2001, including $12.2
       million for 1997.  See Note 2, "Leases," for additional information
       about the financing of nuclear fuel.

   F.  LONG-TERM CONTRACTUAL ARRANGEMENTS
       Yankee Companies:  CL&P, along with PSNH and WMECO, relies on MY and VY
       for approximately three percent of their capacity under long-term
       contracts.  Under the terms of their agreements, the system companies
       pay their ownership (or entitlement) shares of costs, which include
       depreciation, O&M expenses, taxes, the estimated cost of decommissioning
       and a return on invested capital.  These costs are recorded as purchased
       power expense and recovered through the company's rates.  CL&P's total
       cost of purchases under contracts with the Yankee companies, excluding
       YAEC, amounted to $96.4 million in 1996, $105.8 million in 1995, and
       $102.1 million in 1994.  See Note 1E, "Summary of Significant Accounting
       Policies-Investments and Jointly Owned Electric Utility Plant," and Note
       3, "Nuclear Decommissioning," for more information on the Yankee
       companies.

       Nonutility Generators:  CL&P has entered into various arrangements for
       the purchase of capacity and energy from nonutility generators.  These
       arrangements have terms from 10 to 30 years, currently expiring in the
       years 2001 through 2027, and requires the company to purchase energy at
       specified prices or formula rates.  For the 12 months ended December 31,
       1996, approximately 13 percent of system electricity requirements was
       met by nonutility generators. CL&P's total cost of purchases under these
       arrangements amounted to $279.5 million in 1996, $282.2 million in 1995,
       and $277.4 million in 1994.  These costs are eventually recovered
       through the company's rates.

       Hydro-Quebec:  Along with other New England utilities, CL&P, PSNH,
       WMECO, and HWP have entered into agreements to support transmission and
       terminal facilities to import electricity from the Hydro-Quebec system
       in Canada.  CL&P is obligated to pay, over a 30-year period ending in
       2020, its proportionate share of the annual O&M and capital costs of
       these facilities.

       The estimated annual costs of CL&P's significant long-term contractual
       arrangements are as follows:


                           1997         1998      1999         2000      2001
                                           (Millions of Dollars)

   MY and VY ...........  $ 39.0       $ 33.1     $ 39.1      $ 38.9     $ 36.4
   Nonutility
     generators ........   274.0        281.0      291.0       291.0      294.0
   Hydro-Quebec ........    19.4         18.8       18.2        17.9       17.3



    G. THE ROCKY RIVER REALTY COMPANY - OBLIGATIONS
       RRR provides real estate support services which includes the leasing of
       property and facilities used by system companies.  RRR is the obligor
       under financing arrangements for certain system facilities.  Under those
       financing arrangements, the holders of notes for $38.4 million would be
       entitled to request that RRR repurchase the notes if any major
       subsidiary of NU (as defined by the notes) has debt ratings below
       investment grade as of any year-end during the term of the financing.
       The notes are secured by real estate leases between RRR as lessor and
       NUSCO as lessee.  The leases provide for the acceleration of rent equal
       to RRR's note obligations if RRR is unable to repay the obligation.  The
       operating companies, primarily CL&P, WMECO and PSNH may be billed by
       NUSCO for their proportionate share of the accelerated lease obligations
       if the rateholders request repurchase of the notes.  NU has guaranteed
       the notes.

       Based on the terms of the notes, PSNH and NAEC will be defined as major
       subsidiaries of NU, effective as of the end of 1996, and both PSNH's and
       NAEC's debt ratings were below investment grade.  Accordingly, under the
       terms of the RRR financing arrangements, the holders may elect to
       require RRR to repurchase the notes at par.  If the noteholders make
       such an election, RRR has the option to refinance the notes with an
       institutional investor.  However, it is possible that RRR may be
       required to repurchase the notes. As of February 21, 1997, the holders
       had not made such an election.  RRR plans to engage in discussions with
       the noteholders regarding this issue.  Management does not expect the
       resolution to have a material impact on its financial condition.

12.FUEL PRICE MANAGEMENT

   The company utilizes various financial instruments to manage well-defined
   fuel price risks.  The company does not use these instruments for trading
   purposes.

   CL&P uses fuel-price management instruments with financial institutions to
   hedge against some of the fuel-price risk created by long-term negotiated
   energy contracts.  These agreements minimize exposure associated with rising
   fuel prices and effectively fix a portion of CL&P's cost of fuel for these
   negotiated energy contracts.  Under the agreements, CL&P exchanges monthly
   payments based on the differential between a fixed and variable price for
   the associated fuel.  As of December 31, 1996, CL&P had outstanding
   agreements with a total notional value of approximately $228.8 million, and
   a positive mark-to-market position of approximately $1.1 million.

   These agreements have been made with various financial institutions, each of
   which is rated "A" or better by Standard & Poor's rating group.  CL&P is
   exposed to credit risk on fuel-price management instruments if the
   counterparties fail to perform their obligations. However, management
   anticipates that the counterparties will be able to fully satisfy their
   obligations under the agreements.

13.MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY

   In January 1995, CL&P Capital LP (CL&P LP is a subsidiary of CL&P) issued
   $100 million of cumulative 9.3 percent Monthly Income Preferred Securities
   (MIPS), Series A.  CL&P has the sole ownership interest in CL&P LP, as a
   general partner, and is the guarantor of the MIPS securities.  Subsequent to
   the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along
   with CL&P's $3.1 million capital contribution, back to CL&P in the form of
   an unsecured debenture. CL&P consolidates CL&P LP for financial reporting
   purposes.  Upon consolidation, the unsecured debenture is eliminated, and
   the MIPS securities are accounted for as minority interests.

14.FAIR VALUE OF FINANCIAL INSTRUMENTS

   The following methods and assumptions were used to estimate the fair value
   of each of the following financial instruments:

   Cash and nuclear decommissioning trusts:  The carrying amounts approximate
   fair value.

   SFAS 115, "Accounting for Certain Investments in Debt and Equity
   Securities," requires investments in debt and equity securities to be
   presented at fair value.  As a result of this requirement, the investments
   held in the company's nuclear decommissioning trusts were adjusted to market
   by approximately $22.3 million as of December 31, 1996 and by approximately
   $14.4 million as of December 31, 1995, with corresponding offsets to the
   accumulated provision for depreciation. The amounts adjusted in 1996 and
   1995, represent cumulative gross unrealized holding gains.  The cumulative
   gross unrealized holding losses were immaterial for both 1996 and 1995.

   Preferred stock and long-term debt:  The fair value of CL&P's fixed rate
   securities is based upon the quoted market price for those issues or similar
   issues.  Adjustable rate securities are assumed to have a fair value equal
   to their carrying value.


   The carrying amounts of CL&P's financial instruments and the estimated fair
   values are as follows:


                                                           Carrying      Fair
   At December 31, 1996                                     Amount      Value
                                                         (Thousands of Dollars)

     Preferred stock not subject
       to mandatory redemption......................    $  116,200   $  111,845

     Preferred stock subject to
       mandatory redemption.........................       155,000      120,900

     Long-term debt -
       First Mortgage Bonds.........................     1,452,288    1,410,665

       Other long-term debt.........................       592,783      592,783

     MIPS...........................................       100,000      108,520


                                                           Carrying      Fair
   At December 31, 1995                                     Amount      Value
                                                         (Thousands of Dollars)

     Preferred stock not subject
       to mandatory redemption......................    $  116,200   $   82,448

     Preferred stock subject to
       mandatory redemption.........................       155,000      157,575

     Long-term debt -
       First Mortgage Bonds.........................     1,297,245    1,329,549

       Other long-term debt.........................       532,164      532,164

     MIPS...........................................       100,000      108,520


   The fair values shown above have been reported to meet disclosure
   requirements and do not purport to represent the amounts at which those
   obligations would be settled.



To the Board of Directors
   of The Connecticut Light and Power Company:

We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company (a Connecticut corporation and a wholly
owned subsidiary of Northeast Utilities) and subsidiaries as of December
31, 1996 and 1995, and the related consolidated  statements of income,
common stockholder's equity and cash flows for each of the three years in
the period ended December 31, 1996.  These financial statements are the
responsibility of the Company's management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall  financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of The Connecticut Light
and Power Company and subsidiaries as of December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.





                                   /s/ ARTHUR ANDERSEN LLP
                                       ARTHUR ANDERSEN LLP




Hartford, Connecticut
February 21, 1997



MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



This section contains management's assessment of CL&P's (the company) financial
condition and the principal factors having an impact on the results of
operations. The company is a wholly-owned subsidiary of Northeast Utilities
(NU). This discussion should be read in conjunction with the company's
consolidated financial statements and footnotes.

FINANCIAL CONDITION

EARNINGS OVERVIEW
CL&P faced an extremely difficult year in 1996 as a result of the prolonged
outages at the three Millstone units (Millstone). These outages resulted in
significantly increased expenditures for replacement power and work undertaken
at Millstone, which resulted in a net loss for CL&P in 1996. In 1997, while all
three units are out of service, CL&P expects to continue operating at a loss.
The combination of higher expenditures and the uncertainty surrounding when the
units will return to service made it necessary to ensure that access to adequate
cash levels would be available for the duration of the outages. Management took
various actions during 1996 to address NU's nuclear program and liquidity
issues; however, 1997 will continue to be a serious challenge in these areas.

CL&P faces future uncertainty with the rapidly moving trend toward industry
restructuring. While restructuring had little direct impact on 1996 financial
results, it creates an environment of significant uncertainty and financial risk
for the coming years. As discussed in further detail in "Restructuring," the
financial treatment that strandable investments will be accorded will impact
CL&P's ability to compete in a restructured environment.

CL&P had a net loss of approximately $80 million in 1996, compared to net income
of approximately $205 million in 1995. The 1996 loss was primarily due to costs
related to the ongoing outages at Millstone which totaled approximately $400
million and reduced CL&P's 1996 earnings by approximately $232 million. These
costs included replacement power, higher 1996 Millstone operation and
maintenance costs, a reserve recognized in 1996 for 1997 expenditures to return
the Millstone units to service and costs associated with ensuring adequate
generating capacity. In addition, 1996 earnings decreased due to the impact of
CL&P's approved rate settlement agreement, higher recognition of cogeneration
costs and higher nonnuclear operation and maintenance costs. These decreases
were partially offset by higher retail sales and lower recognition of Millstone
3 phase-in costs.

Retail kilowatt-hour sales increased by 1.8 percent in 1996 as a result of
modest economic growth. In 1997, management expects that the Connecticut economy
will continue to experience modest economic growth.


MILLSTONE

OUTAGES
CL&P has an 81 percent ownership interest in Millstone 1 and 2 and a 52.93
percent ownership interest in Millstone 3. Millstone 1, 2 and 3 have been out of
service since November 4, 1995, February 21, 1996, and March 30, 1996,
respectively.

Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the Nuclear Regulatory Commission (NRC) has stated that the
units cannot return to service until independent, third-party verification teams
have reviewed the actions taken to improve the design, configuration and
employee concerns issues that prompted the NRC to place the units on its watch
list. Upon successful completion of these reviews, the NRC must approve the
restart of each unit through a formal commission vote.

Management took several key steps toward improving NU's nuclear program during
1996 and will continue to place a high priority on its recovery in 1997. The NU
Board of Trustees formed a committee in April, 1996, to provide high-level
oversight of the safety and effectiveness of NU's nuclear operations, progress
toward resolving open NRC issues and progress in resolving employee, community
and customer concerns. In September, 1996, Bruce D. Kenyon was appointed
President and Chief Executive Officer of Northeast Nuclear Energy Company
(NNECO), a wholly-owned subsidiary of NU that operates Millstone, and retired
Admiral David M. Goebel was selected to serve as Vice President for Nuclear
Oversight. In early 1997, Neil S. Carns was selected to serve as Senior Vice
President and Chief Nuclear Officer to oversee Millstone operations. Shortly
after his arrival, Mr. Kenyon unveiled a reorganization of NU's nuclear
organization that includes executives loaned from unaffiliated utility
companies. The new organization is intended to establish direct accountability
for performance at each of the nuclear units that the NU system operates and
includes a recovery team for each Millstone unit.

Under the new nuclear organization, each unit's recovery team will be working
toward restart of its respective unit simultaneously with the other two units.
Management estimates that one of the units will be ready for NNECO to request
the NRC's approval for restart in the third quarter of 1997, with the second and
third units ready in the fourth quarter of 1997 and the first quarter of 1998,
respectively. Subsequent to NNECO's request to restart any of the units, the NRC
will require a period of time to assess the results of the reviews performed by
the NRC and the independent third-party teams. Management cannot estimate when
the NRC will allow any of the units to restart, however, it hopes to have at
least one unit operating in the second half of 1997. A period of time will be
required subsequent to restart for each unit to return to operating at full
power.

Higher costs related to the Millstone outages will continue throughout 1997.
Monthly replacement power costs for CL&P are projected to average approximately
$30 million in 1997, while all three Millstone units remain out of service.
Replacement power costs for the Millstone units expensed in 1996 were $216
million, which was a substantial portion of the total 1996 replacement power
costs. CL&P will continue to expense its replacement power costs in 1997.
Nonfuel operation and maintenance costs for CL&P's share of Millstone to be
expensed in 1997 are estimated to be $309 million. A total of $322 million was
expensed in 1996 for nonfuel operation and maintenance costs for Millstone,
including $93 million for incremental costs related to the outages and $50
million reserved for future costs. Nonfuel operation and maintenance costs have
been, and will continue to be, absorbed through CL&P's current rates.

Although CL&P is not precluded from seeking rate recoveries in the future,
management has committed not to seek rate recovery for the portion of these
costs attributable to failure to meet industry standards in operating Millstone.
In light of that commitment, CL&P will not seek rate recovery for a substantial
portion of these costs. Management does not currently intend to request any such
recoveries until after the Millstone units begin returning to service;
therefore, it is unlikely that any additional revenues from any permitted
recovery of these costs will be available to contribute to funding the recovery
efforts while the units are out of service.

Under its present planning assumptions, management believes CL&P has sufficient
funds to restore the Millstone units to service and purchase replacement power.
See "Rate Matters" for further information on the recovery of outage-related
costs. See "Liquidity and Capital Resources" for further information regarding
CL&P's liquidity.

As a result of the nuclear situation, a number of civil lawsuits and criminal
investigations have been initiated, including litigation by NU's shareholders.
In addition, there is the potential for claims by the non-NU owners of Millstone
3 for the costs associated with the current outage. To date, no reserves have
been established for existing or potential litigation. See the "Notes to
Financial Statements" Note 11B, for further information on litigation.

CAPACITY
During 1996 and continuing into 1997, CL&P took measures to improve its capacity
position including obtaining additional generating capacity, improving the
availability of its generating units and improving its transmission capability.
During 1996, CL&P spent approximately $60 million to ensure adequate generating
capacity, of which $42 million was expensed. CL&P anticipates spending
approximately $47 million for additional capacity-related costs in 1997, of
which $27 million is expected to be expensed.

Assuming normal weather conditions and generating unit availability, management
expects that CL&P will have sufficient capacity to meet peak load demands even
if Millstone is not operational at any time through the summer of 1997. If there
are high levels of unplanned outages at other units in New England, or if any
transmission lines used to import power from other states are unavailable, at
times of peak load demand, CL&P and the other New England utilities may have to
resort to operating procedures designed to reduce customer demand. Uncertainties
associated with having sufficient capacity through the summer of 1997 include: a
Seabrook refueling outage scheduled for 49 days beginning on May 10, 1997; the
availability of Maine Yankee, which was put on the NRC's watch list in January,
1997, and is currently not expected to return to service earlier than late
summer 1997; and the timing of the repairs to the Long Island Cable, which is
capable of providing as much as 300 megawatts of transmission capability.

  
See the "Notes to Financial Statements" Note 11B, for further information on
Maine Yankee.

LIQUIDITY AND CAPITAL RESOURCES
During 1996, CL&P took various actions to ensure that it will have access to
adequate cash resources, at reasonable cost. CL&P issued two bonds totaling $222
million, one of which was issued in anticipation of the maturity of
approximately $193 million of bonds in April, 1997. CL&P established a facility
under which it may sell up to $200 million of its billed and unbilled accounts
receivable. As of February 21, 1997, $10 million had been sold using this
facility. Additionally, NU, CL&P and Western Massachusetts Electric Company
(WMECO) entered into a new $313 million three-year revolving credit agreement
(the New Credit Agreement). Under the New Credit Agreement, NU has a contractual
short-term borrowing limit of $150 million, CL&P has a limit of $313 million and
WMECO has a limit of $150 million. The overall limit for all borrowers is $313
million.

Management believes that the borrowing facilities that are currently in place
provide the system companies with adequate access to the funds needed to bring
Millstone back to service if the units begin operating close to the currently
envisioned schedules, and if the other assumptions on which management has based
its planning do not change substantially.

Some of the borrowing facilities contain financial covenants that must be
satisfied before borrowings can be made and for outstanding borrowings to remain
outstanding. Through February 21, 1997, CL&P and WMECO have satisfied all
financial covenants required under their respective borrowing facilities, but NU
needed and obtained a limited waiver of an interest coverage covenant that had
to be satisfied for NU to borrow under the New Credit Agreement.

NU, CL&P and WMECO are currently maintaining their access to the New Credit
Agreement under a written arrangement, which expires March 28, 1997, unless
extended by mutual consent, under which NU agreed not to borrow more than $27
million against the facility for a period of time. In addition, NU agreed to
enter into an interim written arrangement whereby NU, CL&P and WMECO will seek
regulatory approval for certain amendments in order to maintain access to the
New Credit Agreement through its maturity date. It is anticipated that these
amendments will include (i) CL&P and WMECO providing lenders first mortgage
bonds as collateral for specified periods and subject to specified terms for
releasing the collateral, (ii) revised financial covenants that are consistent
with NU's, CL&P's and WMECO's current financial forecasts and (iii) an upfront
payment to the lenders in order to maintain commitments under the New Credit
Agreement.

The holders of $38 million of notes issued by NU's real estate company (Rocky
River Realty Company or RRR) are entitled to require that RRR purchase the notes
because, as of December 31, 1996, Public Service Company of New Hampshire and
North Atlantic Energy Corporation  were rated below investment grade; these
notes are guaranteed by NU. NU is currently engaged in discussions with the
noteholders regarding this issue. See the "Notes to Financial Statements" Note
11G, for further information on these notes.

During 1996, Standard & Poor's Ratings Group (S&P) and Moody's Investors Service
(Moody's) downgraded all non-New Hampshire NU system securities at least once,
and in some cases twice, as a direct result of the Millstone outages. As of
December 31, 1996, the CL&P and WMECO first mortgage bonds were the only
securities on the NU system rated at investment grade. S&P and Moody's are
reviewing all NU system securities for further downgrades. These actions will
adversely affect the availability and cost of funds for the NU system companies.

Cash provided from operations decreased by approximately $229 million in 1996,
primarily due to higher cash operating costs related to the Millstone outages
and costs associated with ensuring adequate generating capacity, partially
offset by higher retail sales and lower income tax payments. Cash flows from
operations were also impacted by a sharp increase in the level of accounts
payable principally caused by costs related to a severe December storm and costs
associated with the Millstone outages that had not been paid by year end. Net
cash used for financing activities decreased by approximately $350 million in
1996, primarily due to higher long-term debt issuances, lower repayment of
short-term debt and lower common dividend payments. Cash used for investments
increased by approximately $122 million in 1996, primarily due to an increase in
investments under the NU system Money Pool.

If the return to service of one or more of the Millstone units is delayed
substantially, or if the needed waivers or modifications discussed above are not
forthcoming on reasonable terms, or if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions, or if the
system encounters additional significant costs or other significant deviations
from management's current assumptions, the currently available borrowing
facilities could be insufficient to meet all of the system's cash requirements.
In those circumstances, management would take actions to reduce costs and cash
outflows and would attempt to take other actions to obtain additional sources of
funds. The availability of these funds would be dependent upon the general
market conditions and the NU system's credit and financial condition at the
time.

See the "Notes to Financial Statements" Note 11E, 7 and 11F, for information on
construction, long-term debt funding and long-term contractual requirements.

RESTRUCTURING
The movement toward electric industry restructuring continues to gain momentum
nationally as well as within Connecticut. Factors that are driving the move
toward restructuring, in the Northeast in particular, include legislative and
regulatory actions and relatively high electricity prices. These actions will
impact the way that CL&P has historically conducted its business. Although CL&P
continues to operate under cost-of-service based regulation, various
restructuring initiatives in Connecticut have created uncertainty with respect
to future rates and the recovery of strandable investments. Strandable
investments are regulatory assets or other assets that would not be economical
in a competitive environment. CL&P has exposure to strandable investments for
its investment in high-priced nuclear generating plants, state mandated
purchased power arrangements that are priced above the market and significant
regulatory assets that represent costs deferred by state regulators for future
recovery. CL&P's exposure to strandable investments and purchased power
obligations exceed its shareholder's equity. CL&P's ability to compete in a
restructured environment would be negatively affected unless CL&P was able to
recover substantially all of these past investments and commitments.

In December, 1996, the legislative task force on electric utility industry
restructuring issued its final report. Although the report included several
legislative recommendations, the task force members did not reach a consensus on
a restructuring proposal. The legislative members of the task force submitted a
restructuring proposal which includes two alternatives:  one for retail
competition pilots available to 10 percent of the load in each rate class by
January 1, 1998, and a second for full retail competition beginning January1,
1998, unless CL&P has effected 10 percent rate reductions for all rate classes
by that date. This proposal, among others, will be considered in developing
restructuring legislation in 1997.

In response to the ongoing efforts in Connecticut to restructure the electric
utility industry, CL&P has developed a restructuring proposal that calls for
reduced rates for all Connecticut customers as soon as January, 1998; the
initiation of a retail choice pilot program as soon as July, 1998; phasing-in
all customers to retail choice over four years beginning in 2000; full recovery
of strandable investments through rate reduction bonds; and retaining ownership
of generating facilities. Management believes that it is entitled to full
recovery of its prudently incurred costs, including regulatory assets and other
strandable investments, based on the general nature of public utility industry
cost-of-service based regulation.

POTENTIAL ACCOUNTING IMPACTS
CL&P follows accounting principles in accordance with Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," that allows the economic effects of rate regulation to be
reflected. Under these principles, regulators may permit incurred costs for
certain events or transactions, which would be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered
through revenues at a later date.

If future competition or regulatory actions cause any portion of its operations
to no longer be subject to SFAS 71, CL&P would no longer be able to recognize
regulatory assets and liabilities for that portion of its business unless these
costs would be recoverable by a portion of the business remaining on cost-of-
service based regulation. Under its current regulatory environment, management
believes that CL&P's use of SFAS 71 remains appropriate.

If events create uncertainty about the recoverability of any of CL&P's remaining
long-lived assets, CL&P would be required to determine the fair value of its
long-lived assets, including regulatory assets, in accordance with SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The implementation of SFAS 121 did not have a material impact
on the company's financial position or results of operations as of December 31,
1996. Management believes it is probable that CL&P will recover its investments
in long-lived assets through future revenues. This conclusion may change in the
future as competitive factors influence wholesale and retail pricing in the
electric utility industry or if the cost-of-service based regulatory structure
were to change.

See the "Notes to Financial Statements" Note 1H, for further information on
regulatory accounting.

COMPETITION
In addition to legislative and regulatory actions, competition in the electric
utility industry continues to grow at a rapid pace as a result of technological
advances; relatively high electricity prices in certain regions of the country,
including New England; surplus generating capacity; and the increased
availability of natural gas. Competitive forces in the electric utility industry
have already caused some customers to choose alternative energy suppliers or
relocate outside of the CL&P's territory. In response, CL&P is preparing for a
competitive environment by expanding previously established programs and
developing new ways to fortify its relationships with existing customers and
attract new customers, both within and outside its service territory.

During 1996, CL&P continued to negotiate long-term power supply arrangements
with certain large commercial and industrial retail customers that require an
incentive to locate or expand their operations within CL&P's service territory,
are considering leaving or reducing operations in the service territory, are
facing short-term financial problems, or are considering generating their own
electricity. Approximately 10 percent of CL&P's commercial and industrial retail
revenues were under negotiated rate agreements at the end of 1996. These
negotiated rate reductions amounted to approximately $19 million in 1996 and
1995. These activities are expected to continue in 1997.

During 1996, the NU system devoted significantly more resources to its Retail
Marketing Organization, whose primary mission is to provide value added energy
solutions to customers. Training was emphasized for its 170 new employees, the
majority of whom are account executives charged with developing tailored
solutions for the NU system's customers and positioning NU as a valuable partner
for the future. The ability of these account executives to obtain an intimate
understanding of customers' needs and concerns and provide value added energy
solutions  will play a key role in the NU system's ability to effectively
compete in the future.

NU subsidiaries competed actively in two pilot retail access programs that were
initiated in New England in 1996. In New Hampshire, approximately 14,500
customers are participating in a two-year statewide pilot program. NU
subsidiaries introduced three energy and service product offerings under
different brand names and competed against 35 other energy suppliers. In
addition to exposing the NU system to a competitive environment, these pilots
have enabled the NU system to develop relationships with customers outside of
its service territory and to secure energy contracts with major commercial
customers.

Revenue erosion from traditional retail electric sales may be significant after
restructuring. While margins on retail electric sales are likely to be thin,
utilities can compete successfully if they are allowed to recover their
strandable investments. During 1997 and beyond, the NU system will continue to
participate in state sanctioned retail access programs; invest in new
unregulated businesses; develop new energy-related products and services; and
pursue strategic alliances with companies in various energy-related fields,
including fuel supply and management, power quality, energy efficiency and load
management services. Strategic alliances will allow NU subsidiaries to enter
markets that provide access to new product lines and technologies that
complement the NU system's current products and services.

RATE MATTERS
In July, 1996, the Department of Public Utility Control (DPUC) approved a rate
settlement agreement with CL&P (the Settlement). Under the Settlement, CL&P
froze base rates until at least December 31, 1997, accelerated the amortization
of regulatory assets by $73 million in 1996 and between $54 million and $68
million in 1997, and extended the depreciable lives of transmission and
distribution assets by ten years. Additionally, the Settlement terminated all
pending litigation, as of March 31, 1996, among the parties that could
potentially affect CL&P's rates. The Settlement does not impact costs incurred
subsequent to March 31, 1996, that are associated with the Millstone outages.
The Settlement reduced 1996 earnings by approximately $35 million. The impact on
1997 earnings is not expected to be significant.

In October, 1996, the DPUC issued a final order establishing an Energy
Adjustment Clause (EAC), which replaced both CL&P's fossil-fuel adjustment
clause and its generation utilization adjustment clause (GUAC). The EAC, which
is designed to calculate the difference between actual fuel costs and fuel costs
collected through base rates, took effect on January 1, 1997. The order includes
an incentive mechanism which disallows recovery of the first $9 million of
actual fuel costs in excess of base rate levels, but permits CL&P to retain the
first $9 million in actual fuel costs below base rate levels.

In January, 1997, the DPUC notified CL&P that it intends to conduct its prudence
review of nuclear cost issues in multiple phases, beginning immediately. The
first phase, covering the period April 1 through June 30, 1996, has already
begun. CL&P will not be permitted to collect any replacement power costs
associated with the current nuclear outages prior to the completion of the
DPUC's prudence reviews. Management does not expect to seek recovery of a
substantial portion of these costs.

NUCLEAR DECOMMISSIONING
CL&P has a 34.5 percent ownership interest in the Connecticut Yankee nuclear
generating facility (CY or the plant). On December 4, 1996, the CY Board of
Directors voted unanimously to cease permanently the production of power at the
plant. The decision to retire CY from commercial operation was based on an
economic analysis of the costs of operating it compared to the costs of closing
it and incurring replacement power costs over the remaining period of the
plant's operating license, which expires in 2007. The economic analysis showed
that closing the plant and incurring replacement power costs produced
substantial savings.

CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December, 1996, CY filed an amendment to its power
contracts with the Federal Energy Regulatory Commission (FERC) to clarify the
obligations of its purchasing utilities following the decision to cease power
production. At December 31, 1996, CL&P's share of these obligations was
approximately $263 million, including the cost of decommissioning and the
recovery of existing assets. Management expects that CL&P will continue to be
allowed to recover such FERC-approved costs from its customers.  Accordingly,
CL&P has recognized its share of the estimated costs as a regulatory asset, with
a corresponding obligation, on its Balance Sheets.

CL&P's estimated cost to decommission its shares of Millstone 1, 2 and 3 and
Seabrook is approximately $858 million in year end 1996 dollars. These costs are
being recognized over the lives of the respective units with a portion being
currently recovered through rates. As of December 31, 1996, the market value of
the contributions already made to the decommissioning trusts, including their
investment returns, was approximately $297 million.

See the "Notes to Financial Statements" Note 3, for further information on
nuclear decommissioning, including CL&P's share of costs to decommission the
regional nuclear generating units.

ENVIRONMENTAL MATTERS
CL&P is potentially liable for environmental cleanup costs at a number of sites
inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of CL&P. At December 31, 1996, CL&P had recorded
an environmental reserve of approximately $7 million, the most probable amount
as required by SFAS 5, "Accounting for Contingencies."

See the "Notes to Financial Statements" Note 11C, for further information on
environmental matters.

RISK MANAGEMENT INSTRUMENTS
CL&P uses fuel-price management instruments to reduce a portion of the fuel-
price risk associated with certain of its long-term negotiated energy contracts.
These instruments are not used for trading purposes. The differential paid or
received as fuel prices change is recognized in income when realized. As of
December 31, 1996, CL&P had outstanding fuel-price management instruments with a
total notional value of approximately $229 million. The settlement amounts
associated with the instruments reduced fuel expense by approximately $7.5
million for CL&P during 1996. CL&P's fuel-price management instruments seek to
minimize exposure associated with rising fuel prices and effectively fix the
cost of fuel and profitability of certain of its long-term negotiated contract
sales.

See the "Notes to Financial Statements" Note 12, for further information on
fuel-price management instruments.


RESULTS OF OPERATIONS

                                   Income Statement Variances
                                      (Millions of Dollars)
                              1996 over/(under)    1995 over/(under)

                                     1995                 1994

                               Amount    Percent    Amount   Percent

Operating revenues              $10         -%       $59        3%

Fuel, purchased and net
 interchange power              222        37         40        7
Other operation                 164        27         21        4
Maintenance                     107        56        (14)      (7)
Depreciation                      5         2         11        5
Amortization of regulatory
 assets, net                      3         6        (23)     (30)
Federal and state income
 taxes                         (202)       (a)        (5)      (3)
Deferred nuclear plants return
 (other and borrowed funds)      (5)      (78)       (14)     (69)
Other, net                        9        (a)        (4)     (77)
Minority interest in income
 of subsidiary                    1         7          9      100

Net income                     (285)       (a)         7        4


(a)  Percent greater than 100

OPERATING REVENUES
Total operating revenues increased in 1996, primarily due to higher retail sales
and regulatory decisions, partially offset by lower fuel recoveries and lower
wholesale revenues. Retail sales increased 1.8 percent ($29 million) primarily
due to modest economic growth in 1996. Regulatory decisions increased revenues
by $15 million primarily due to the mid-1995 retail rate increase, partially
offset by 1996 reserves for over-recoveries of demand side management costs.
Fuel recoveries decreased $24 million primarily due to lower average fossil fuel
prices. Wholesale revenues decreased $18 million primarily due to higher
recognition in 1995 of lump-sum payments for the termination of a long-term
contract and capacity sales contracts that expired in 1995.

Total operating revenues increased in 1995, primarily due to regulatory
decisions and higher fuel recoveries, partially offset by lower retail sales and
wholesale revenues. Revenues related to regulatory decisions increased $61
million primarily due to the effects of the mid-1994 and 1995 retail rate
increases and higher recoveries for demand side management costs. Fuel and
purchased power cost recoveries increased $25 million primarily due to higher
energy costs and the recovery of GUAC costs. Wholesale revenues decreased $16
million primarily due to capacity sales contracts that expired in 1994.

FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to replacement power due to the nuclear outages and the 1996 write-off of
GUAC balances under the Settlement, partially offset by lower nuclear generation
and the timing of the recognition of costs under the company's fuel clauses.

Fuel, purchased and net interchange power expense increased in 1995, primarily
due to higher fossil generation and higher priced outside energy purchases from
other utilities.

OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased in 1996, primarily due to
higher costs associated with the Millstone outages ($143 million, including $50
million reserved for future costs) and 1996 costs to ensure adequate generating
capacity ($39 million). In addition, these costs reflect higher storm and
reliability expenditures, higher recognition of conservation expenses and higher
marketing costs.

Other operation and maintenance expenses increased in 1995, primarily due to
higher recognition of conservation expense, higher recognition of postretirement
benefit costs and higher capacity charges from the regional nuclear generating
units, partially offset by higher reserves for excess/obsolete inventory in 1994
and lower maintenance costs at the fossil units.

DEPRECIATION
Higher plant balances and higher decommissioning levels in 1996, were partially
offset by longer depreciable lives of transmission and distribution assets under
the Settlement. Depreciation increased in 1995, primarily due to higher plant
balances and higher decommissioning levels.

AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 1996, primarily due to lower
cogeneration deferrals and the accelerated amortization of regulatory assets as
a result of the Settlement, partially offset by the completion of the Millstone
3 phase-in amortization in 1995.

Amortization of regulatory assets, net decreased in 1995, primarily due to
higher cogeneration deferrals in 1995 and the completion during 1994 of the
amortization of a 1993 cogeneration buyout, partially offset by higher 1995
amortization of Millstone 3 and Seabrook 1 phase-in costs.

FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased in 1996, primarily due to lower book
taxable income, partially offset by 1995 tax benefits from a favorable tax
ruling.

Federal and state income taxes decreased in 1995, primarily due to tax benefits
from a favorable tax ruling, partially offset by higher book taxable income.

DEFERRED NUCLEAR PLANTS RETURN
Although the change in 1996 was not significant, deferred nuclear plants return
decreased in 1995, primarily due to the completion of the Millstone 3 phase-in
in 1995.

OTHER, NET
Other, net increased in 1996, primarily due to higher income on temporary cash
investments in 1996.

Other, net decreased in 1995, primarily due to the 1993 property tax accounting
change as ordered in the 1993 CL&P rate decision. The allocation of this change
to customers occurred in 1994 and amortization began in 1995.

MINORITY INTEREST IN INCOME OF SUBSIDIARY
Although the change in 1996 was not significant, minority interest in income of
subsidiary increased in 1995, primarily due to the issuance of Monthly Income
Preferred Securities in 1995. See the "Notes to Financial Statements" Note 13,
for further information on these securities.


SELECTED FINANCIAL DATA   (a)

                          1996         1995      1994       1993         1992
                                            (Thousands of Dollars)

Operating Revenues.... $2,397,460  $2,387,069  $2,328,052 $2,366,050  $2,316,451

Operating Income......     29,773     324,026     286,948    241,655     288,088

Net (Loss) Income.....    (80,237)    205,216     198,288    191,449(b)  206,714

Cash Dividends on
  Common Stock........    138,608     164,154     159,388    160,365     164,277

Total Assets..........  6,244,036   6,045,631   6,217,457  6,397,405   5,582,831

Long-Term Debt (c)....  2,038,521   1,822,018   1,823,690  2,057,280   2,087,936

Preferred Stock Not
 Subject to Mandatory
 Redemption...........    116,200     116,200     166,200    166,200     231,196

Preferred Stock
 Subject to Mandatory
 Redemption(c)........    155,000     155,000     230,000    230,000     200,000

Obligations Under
 Capital Leases(c)....    155,708     172,264     175,969    177,418     197,404


STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)

                                              Quarter Ended(a)
1996                        March 31     June 30    September 30   December 31

Operating Revenues          $659,355     $542,999    $599,505       $ 595,601

Operating Income (Loss)     $ 59,977     $ 15,197    $    593       $ (45,994)

Net Income (Loss)           $ 32,851     $(10,700)   $(26,938)      $ (75,450)



1995

Operating Revenues          $601,194     $525,147    $638,392       $ 622,336

Operating Income            $ 96,191     $ 65,867    $ 88,012       $  73,956

Net Income                  $ 65,877     $ 38,089    $ 60,462       $  40,788



(a) Reclassifications of prior data have been made to conform with the current
    presentation.
    
(b) Includes the cumulative effect of change in accounting for municipal 
    property tax expense, which increased earnings for common shares by $47.7
    million.

(c) Includes portion due within one year.



STATISTICS

         Gross Electric                    Average
         Utility Plant                      Annual
          December 31,                     Use Per        Electric
         (Thousands of    kWh Sales     Residential     Customers     Employees
            Dollars)      (Millions)   Customer (kWh)   (Average)  (December 31)


1996       $6,512,659       26,043          8,639       1,099,340        2,194
1995        6,389,190       26,366          8,506(a)    1,094,527        2,270
1994        6,327,967       26,975          8,775       1,086,400        2,587
1993        6,214,401       26,107          8,519       1,078,925        2,676
1992        6,100,682       25,809          8,501       1,075,425        3,028

(a)  Effective January 1, 1996, the amounts shown reflect billed and
     unbilled sales. 1995 has been restated to reflect this change.