EXHIBIT 13.1



                                  EXHIBIT 13.1
                      NORTHEAST UTILITIES AND SUBSIDIARIES
                   AMENDED 1997 ANNUAL REPORT TO SHAREHOLDERS













                      Northeast Utilities and Subsidiaries
                          Amended 1997 Annual Report
                                   Index

Contents                                                                 Page



Company Report.......................................................     2

Report of Independent Public Accountants.............................     3

Consolidated Balance Sheets (Restated)...............................    4-5

Consolidated Statements of Income (Restated).........................     6

Consolidated Statements of Cash Flows (Restated).....................     7

Consolidated Statements of Shareholders' Equity (Restated)...........     8

Consolidated Statements of Capitalization (Restated).................     9

Notes to Consolidated Statements of Capitalization...................    10

Consolidated Statements of Income Taxes (Restated)...................    12

Notes to Consolidated Financial Statements (Restated)................    13

Management's Discussion and Analysis of Financial
Condition and Results of Operations (Restated).......................    48

Statement of Quarterly Financial Data (Restated).....................    64

Consolidated Generation Statistics...................................    64

Selected Consolidated Financial Data (Restated)......................    65

Consolidated Sales Statistics........................................    66




Company Report

The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.

The company has endeavored to establish a control environment that encourages
the maintenance of high standards of conduct in all of its business activities.
The company maintains a system of internal controls over financial reporting
which is designed to provide reasonable assurance to the company's management
and Board of Trustees regarding the preparation of reliable, published financial
statements. The system is supported by an organization of trained management
personnel, policies and procedures, and a comprehensive program of internal
audits. Through established programs, the company regularly communicates to its
management employees their internal control responsibilities and policies
prohibiting conflict of interest.

The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. This committee meets periodically with management, the internal
auditors and the independent auditors to review the activities of each and to
discuss audit matters, financial reporting and the adequacy of internal
controls.

Because of inherent limitations in any system of internal controls, errors or
irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation of
all financial statements, are reliable.

Report of Independent Public Accountants

To the Board of Trustees and Shareholders
of Northeast Utilities:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization, as restated - see Note 1, of Northeast Utilities
(a Massachusetts trust)  and subsidiaries as of December 31, 1997 and 1996, and
the related  consolidated statements of income, common shareholders' equity,
cash flows and income taxes, as restated - see Note 1, for each of the three
years in the period ended December 31, 1997.  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 Northeast Utilities and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.

As explained in Note 1 to the consolidated financial statements, the company has
given retroactive effect to the change in accounting for nuclear compliance
costs.



                                             /s/ ARTHUR ANDERSEN LLP
                                                 ARTHUR ANDERSEN LLP


Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in Note 1,
  as to which the date is June 10, 1998)


NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Balance Sheets

<TABLE>
<CAPTION>

----------------------------------------------------------------------------------------
                                                                     At December 31,
----------------------------------------------------------------------------------------
(Thousands of Dollars)                                            1997          1996
                                                               (Restated)    (Restated)
----------------------------------------------------------------------------------------
                                                               
<S>                                                           <C>           <C>
Assets
------
Utility Plant, at cost:
  Electric................................................... $ 9,869,561   $ 9,685,155
  Other......................................................     186,130       192,303
                                                              ------------  ------------
                                                               10,055,691     9,877,458
     Less: Accumulated provision for depreciation............   4,330,599     3,979,864
                                                              ------------  ------------
                                                                5,725,092     5,897,594
  Unamortized PSNH acquisition costs.........................     402,285       491,709
  Construction work in progress..............................     141,077       146,438
  Nuclear fuel, net..........................................     194,704       196,424
                                                              ------------  ------------
      Total net utility plant................................   6,463,158     6,732,165
                                                              ------------  ------------
Other Property and Investments:                                
  Nuclear decommissioning trusts, at market..................     502,749       403,544
  Investments in regional nuclear generating companies,        
    at equity................................................      86,955        85,340
  Investments in transmission companies, at equity...........      19,635        21,186
  Investments in Charter Oak Energy, Inc.....................         -          57,188
  Other, at cost.............................................      95,362        43,372
                                                              ------------  ------------
                                                                  704,701       610,630
                                                              ------------  ------------
Current Assets:                                                
  Cash and cash equivalents..................................     143,403       194,197
  Investments in securitizable assets........................     230,905           -
  Receivables,less accumulated provision for uncollectible     
    accounts of $2,052,000 in 1997 and $17,062,000 in 1996...     214,914       477,021
  Accrued utility revenues...................................      36,885       127,162
  Fuel, materials, and supplies, at average cost.............     212,721       211,414
  Recoverable energy costs, net--current portion.............      59,959         1,804
  Investments in Charter Oak Energy, Inc. held for sale......      33,391           -
  Prepayments and other......................................      38,495        55,318
                                                              ------------  ------------
                                                                  970,673     1,066,916
                                                              ------------  ------------
Deferred Charges:                                              
  Regulatory assets..........................................   2,173,278     2,221,839
  Unamortized debt expense...................................      38,758        38,146
  Other .....................................................      63,844        72,052
                                                              ------------  ------------
                                                                2,275,880     2,332,037

                                                              ------------  ------------
Total Assets................................................. $10,414,412   $10,741,748
                                                              ============  ============

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

NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Balance Sheets

<TABLE>
<Caption

------------------------------------------------------------------------------------------
                                                                       At December 31,
------------------------------------------------------------------------------------------
                                                                    1997          1996
(Thousands of Dollars)                                           (Restated)    (Restated)
------------------------------------------------------------------------------------------
        
<S>                                                             <C>           <C>
Capitalization and Liabilities:
-------------------------------
Capitalization: (See Consolidated Statements of Capitalization)
  Common shareholders' equity (See Note (a) - Consolidated
     Statements of Common Shareholders' Equity):
    Common shares, $5 par value--authorized 225,000,000
      shares;136,842,170 shares issued and 130,182,736
      shares outstanding in 1997 and 136,051,938 shares        
      issued and 128,444,373 shares outstanding in 1996........ $   684,211   $   680,260
    Capital surplus, paid in...................................     932,493       940,446
    Deferred contribution plan--employee stock ownership       
      plan (ESOP)..............................................    (154,141)     (176,091)
    Retained earnings (Note 1).................................     707,522       869,618
                                                                ------------  ------------
      Total common shareholders' equity........................   2,170,085     2,314,233
  Preferred stock not subject to mandatory redemption..........     136,200       136,200
  Preferred stock subject to mandatory redemption..............     245,750       276,000
  Long-term debt...............................................   3,645,659     3,613,681
                                                                ------------  ------------
      Total capitalization.....................................   6,197,694     6,340,114
                                                                ------------  ------------
Minority Interest in Consolidated Subsidiaries.................     100,000        99,972
                                                                ------------  ------------
Obligations Under Capital Leases...............................      30,427       186,860
                                                                ------------  ------------
Current Liabilities:                                           
  Notes payable to banks.......................................      50,000        38,750
  Long-term debt and preferred stock--current portion..........     274,810       319,503
  Obligations under capital leases--current portion............     177,304        19,305
  Accounts payable.............................................     402,870       507,139
  Accrued taxes................................................      46,016         7,050
  Accrued interest.............................................      30,786        51,386
  Accrued pension benefits.....................................      77,186        99,699
  Other........................................................      88,396        98,570
                                                                ------------  ------------
                                                                  1,147,368     1,141,402
                                                                ------------  ------------
Deferred Credits:                                              
  Accumulated deferred income taxes............................   1,984,513     2,070,225
  Accumulated deferred investment tax credits..................     158,837       168,444
  Deferred contractual obligations.............................     525,076       440,495
  Other........................................................     270,497       294,236
                                                                ------------  ------------
                                                                  2,938,923     2,973,400
                                                                ------------  ------------
Commitments and Contingencies (Note 8)                         
                                                               
Total Capitalization and Liabilities........................... $10,414,412   $10,741,748
                                                                ============  ============
</TABLE>

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

NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Statements of Income

<TABLE>
<CAPTION>

--------------------------------------------------------------------------------------------
                                                       For the Years Ended December 31,
--------------------------------------------------------------------------------------------
(Thousands of Dollars, except share                     1997          1996
  information)                                       (Restated)    (Restated)       1995
--------------------------------------------------------------------------------------------
         
<S>                                                <C>           <C>           <C>
Operating Revenues................................ $  3,834,806  $  3,792,148  $  3,750,560
                                                   ------------- ------------- -------------
Operating Expenses:                                 
  Operation --                                      
    Fuel, purchased and net interchange power.....    1,293,518     1,139,848       909,244
    Other.........................................    1,097,297     1,094,078       966,845
  Maintenance.....................................      501,693       415,532       288,927
  Depreciation....................................      354,329       359,507       354,293
  Amortization of regulatory assets, net..........      130,900       122,573       128,413
  Federal and state income taxes (See                              
   Consolidated Statements of Income Taxes).......       12,650        94,363       261,287
  Taxes other than income taxes...................      253,637       257,577       249,463
                                                   ------------- ------------- -------------
      Total operating expenses (Note 1)...........    3,644,024     3,483,478     3,158,472
                                                   ------------- ------------- -------------
Operating Income..................................      190,782       308,670       592,088
                                                   ------------- ------------- -------------
Other Income:                                       
  Deferred nuclear plants return--other funds.....        7,288         8,988        14,196
  Equity in earnings of regional nuclear            
    generating and transmission companies.........       11,306        13,155        13,208
  Other, net......................................      (38,473)       30,932        10,954
  Minority interest in income of subsidiary.......       (9,300)       (9,300)       (8,732)
  Income taxes....................................       10,702        (1,747)         (683)
                                                   ------------- ------------- -------------
      Other (loss)/ income, net...................      (18,477)       42,028        28,943
                                                   ------------- ------------- -------------
      Income before interest charges..............      172,305       350,698       621,031
                                                   ------------- ------------- -------------
Interest Charges:                                   
  Interest on long-term debt......................      282,095       285,463       315,862
  Other interest..................................        3,561         7,649         6,666
  Deferred nuclear plants return--borrowed funds..      (13,675)      (15,119)      (23,310)
                                                   ------------- ------------- -------------
      Interest charges, net.......................      271,981       277,993       299,218
                                                   ------------- ------------- -------------
     (Loss)/Income after interest charges.........      (99,676)       72,705       321,813
Preferred Dividends of Subsidiaries...............       30,286        33,776        39,379
                                                   ------------- ------------- -------------
Net (Loss)/Income (Note 1)........................ $   (129,962) $     38,929  $    282,434
                                                   ============= ============= =============
(Loss)/Earnings Per Common Share (Note 1)......... $      (1.01) $       0.30  $       2.24
                                                   ============= ============= =============
Common Shares Outstanding (average)...............  129,567,708   127,960,382   126,083,645
                                                   ============= ============= =============
</TABLE>

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

 NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
For the Years Ended December 31,                                    1997       1996       1995
                                                                 (Restated) (Restated)
------------------------------------------------------------------------------------------------
                                                                      (Thousands of Dollars)
<S>                                                              <C>        <C>        <C>
Operating Activities:                                           
  (Loss)/Income before preferred dividends of subsidiaries..... $ (99,676) $  72,705  $ 321,813
  Adjustments to reconcile to net cash                                       
   from operating activities:
    Depreciation...............................................   354,329    359,507    354,293
    Deferred income taxes and investment tax credits, net......    26,435     71,832    164,208
    Deferred nuclear plants return, net of amortization........   (13,781)   (14,948)    71,788
    Amortization of demand-side-management costs, net..........    38,029     26,941       (937)
    Recoverable energy costs, net of amortization..............   (54,102)   (14,289)   (27,874)
    Amortization of PSNH acquisition costs.....................    56,557     56,884     55,547
    Amortization of deferred cogeneration costs, net...........    32,700     25,957    (55,341)
    Deferred nuclear refueling outage, net of amortization.....   (36,514)    51,831    (29,569)
    Other sources of cash......................................   141,041    164,915    147,348
    Other uses of cash.........................................   (86,202)   (41,589)   (67,838)
  Changes in working capital:                                   
    Receivables and accrued utility revenues ..................   262,384    (31,992)   (72,081)
    Fuel, materials, and supplies..............................    (1,307)   (10,834)   (10,518)
    Accounts payable...........................................  (104,269)   188,101     38,096
    Accrued taxes..............................................    38,966    (68,168)    17,686
    Sale of receivables and accrued utility revenues...........    90,000          -          -
    Investments in securitizable assets........................  (230,905)         -          -
    Other working capital (excludes cash)......................   (36,464)   (21,383)    (2,458)
                                                                ---------- ---------- ----------
Net cash flows from operating activities (Note 1)..............   377,221    815,470    904,163
                                                                ---------- ---------- ----------

Financing Activities:                                           
  Issuance of common shares....................................     6,502     10,622     31,976
  Issuance of long-term debt...................................   260,000    222,150    225,100
  Issuance of Monthly Income                                                 
   Preferred Securities........................................      -          -       100,000
  Net increase/(decrease) in short-term debt...................    11,250    (60,250)   (91,000)
  Reacquisitions and retirements of long-term debt.............  (288,793)  (248,142)  (425,500)
  Reacquisitions and retirements of preferred stock............   (25,000)   (36,500)  (140,675)
  Cash dividends on preferred stock............................   (30,286)   (33,776)   (39,379)
  Cash dividends on common shares..............................   (32,134)  (176,277)  (221,701)
                                                                ---------- ---------- ----------
Net cash flows used for financing activities...................   (98,461)  (322,173)  (561,179)
                                                                ---------- ---------- ----------
Investment Activities:                                          
  Investment in plant:                                          
    Electric and other utility plant...........................  (233,399)  (222,829)  (231,408)
    Nuclear fuel...............................................    (6,852)   (14,529)   (18,261)
                                                                ---------- ---------- ----------
  Net cash flows used for investments in plant.................  (240,251)  (237,358)  (249,669)
  Investment in nuclear decommissioning trusts.................   (61,046)   (65,716)   (60,642)
  Other investment activities, net.............................   (28,257)   (25,064)   (30,761)
                                                                ---------- ---------- ----------
Net cash flows used for investments............................  (329,554)  (328,138)  (341,072)
                                                                ---------- ---------- ----------
Net (Decrease)/Increase In Cash For The Period.................   (50,794)   165,159      1,912
Cash and cash equivalents - beginning of period................   194,197     29,038     27,126
                                                                ---------- ---------- ----------
Cash and cash equivalents - end of period...................... $ 143,403  $ 194,197  $  29,038
                                                                ========== ========== ==========

Supplemental Cash Flow Information:                             
Cash paid/(refunded) during the year for:                       
  Interest, net of amounts capitalized......................... $ 291,335  $ 268,129  $ 321,148
                                                                ========== ========== ==========
  Income taxes................................................. $ (26,387) $  64,189  $ 108,928
                                                                ========== ========== ==========
Increase in obligations:                                        
  Niantic Bay Fuel Trust and other capital leases.............. $   3,475  $   3,524  $  41,388
                                                                ========== ========== ==========

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







                                                    
NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Statements of Shareholders' Equity
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                                         Capital     Deferred     Retained 
                                               Common    Surplus,  Contribution  Earnings (b)
                                              Shares(a)  Paid In    Plan--ESOP     (Note 1)      Total
---------------------------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                            <C>       <C>          <C>           <C>        <C>
Balance as of January 1, 1995............... $ 671,051  $904,371  $   (213,324) $    946,988  $2,309,086
                                             ---------- --------- ------------- ------------- -----------
   Net income for 1995......................                                         282,434     282,434
   Cash dividends on common shares--        
      $1.76 per share.......................                                        (221,701)   (221,701)
   Loss on retirement of preferred stock....                                            (381)       (381)
   Issuance of 1,400,940 common shares,     
     $5 par value...........................     7,005    24,971                                  31,976
   Allocation of benefits-- ESOP............                  70        15,172                    15,242
   Capital stock expenses, net..............               6,896                                   6,896
                                             ---------- --------- ------------- ------------- -----------
Balance as of December 31, 1995.............   678,056   936,308      (198,152)    1,007,340   2,423,552
                                             ---------- --------- ------------- ------------- -----------
   Net income for 1996 (Note 1).............                                          38,929      38,929
   Cash dividends on common shares--        
      $1.38 per share.......................                                        (176,277)   (176,277)
   Loss on retirement of preferred stock....                                            (374)       (374)
   Issuance of 440,772 common shares,       
     $5 par value...........................     2,204     8,418                                  10,622
   Allocation of benefits-- ESOP............              (8,103)       22,061                    13,958
   Capital stock expenses, net..............               3,077                                   3,077
   Currency translation adjustments.........                 746                                     746
                                             ---------- --------- ------------- ------------- -----------
Balance as of December 31, 1996 (Restated)..   680,260   940,446      (176,091)      869,618   2,314,233
                                             ---------- --------- ------------- ------------- -----------
   Net loss for 1997 (Note 1)...............                                        (129,962)   (129,962)
   Cash dividends on common shares--        
      $0.25 per share.......................                                         (32,134)    (32,134)
   Issuance of 790,232 common shares,                     
     $5 par value...........................     3,951     2,551                                   6,502
   Allocation of benefits-- ESOP............             (12,238)       21,950                     9,712
   Capital stock expenses, net..............               2,592                                   2,592
   Currency translation adjustments.........                (858)                                   (858)
                                             ---------- --------- ------------- ------------- -----------
Balance as of December 31, 1997 (Restated).. $ 684,211  $932,493  $   (154,141) $    707,522  $2,170,085
                                             ========== ========= ============= ============= ===========

(a) NU issued 8,430,910 warrants as part of its acquisition of PSNH. These warrants, which
    expired on June 5, 1997, entitled the holder to purchase one share of NU common stock at an
    exercise price of $24 per share. As of June 5, 1997, 464,678 shares had been purchased through
    the exercise of warrants.

(b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt
    agreements. These restrictions also limit the amount of retained earnings available for NU
    common dividends. At December 31, 1997, these restrictions totaled approximately $559.6 million.


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

NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                                                    At December 31,
-------------------------------------------------------------------------------------------------------
                                                                                    1997        1996
(Thousands of Dollars)                                                           (Restated)  (Restated)
<S>                                                                              <C>         <C>
-------------------------------------------------------------------------------------------------------
Common Shareholders' Equity (See Consolidated Balance Sheets).................. $2,170,085  $2,314,233
-------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subisidiaries:
  $25 par value--authorized 36,600,000 shares at December 31, 1997 and 1996;
    4,840,000 shares outstanding in 1997 and 5,840,000 shares outstanding in 1996
  $50 par value--authorized 9,000,000 shares at December 31, 1997 and 1996;
    5,424,000 shares outstanding in 1997 and 5,424,000 shares outstanding in 1996
  $100 par value--authorized 1,000,000 shares at December 31, 1997 and 1996;
    200,000 shares outstanding in 1997 and 1996
-------------------------------------------------------------------------------------------------------
                                      Current                    Current
Dividend Rates                   Redemption Prices(a)      Shares Outstanding
-------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
$50 par value--$1.90 to $3.28       $50.50 to $54.00            2,324,000......    116,200     116,200
$100 par value--$7.72               $103.51                       200,000......     20,000      20,000
-------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory Redemption......................    136,200     136,200
-------------------------------------------------------------------------------------------------------
Subject to Mandatory Redemption: (b)
$25 par value--$1.90 to $2.65       $25.00 to $25.64            4,840,000......    121,000     146,000
$50 par value--$2.65 to $3.615      $51.00 to $52.41            3,100,000......    155,000     155,000
-------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption..........................    276,000     301,000
Less:Preferred Stock to be redeemed within one year............................     30,250      25,000
-------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption,net............................    245,750     276,000
-------------------------------------------------------------------------------------------------------
Long-term Debt: (c)
First Mortgage Bonds--
Maturity            Interest Rates
-------------------------------------------------------------------------------------------------------
   1997               5.75% to 7.625%..........................................       -        207,988
   1998               6.50% to 9.17%...........................................    199,800     199,800
   1999               5.50% to 7.25%...........................................    279,000     279,000
   2000               5.75% to 6.875%..........................................    260,000     260,000
   2001               7.375% to 7.875%.........................................    220,000     160,000
   2002               7.75% to 9.05%...........................................    580,000     400,000
   2004               6.125%...................................................    140,000     140,000
   2019-2023          7.375% to 7.50%..........................................    120,000     120,000
   2024-2025          7.375% to 8.50%..........................................    430,000     430,000
-------------------------------------------------------------------------------------------------------
 Total First Mortgage Bonds                                                      2,228,800   2,196,788
-------------------------------------------------------------------------------------------------------
Other Long-Term Debt --(d)
   Pollution Control Notes and Other Notes--
   2000               Adjustable Rate (e) and 7.67%............................    218,033     224,182
   2005-2006          8.38% to 8.58%...........................................    194,000     210,000
   2013-2018          Adjustable Rate..........................................     33,400      33,400
   2020               Adjustable Rate..........................................     15,300      15,300
   2021-2022          7.50% to 7.65% and Adjustable Rate.......................    552,485     552,485
   2028               Adjustable Rate..........................................    369,300     369,300
   2031               Adjustable Rate..........................................     62,000      62,000
-------------------------------------------------------------------------------------------------------
 Total Pollution Control Notes and Other Notes.................................  1,444,518   1,466,667
Fees and interest due for spent nuclear fuel disposal costs (Note 2P)..........    205,502     195,023
Other..........................................................................     18,513      57,169
-------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt.....................................................  1,668,533   1,718,859
-------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net..........................................     (7,113)     (7,463)
-------------------------------------------------------------------------------------------------------
Total Long-Term Debt...........................................................  3,890,220   3,908,184
Less: Amounts due within one year..............................................    244,561     294,503
-------------------------------------------------------------------------------------------------------
Long-Term Debt, net............................................................  3,645,659   3,613,681
-------------------------------------------------------------------------------------------------------
Total Capitalization........................................................... $6,197,694  $6,340,114
=======================================================================================================

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


Notes to Consolidated Statements of Capitalization

(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.

(b) Changes in Preferred Stock Subject to Mandatory Redemption:

----------------------------------------------------------------------------
(Thousands of Dollars)
----------------------------------------------------------------------------
Balance at January 1, 1995 .............................. $ 379,675
Reacquisitions and Retirements ..........................   (75,675)
----------------------------------------------------------------------------
Balance at December 31, 1995 ............................   304,000
Reacquisitions and Retirements ..........................    (3,000)
----------------------------------------------------------------------------
Balance at December 31, 1996 ............................   301,000
Reacquisitions and Retirements ..........................   (25,000)
----------------------------------------------------------------------------
Balance at December 31, 1997 ............................ $ 276,000
============================================================================

The minimum sinking-fund requirements of the series subject each year to
mandatory redemption aggregate approximately $30.3 million in 1998, $46.3
million each year in 1999, 2000 and 2001 and $21.3 million in 2002. In case of
default on sinking-fund payments, 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 a subsidiary is in arrears in the payment of dividends
on any outstanding shares of preferred stock, the subsidiary is prohibited from
redeeming or purchasing less than all of the outstanding preferred stock.

(c) Long-term debt maturities and cash sinking-fund requirements, excluding
fees and interest due for spent nuclear fuel disposal costs, on debt outstanding
at December 31, 1997, for the years 1998 through 2002 are approximately $244.6
million, $375.9 million, $557.8 million, $313.2 million and $375.4 million,
respectively.

In addition, there are annual one percent sinking- and improvement-fund
requirements of approximately $1.5 million each year for 1998 and 1999 and $900
thousand each year for 2000 through 2002 for certain series of Western
Massachusetts Electric Company (WMECO) first mortgage bonds. The WMECO sinking-
and improvement-fund requirements may be satisfied by the deposit of cash or
bonds or by certification of property additions. The one percent sinking- and
improvement-fund requirements for The Connecticut Light and Power Company (CL&P)
first mortgage bonds are no longer required, as of 1997, as determined by a
majority of bond holders. Essentially all utility plant of CL&P, WMECO, Public
Service Company of New Hampshire (PSNH) and North Atlantic Energy Corporation
(NAEC), wholly owned subsidiaries of NU, is subject to the liens of each
company's respective first mortgage bond indenture.

NAEC's first mortgage bonds also are secured by payments made to NAEC by PSNH
under the terms of the Seabrook Power Contracts.

CL&P and WMECO have secured $369.3 million of pollution-control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.

CL&P and WMECO have issued $225 million and $90 million, respectively, of first
mortgage bonds as collateral to enable them to borrow under a three-year
revolving credit agreement. At December 31, 1997, CL&P and WMECO had $35 million
and $15 million, respectively, in borrowings under this agreement. PSNH's
Revolving Credit Facility has a second lien, junior to the lien of its first
mortgage bond indenture, on all PSNH property located in New Hampshire, which
will expire in April 1999. At December 31, 1997, PSNH had no borrowings under
the Revolving Credit Facility. For further information on these borrowing
facilities, see Note 4, "Short-Term Debt."

CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with
a bond insurance and liquidity facility secured by first mortgage bonds.

Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH
entered into financing arrangements with the Business Finance Authority (BFA) of
the state of New Hampshire. Pursuant to these arrangements, the BFA issued seven
series of PCRBs and loaned the proceeds to PSNH. At December 31, 1997, $516.5
million of the PCRBs were outstanding. PSNH's obligation to repay each series of
PCRBs is secured by a series of first mortgage bonds that were issued under its
indenture. Each such series of first mortgage bonds contains terms and
provisions with respect to maturity, principal payment, interest rate and
redemption that correspond to those of the applicable series of PCRBs. For
financial reporting purposes, these bonds would not be considered outstanding
unless PSNH fails to meet its obligations under the PCRBs.

(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.4 percent to 5.6 percent for 1997 and 3.2 percent to 5.5
percent for 1996.

(e) Interest-rate management instruments with financial institutions effectively
fix the interest rate of NAEC's $200 million variable-rate bank note at 7.823
percent. For further information, see Note 9, "Market Risk Management."



Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
                                                     For the Years Ended December 31,
--------------------------------------------------------------------------------------
                                                       1997        1996
(Thousands of Dollars)                              (Restated)  (Restated)     1995
--------------------------------------------------------------------------------------
<S>                                                    <C>        <C>         <C>
The components of the federal and state income tax
provisions (credited)/charged to operations are:
Current income taxes
  Federal......................................... $  (22,760) $   13,500  $   53,862
  State...........................................     (1,727)     10,778      43,900
--------------------------------------------------------------------------------------
Total current.....................................    (24,487)     24,278      97,762
--------------------------------------------------------------------------------------
Deferred income taxes, net
  Federal.........................................     46,871      90,093     167,091
  State...........................................    (10,841)     (8,667)      7,224
--------------------------------------------------------------------------------------
Total deferred....................................     36,030      81,426     174,315
--------------------------------------------------------------------------------------
Investment tax credits, net.......................     (9,595)     (9,594)    (10,107)
--------------------------------------------------------------------------------------
Total income tax expense (Note 1)................. $    1,948  $   96,110  $  261,970
======================================================================================
The components of total income tax expense are
classified as follows:
  Income taxes charged to operating expenses...... $   12,650  $   94,363  $  261,287
  Other income taxes..............................    (10,702)      1,747         683
--------------------------------------------------------------------------------------
Total income tax expense.......................... $    1,948  $   96,110  $  261,970
======================================================================================
Deferred income taxes comprise the tax effects of
temporary differences as follows:
  Depreciation, leased nuclear fuel, settlement
   credits and disposal costs..................... $   32,932  $   18,401  $   82,318
  Energy adjustment clauses.......................      5,916      (8,268)     26,851
  Nuclear plant deferrals.........................     13,989     (15,549)      2,666
  Contractual settlements.........................      1,754       2,513      (9,496)
  Bond redemptions................................     (4,260)     (4,685)      9,224
  Amortization of New Hampshire regulatory        
   settlement.....................................     11,501      11,501      11,501
  Deferred tax asset associated with net          
   operating losses...............................       -         96,756      57,543
  Demand-side management..........................    (12,169)    (14,954)        765
  State net operating loss carryforward...........     (7,670)       -           -
  Other...........................................     (5,963)     (4,289)     (7,057)
--------------------------------------------------------------------------------------
Deferred income taxes, net........................ $   36,030  $   81,426  $  174,315
======================================================================================
A reconciliation between income tax expense and
the expected tax expense at 35 percent of pretax
income:
Expected federal income tax....................... $  (34,205) $   59,085  $  204,324
Tax effect of differences:
  Depreciation....................................     22,049      24,337      25,639
  Deferred nuclear plants return..................     (2,551)     (3,146)     (4,969)
  Amortization of regulatory assets...............      5,498       7,910      20,389
  Amortization of PSNH acquisitions costs.........     31,298      31,410      31,522
  Seabrook intercompany loss......................     (4,616)     (7,503)    (13,048)
  Investment tax credit amortization..............     (9,595)     (9,594)    (10,107)
  State income taxes, net of federal benefit......     (7,839)      1,372      33,231
  Sale of Seabrook 2 steam generator..............       -         (2,516)       -
  Adjustment for prior years' taxes...............     (1,712)       (962)    (20,312)
  Employee stock ownership plan...................     (4,648)     (4,007)     (2,192)
  Dividends received deduction....................     (1,563)     (3,027)     (3,936)
  Loss reserve on sale of investment..............      8,750        -           -
  Other, net......................................      1,082       2,751       1,429
--------------------------------------------------------------------------------------
Total income tax expense.......................... $    1,948  $   96,110  $  261,970
======================================================================================

The accompanying notes are an integral part of these financial statements.
</TABLE>                                          
           
                  Notes to Consolidated Financial Statements


1.  Securities and Exchange Commission Inquiry

In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC)
inquired into Northeast Utilities' (NU or the company) accounting for nuclear
compliance costs.  These costs are the unavoidable incremental costs associated
with the current nuclear outages required to be incurred  prior to restart of
the units in accordance with correspondence received from the Nuclear Regulatory
Commission (NRC) early in 1996.  The SEC's view is that these unavoidable costs
associated with nuclear outages and procedures to be implemented at nuclear
power plants in response to regulatory requirements required prior to restart of
the units should be expensed as incurred. During 1996 and 1997,  NU and its
wholly owned subsidiaries, CL&P, PSNH and WMECO reserved for these unavoidable
incremental costs that they expected to incur to meet NRC standards.  The SEC
advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred.
While NU and its independent auditors, Arthur Andersen LLP, believed the
accounting was required by, and was in accordance with, generally accepted
accounting principles, the company has agreed to adjust its accounting for
nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings.  The
financial statements in this report have been restated to reflect the change in
accounting.

2. Summary of Significant Accounting Policies

A. About Northeast Utilities

NU is the parent company of the Northeast Utilities system (the NU system). The
NU system furnishes franchised retail electric service in Connecticut, New
Hampshire and western Massachusetts through four wholly owned subsidiaries:
CL&P, PSNH, WMECO and Holyoke Water Power Company (HWP). A fifth wholly
owned subsidiary, NAEC, sells all of its entitlement to the capacity and output
of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its
franchised retail service, the NU system furnishes firm and other wholesale
electric services to various municipalities and other utilities, and
participates in limited retail access programs, providing off-system retail
electric service. The NU system serves about 30 percent of New England's
electric needs and is one of the 25 largest electric utility systems in the
country as measured by revenues.

Several wholly owned subsidiaries of NU provide support services for the NU
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 NU system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
generating facilities. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibility for Seabrook. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by the NU system
companies. In addition, CL&P and WMECO each have established a special purpose
subsidiary whose business consists of the purchase and resale of receivables.

Charter Oak Energy, Inc. (COE), HEC, Inc. (HEC), Mode 1 Communications, Inc.
(Mode 1), and Select Energy, Inc., (formerly NUSCO Energy Partners, Inc.) are
other NU system companies which engage in a variety of activities.

Directly and through subsidiaries, COE has investments in cogeneration,
small-power production and other forms of nonutility generation as permitted
under the Public Utility Regulatory Policy Act, and in exempt wholesale
generators and foreign utility companies as permitted under the Energy Policy
Act of 1992 (Energy Act). These investments are accounted for on either a cost
or equity basis based upon COE's level of participation. NU has put COE up
for sale. For further information regarding the sale of COE, see Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A),
and Note 8G, "Commitments and Contingencies -- Sale of COE."

HEC provides energy management services for the NU system's and other utilities'
commercial, industrial and institutional electric customers. Mode 1 and Select
Energy, Inc. develop and invest in telecommunications and in energy-related
activities, respectively.

B. Presentation

The consolidated financial statements of the company 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.

C. Public Utility Regulation

NU is registered with the SEC as a holding company under the Public Utility
Holding Company Act of 1935 (1935 Act). NU and its subsidiaries are subject to
the provisions of the 1935 Act. Arrangements among the NU 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 operating
subsidiaries are subject to further regulation for rates, accounting and other
matters by the FERC and/or applicable state regulatory commissions.

For information regarding proposed changes in the nature of industry regulation,
see Note 8A, "Commitments and Contingencies -- Restructuring and Rate Matters."


D. New Accounting Standards

The Financial Accounting Standards Board (FASB) issued two new accounting
standards in February 1997: Statement of Financial Accounting Standards (SFAS)
128, "Earnings per Share" and SFAS 129, "Disclosure of Information about Capital
Structure." SFAS 128 establishes standards for computing and presenting earnings
per share (EPS) and is effective for 1997. The adoption of SFAS 128 did not have
a material impact on the company's EPS calculation and presentation. SFAS 129
establishes standards for disclosing information about an entity's capital
structure. NU's current disclosures are consistent with the requirements of SFAS
129.

During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and
SFAS 131, "Disclosures about Segments of an Enterprise and Related Information."
SFAS 130 establishes standards for the reporting and disclosure of comprehensive
income. To date, the NU system companies have not had material transactions that
would be required to be reported as comprehensive income. SFAS 131 determines
the standards for reporting and disclosing qualitative and quantitative
information about a company's operating segments. This information includes
segment profit or loss, certain segment revenue and expense items and segment
assets and a reconciliation of these segment disclosures to corresponding
amounts in the company's general purpose financial statements. The NU system
currently evaluates management performance using a cost-based budget, and the
information required by SFAS 131 is not  available. Therefore, these disclosure
requirements are not applicable. Management believes that the implementation of
SFAS 130 and SFAS 131 will not have a material impact on NU's current
disclosures.

See Note 7, "Sale of Customer Receivables and Accrued Utility Revenues," and
Note 8C, "Commitments and Contingencies -- Environmental Matters," for
information on other 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, PSNH and WMECO own common stock of
four regional nuclear generating companies (Yankee companies). The NU system's
investments in the Yankee companies are accounted for on the equity basis due to
NU's ability to exercise significant influence over their operating and
financial policies. The Yankee companies, with the NU system's equity
investments and ownership interests are:


----------------------------------------------------------------------------
(Thousands of Dollars Except for Percentages)
----------------------------------------------------------------------------
Connecticut Yankee Atomic
Power Company (CYAPC)                             $54,671       49.0%
Yankee Atomic Electric
Company (YAEC)                                      8,020       38.5
Maine Yankee Atomic
Power Company (MYAPC)                              15,699       20.0
Vermont Yankee Nuclear
Power Corporation (VYNPC)                           8,565       16.0
----------------------------------------------------------------------------
Total Equity Investment                           $86,955
============================================================================

Each Yankee company owns a single nuclear generating unit. Under the terms of
the contracts with the Yankee companies, the shareholders-sponsors are
responsible for their proportionate share of the costs of each unit, including
decommissioning. The energy and capacity costs from VYNPC and nuclear
decommissioning costs of the Yankee companies that have been shut down are
billed as purchased power to CL&P, PSNH and WMECO.

The electricity produced by the Vermont Yankee nuclear generating facility (VY)
is committed substantially on the basis of ownership interests and is billed
pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's  nuclear power
plants were shut down permanently on February 26, 1992, December 4, 1996, and
August 6, 1997, respectively. Under ownership agreements with the Yankee
companies, CL&P, PSNH and WMECO may be asked to provide direct or indirect
financial support for one or more of the companies. For more information on the
Yankee companies, see Note 3, "Nuclear Decommissioning," and Note 8F,
"Commitments and Contingencies -- Long-Term Contractual Arrangements."

Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a 660-
megawatt (MW) nuclear generating unit and Millstone 2, a 870-MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154-MW nuclear generating unit.

The three Millstone units are out of service. NU hopes to return Millstone 3 to
service in early spring of 1998 and Millstone 2 three to four months after
Millstone 3. Millstone 1 has been placed in extended maintenance status.
Management is reviewing its options with respect to Millstone 1, including
restart, early retirement and other options. In a draft ruling issued in
February 1998, the Connecticut Department of Public Utility Control (DPUC)
determined that Millstone 1 was no longer "used and useful" and ordered it
removed from rate base.

In 1996, one of the joint owners of Millstone 3, Vermont Electric Generation and
Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy. The subsequent
liquidation resulted in the offering of VEG&T's 0.035 percent share of Millstone
3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners
accepted the offer. During 1998, CL&P expects to make the necessary regulatory
filings to acquire ownership of VEG&T's share of Millstone 3.

For more information regarding the DPUC's action, see the MD&A. For more
information regarding the Millstone units see Note 3, "Nuclear Decommissioning,"
and Note 8B, "Commitments and Contingencies -- Nuclear Performance."

Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook 1 to PSNH under two long-term
contracts (the Seabrook Power Contracts).

Plant-in-service and the accumulated provision for depreciation for the NU
system's share of the three Millstone units and Seabrook 1 are as follows:

-----------------------------------------------------------------------------
                                               At December 31,
-----------------------------------------------------------------------------
(Millions of Dollars)                      1997              1996
-----------------------------------------------------------------------------
Plant-in-service
Millstone 1                             $  478.7          $  474.7
Millstone 2                                857.1             851.8
Millstone 3                              2,404.3           2,402.4
Seabrook 1                                 897.5             892.4

Accumulated provision for depreciation
Millstone 1                             $  212.1          $  196.6
Millstone 2                                306.7             275.8
Millstone 3                                695.1             633.3
Seabrook 1                                 150.0             131.7
=============================================================================

The NU system's share of Millstone and Seabrook 1 expenses are included in the
corresponding operating expenses on the accompanying Consolidated Statements of
Income.

Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
approximately $19.6 million, in two companies that transmit electricity imported
from the Hydro-Quebec system in Canada. The two companies own and operate
transmission and terminal facilities which have the capability of  importing up
to 2,000 MW from the Hydro-Quebec system. See Note 8F, "Commitments and
Contingencies -- Long-Term Contractual Arrangements," for additional
information.

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 3.8 percent in 1997, 1996 and 1995.  See Note 3, "Nuclear Decommissioning,"
for information on nuclear plant decommissioning.

The NU system'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, 1997
and 1996, the accumulated provision for depreciation included approximately
$83.2 million and $77.3 million, respectively, 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, commercial and industrial customers and limited 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. Regulatory
commissions also have authority over the terms and conditions of nontraditional
rate-making arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue an estimate for the amount of energy delivered but unbilled.

For information on rate proceedings and their potential impact on CL&P and
PSNH, see the MD&A.

H. Regulatory Accounting and Assets

The accounting policies of the operating companies 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 also may reduce or eliminate the value of an asset, or
create a liability. If any portion of the operating companies' 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 all of its related regulatory assets and
liabilities unless there is a formal transition plan which provides for the
recovery, through established rates, for the collection of approved stranded
costs and to maintain the cost-of-service basis for the remaining regulated
operations. At the time of transition, the operating companies would be required
to determine any impairment to the carrying costs of deregulated plant and
inventory assets.

Management anticipates that restructuring programs will be implemented within
each of the NU system operating companies' respective jurisdictions during the
next few years. In a restructured environment, the companies' generation
businesses no longer will be rate regulated on a cost-of-service basis. The
majority of NU's regulatory assets are related to its generation business.

The staff of the SEC has had concerns regarding the appropriateness of the
utilities' ability to continue application of SFAS 71 for the generation portion
of their business in a restructured environment. The SEC referred the issue to
the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and
issued "Deregulation of the Pricing of Electricity-Issues Related to the
Application of FASB Statements No. 71 and 101" (EITF 97-4). The EITF concluded:
(1) the future recognition of regulatory assets for the portion of the business
that no longer qualifies for application of SFAS 71 depends on the regulators'
treatment of the recovery of those costs and other stranded assets from cash
flows of other portions of the business still considered to be regulated, and
(2) a utility should discontinue the application of SFAS 71 when a legislative
and regulatory plan has been enacted, which would include transition plans
into a competitive environment, and when the stranded costs which are subject to
future rate recovery are determined. EITF 97-4 became effective in August 1997.

Electric utility industry restructuring within the state of Massachusetts will
be effective March 1, 1998. WMECO has submitted its proposed restructuring plan
to the Massachusetts Department of Telecommunications and Energy (DTE), formerly
the Massachusetts Department of Public Utilities. If the DTE approves the plan
in its current form, WMECO would discontinue the application of SFAS 71.
However, the restructuring legislation enacted by the state of Massachusetts
specifically provides for future deferrals and the cost recovery of generation-
related assets as contemplated under the plan. As such, WMECO is not expected to
have to write off either its generation-related assets or related regulatory
assets. WMECO's generation-related regulatory assets were valued at
approximately $188 million at December 31, 1997.

The issue of restructuring the electric utility industry in New Hampshire is
currently the focus of negotiations and proceedings within the federal and state
court systems.  Management believes that PSNH's use of regulatory accounting
remains appropriate while this issue remains in litigation.

The Connecticut General Assembly is addressing a proposal for electric industry
restructuring in the state of Connecticut during 1998. As the terms and
conditions to be contained within the restructuring plan cannot be determined at
this time, management believes that its use of regulatory accounting within this
jurisdiction remains appropriate.

The company expects that its transmission and distribution business within each
of its jurisdictions will continue to be rate regulated on a cost-of-service
basis and, accordingly, CL&P, WMECO and PSNH will continue to apply SFAS 71 to
this portion of their business.

For further information on the NU system companies' respective regulatory
environments and the potential impacts of restructuring, see Note 8A,
"Commitments and Contingencies -- Restructuring and Rate Matters" and the MD&A.

SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," 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 this revaluation is less than the book value of the asset,
an impairment loss would be charged to earnings.

Management continues to believe it is probable that the operating companies will
recover their investments in long-lived assets through future revenues. This
conclusion may change in the future as the implementation of restructuring plans
within the NU system companies' respective jurisdictions will generally require
the formation of separate generation entities that will be subject to
competitive market conditions. As a result, the NU system companies will be
required to assess the carrying amounts of their long-lived assets in accordance
with SFAS 121. The components of the NU system companies' regulatory assets are
as follows:

----------------------------------------------------------------------------
                                                      At December 31,
----------------------------------------------------------------------------
(Thousands of Dollars)                               1997         1996

Income taxes, net (Note 2I)                      $ 938,564    $1,012,343
Recoverable energy costs,
net (Note 2K)                                      324,809       328,863
Deferred costs -- nuclear
plants (Note 2L)                                   199,753       185,078
Unrecovered contractual
obligations (Note 3)                               515,076       435,495
Deferred demand-side
management costs (Note 2M)                          52,100        90,129
Cogeneration costs (Note 2N)                        33,505        66,205
Seabrook deferral (Note 2L)                          8,376          --
Other                                              101,095       103,726
---------------------------------------------------------------------------
                                                $2,173,278    $2,221,839
===========================================================================

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. See the Consolidated Statements of Income Taxes for the components
of income tax expense.


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

-----------------------------------------------------------------------------
                                                         At December 31,
-----------------------------------------------------------------------------
(Thousands of Dollars)                                  1997         1996
-----------------------------------------------------------------------------
Accelerated depreciation and
other plant-related
differences                                        $ 1,567,597   $ 1,640,068
Net operating loss
carryforwards                                         (102,492)      (94,149)
Regulatory assets --
income tax gross up                                    395,619       423,363
Other                                                  123,789       100,943
-----------------------------------------------------------------------------
                                                   $ 1,984,513   $ 2,070,225
=============================================================================

At December 31, 1997, PSNH had a net operating loss (NOL) carryforward of
approximately $293 million that can be used against PSNH's federal taxable
income and which, if unused, expires between the years 2000 and 2006. CL&P had a
state of Connecticut NOL carryforward of approximately $131 million that can be
used against CL&P and its affiliates' combined Connecticut taxable income and
which, if unused, expires in the year 2002. PSNH also had Investment Tax Credit
(ITC) carryforwards of $40 million which, if unused, expire between the years
1998 and 2004. For a portion of the carryforward amounts indicated above, the
reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code
limits the annual amount of PSNH NOL and ITC carryforwards that may be used.
Approximately $31 million of the NOL and $9 million of the ITC carryforwards are
subject to this limitation.

J. Unamortized PSNH Acquisition Costs

The unamortized PSNH acquisition costs represent the aggregate value placed by
the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on
PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets,
plus the $700 million value assigned to Seabrook by the Rate Agreement, as part
of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate
Agreement provides for the recovery through rates, with a return, of the
unamortized PSNH acquisition costs. The  Rate Agreement provides that $425
million of the unamortized PSNH acquisition costs be amortized over the first
seven years after PSNH's May 16, 1991 reorganization from bankruptcy
(Reorganization Date) with the remaining amount to be amortized over the 20-year
period after the Reorganization Date. The unrecovered balance of PSNH
acquisition costs at December 31, 1997, was approximately $402.3 million.  In
accordance with the Rate Agreement, approximately $32.9 million of this amount
will be recovered through rates by June 1, 1998, and the remaining amount of
approximately $369.4 million will be recovered through rates by 2011. As of
December 31, 1997, PSNH has collected approximately $591 million of acquisition
costs through rates.

K. Recoverable Energy Costs

Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed for
their proportionate shares 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, PSNH, WMECO and NAEC are currently recovering
these costs through rates. As of December 31, 1997, the company's total D&D
deferrals were approximately $63.7 million.

CL&P: During 1997, CL&P implemented an energy adjustment clause (EAC) under
which fuel prices above or below base-rate levels are charged or credited to
customers. The EAC replaced CL&P's fuel adjustment and generation utilization
adjustment clauses and is designed to reconcile and adjust the difference
between actual fuel costs and the fuel revenue collected through base rates on a
six-month basis.

For the period January 1, 1997 through June 30, 1997, CL&P agreed to a zero EAC
rate. For the period July 1, 1997 through December 31, 1997, the DPUC approved
an EAC rate through which CL&P recovered approximately $11.5 million
of deferred fuel costs. While this proceeding did not include provisions for the
recovery of approximately $18 million of costs related to the early closing of
CYAPC's nuclear generating unit, it did allow for the recovery of costs, subject
to refund, related to the closure of MYAPC's nuclear generating unit. CL&P has
appealed the DPUC's ruling related to CYAPC replacement power costs.

During December 1997, the DPUC approved an EAC rate for the period January 1,
1998 through June 30, 1998. During this period, CL&P will recover approximately
$27.9 million of deferred fuel costs.

At December 31, 1997, CL&P's net recoverable energy costs, excluding current net
recoverable energy costs, were approximately $104.8 million, which includes
approximately $50.1 million of costs related to CL&P's share of the D&D
assessment.

PSNH: The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period that began in May 1991, the retail portion of differences
between the fuel and purchased power costs assumed in the Rate Agreement and
PSNH's actual costs, which include the costs related to the Seabrook Power
Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are
subject to a prudence review by the New Hampshire Public Utilities Commission
(NHPUC).

Under the Rate Agreement, the deferred Seabrook return is being deferred by PSNH
and subsequently will be billed and collected by PSNH through the FPPAC. PSNH
began to defer the amount of these costs on December 1, 1997, and will continue
to do so for the period from December 1, 1997 through May 31, 1998. Beginning on
June 1, 1998, these costs will be recovered from PSNH customers over a 36-month
period. At December 31, 1997, PSNH has deferred approximately $8.4 million of
these costs.

On February 10, 1998, the NHPUC established a FPPAC rate for the period
December 1, 1997 through May 31, 1998. The new FPPAC rate increased customer
billings by approximately six percent. This rate continues to defer a
substantial portion of these costs.

At December 31, 1997, PSNH's net recoverable energy costs, excluding current net
recoverable energy costs, were approximately $191.7 million. This amount
includes approximately $172.9 million of deferred small power producer costs.

WMECO: WMECO has a fuel adjustment clause (FAC) which includes energy costs
along with capacity and transmission charges and credits that result from short-
term transactions with other utilities and from certain FERC-approved contracts
among the NU system's operating companies. The Massachusetts restructuring
legislation will effectively eliminate the FAC, effective March 1, 1998.

On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a
settlement agreement with the Massachusetts Attorney General which allowed WMECO
to recover approximately $15.3 million of fuel costs for the period September
1997 through February 1998.

At December 31, 1997, WMECO's net recoverable energy costs were approximately
$26.3 million, which includes approximately $11.3 million of costs related to
WMECO's share of the D&D assessment.

For further information on recoverable energy costs, see the MD&A.

L. Deferred Costs -- Nuclear Plants

As of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion
of its investment in Seabrook 1. This plan is in compliance with SFAS 92,
"Regulated Enterprises -- Accounting for Phase-in Plans." From the Acquisition
Date through November 1997, NAEC recorded $203.9 million of deferred return on
its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant
included $84.1 million of deferred return that was transferred as part of the
Seabrook plant assets to NAEC on the Acquisition Date. Beginning on December 1,
1997, the deferred return, including the portion transferred to NAEC, is
currently being billed through the Seabrook Power Contracts to PSNH and will be
fully recovered from customers by May 2001.

M. Demand-Side Management (DSM)

CL&P's DSM costs are recovered in base rates through a Conservation Adjustment
Mechanism. CL&P is allowed to recover DSM costs in excess of costs reflected in
base rates over periods ranging from approximately four to ten years.

During April 1997, the DPUC approved CL&P's DSM budget of $36 million for 1997.
In October 1997, CL&P and other interested parties filed a stipulation with the
DPUC requesting that the DPUC approve certain programs and establish a budget
level of $32.7 million for 1998 and $28.8 million for 1999. The $52.1 million of
DSM costs on CL&P's books as of December 31, 1997, currently being collected,
will be fully recovered by 2000.

N. CL&P 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 was applied to the deferred balance in 1997, as required under a
settlement agreement which CL&P reached with the DPUC. CL&P continues 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. At
December 31, 1997, CL&P's deferred cogeneration costs balance was approximately
$33.5 million.

O. Market Risk-Management Policies

The company utilizes market risk-management instruments, including swaps,
collars, puts and calls, to hedge well-defined risks associated with variable
interest rates and changes in fuel prices. To qualify for hedge treatment, the
underlying hedged item must expose the company to risks associated with market
fluctuations and the market risk-management instrument used must be designated
as a hedge and must reduce the company's exposure to market fluctuations
throughout the period.  Amounts receivable or payable under fuel-price
management instruments are recognized in operating revenues when realized.

Amounts receivable or payable under interest-rate management instruments are
accrued and offset against interest expense. The company does not use market
risk-management instruments for speculative purposes. For further information,
see Note 9, "Market Risk Management."

P. Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO and NAEC must pay
the United States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the selection
and development of repositories for, and 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. Until such payment is made, the  outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield Rate. At
December 31, 1997, fees due to the DOE for the disposal of prior-period fuel
were approximately $205.5 million, including interest costs of $123.4 million.

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. Extended
delays or a default by the DOE could lead to consideration of costly
alternatives. The company has primary responsibility for the interim storage of
its spent nuclear fuel. Current capability to store spent fuel at Millstone 1, 2
and Seabrook are estimated to be adequate until the years 2004 for Millstone 1
and 2 and 2010 for Seabrook. Storage facilities for Millstone 3 are expected to
be adequate for the projected life of the unit. Meeting spent fuel storage
requirements beyond these periods could require new and separate storage
facilities, the costs for which have not been determined.

In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled
that the lack of an interim storage facility does not excuse the DOE from
meeting its contractual obligation to begin accepting spent nuclear fuel no
later than January 31, 1998. Currently, the DOE has not taken the spent nuclear
fuel as scheduled and, as a result, may have to pay contract damages. The
ultimate outcome of this legal proceeding is uncertain at this time.

Q. Cash and Cash Equivalents

Cash and cash equivalents includes cash on hand and short-term cash  investments
which are highly liquid in nature and have original maturities of three months
or less.

3. Nuclear Decommissioning

Millstone and Seabrook: The NU system'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. Current decommissioning studies 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 Millstone 1 and 2, in year-end 1997
dollars, is $482.6 million and $432.2 million, respectively. The NU system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 in year-end 1997 dollars, is $377.4 million and $189.4 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 $48.8 million in 1997, $47.8 million in 1996
and $38.9 million in 1995. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on the Consolidated
Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated
reserve for depreciation amounted to $540.8 million and $435.7 million,
respectively.

CL&P and WMECO have established external decommissioning trusts through a
trustee for their portions of the costs of decommissioning Millstone 1, 2 and 3.
PSNH makes payments to an independent decommissioning trust for its portion of
the costs of decommissioning Millstone 3. CL&P's and NAEC's portions of the cost
of decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the estimated
decommissioning costs assumes levelized collections for the Millstone units and
escalated collections for Seabrook 1 and after-tax earnings on the Millstone and
Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent,
respectively.

As of December 31, 1997, CL&P, PSNH and WMECO collected through rates $277.9
million, $2.6 million and $59.7 million, respectively, toward the future
decommissioning costs of their share of  the Millstone units, of which $302.6
million has been transferred to external decommissioning trusts. As of December
31, 1997, CL&P and NAEC (including payments made prior to the Acquisition Date
by PSNH) paid approximately $2.9 million and $21.1 million, respectively, 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 depreciation. Unrealized gains and losses associated
with the decommissioning trusts and financing fund also impact the balance of
the trusts and the accumulated reserve for depreciation.

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, PSNH and WMECO attempt to recover sufficient amounts through their allowed
rates to cover their expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
regulatory agencies is reflected in rates of the NU system companies. Based on
present estimates and assuming its nuclear units operate to the end of their
respective license periods, the NU system expects that the decommissioning
trusts and financing fund will be substantially funded when the units are
retired from service.

Millstone 1 has been placed in extended maintenance status while management is
reviewing its options with respect to the unit. These include restart, early
retirement and other options. Relating to management's consideration of the
option to immediately retire Millstone 1 are certain Connecticut state law
issues. In its four-year rate review proceeding, the DPUC noted that CL&P may
not be able to obtain its remaining investment in Millstone 1 if it were to
determine that the unit had been prematurely shut down due to management
imprudence. Additionally, there is a Connecticut statute which may limit CL&P's
ability to collect future decommissioning charges related to Millstone 1 if
Millstone 1 were to be terminated before the end of its expected life.

At December 31, 1997, CL&P's net unrecovered Millstone 1 plant costs were $215.7
million and the remaining unrecovered decommissioning costs were approximately
$198 million.

Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share of
estimated costs, in year-end 1997 dollars, of decommissioning this unit is $80.8
million.

On August 6, 1997, the board of directors of MYAPC voted unanimously to cease
permanently the production of power at its nuclear generating facility (MY). The
NU system companies had relied on MY for approximately one percent of their
capacity. During November 1997, MYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. During January 1998, the FERC accepted the amendments
and proposed rates, subject to refund. At December 31, 1997, the remaining
estimated obligation, including decommissioning, amounted to approximately
$867.2 million, of which the NU system's share was approximately $173.4 million.

On December 4, 1996, the board of directors of CYAPC voted unanimously to cease
permanently the production of power at its nuclear generating plant (CY).
During 1996, the NU system companies had relied on CY for approximately three
percent of their capacity. During late December 1996, CYAPC filed an amendment
to its power contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. On February 27, 1997, the FERC
approved an order for hearing which, among other things, accepted CYAPC's
contract amendment. The new rates became effective March 1, 1997, subject to
refund. At December 31, 1997, the remaining estimated obligation, including
decommissioning, amounted to $619.9 million, of which the NU system's share was
approximately $303.7 million.

YAEC is in the process of decommissioning its nuclear facility.  At 
December 31, 1997, the estimated remaining costs, including decommissioning, 
amounted to $124.4 million, of which the NU system's share was approximately 
$47.9 million.

Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-
sponsor companies, including CL&P, WMECO and PSNH, are responsible for their
proportionate share of the costs of the units, including decommissioning.
Management expects that CL&P, PSNH and WMECO each will continue to be allowed to
recover these costs from their customers. Accordingly, CL&P, PSNH and WMECO have
recognized these costs as regulatory assets, with corresponding obligations.

Proposed Accounting: The staff of the SEC has questioned certain current
accounting practices of the electric utility industry, including NU, regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating units in the financial statements. In response to these
questions, the FASB has agreed to review the accounting for closure and removal
costs, including decommissioning. If current electric utility industry
accounting practices for nuclear power plant decommissioning are changed, the
annual provision for decommissioning could increase relative to 1997, and the
estimated cost for decommissioning could be recorded as a liability (rather than
as accumulated depreciation), with recognition of an increase in the cost of the
related nuclear power plant. Management believes that the operating companies
each will continue to be allowed to recover decommissioning costs through rates.

4. Short-Term Debt

Limits: The amount of short-term borrowings that may be incurred by the NU
system's utility companies is subject to periodic approval by either the SEC
under the 1935 Act or by their respective state regulators. SEC authorization
allowed CL&P, WMECO and NAEC, as of January 1, 1998, to incur total short-term
borrowings up to a maximum of $375 million, $150 million and $60 million,
respectively. In addition, the charter   of WMECO contains a provision which
restricts the total amount of unsecured debt that it may borrow at any one time.
As of January 1, 1998, this charter provision allowed WMECO to incur unsecured
borrowings, whether short-term or long-term, up to a maximum of approximately
$114 million. PSNH was authorized under a waiver from the NHPUC to incur short-
term borrowings up to a maximum of $125 million effective May 1997.

Credit Agreements: In May 1997, because of the potential for NU and CL&P to
violate their various financial ratio tests, NU amended the three-year revolving
credit agreement (Credit Agreement) with a group of 12 banks. Under the amended
Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability
of first mortgage bond collateral, up to $313.75 million and $150 million,
respectively. At December 31, 1997, CL&P and WMECO have issued first mortgage
bonds to enable borrowings under this facility up to a maximum of $225 million
and $90 million, respectively. NU, which cannot issue first mortgage bonds, will
be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet
certain interest coverage tests for two consecutive quarters. In addition, CL&P
and WMECO each must meet certain minimum quarterly financial ratios to access
the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter
ending December 31, 1997. The overall limit for all of the borrowing system
companies under the entire Credit Agreement is $313.75 million. The companies
are obligated to pay a facility fee of .50 percent per annum of each bank's
total commitment under this Credit Agreement, which will expire in November
1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million,
respectively, in borrowings under this Credit Agreement.

In February 1998, because of borrowing restrictions on NU in the amended Credit
Agreement, NU entered into a separate $25 million 364-day revolving credit
facility (Credit Facility) with one bank. NU is obligated to pay a facility fee
of .625 percent per annum on the unused commitment.

In addition to the Credit Agreement and Credit Facility, NU, CL&P, WMECO, HWP
and The Rocky River Realty Company (RRR) have various revolving credit
lines through separate bilateral credit agreements. Under this facility, four
banks maintain commitments to the respective companies totaling $56.25 million.
NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP
and RRR may borrow up to their SEC or board authorized short-term debt limit of
$5 million and $22 million, respectively. Under the terms of this facility, the
companies are obligated to pay a facility fee of .15 percent per annum of each
bank's total commitment. These commitments will expire in December 1998. At
December 31, 1997 and 1996, there were no borrowings and $11.3 million in
borrowings, respectively, under this facility.

PSNH has a $125 million revolving credit agreement that will expire in April
1999. The revolving credit agreement is with a group of 16 banks. PSNH is
obligated to pay a facility fee of .50 percent per annum on the commitment of
$125 million. At December 31, 1997 and 1996, there were no borrowings under the
facility.

Under the credit facilities discussed above, with the exception of the $25
million NU Credit Facility, the NU system companies may borrow funds on a short-
term revolving basis under their respective agreements, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding. Standby
loans are based upon several alternative variable rates. Loans advanced under
the $25 million NU Credit Facility are on a standby basis only. The weighted
average annual interest rate on the NU system companies' notes payable to banks
outstanding on December 31, 1997 and 1996 was 6.95 percent and 8.3 percent,
respectively. Maturities of short-term debt obligations were for periods of
three months or less.

For further information on short-term debt, including the ability to access
these agreements, see the MD&A.

5. Leases

CL&P and WMECO may finance up to $400 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 which is scheduled to
expire July 31, 1998. The NBFT capital lease agreement, which was amended in
February 1998, requires CL&P and WMECO to secure their obligation to repay the
NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue
these bonds by May 1998.

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. The NU
system companies also have 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.

Capital lease rental payments charged to operating expense were $19.0 million in
1997, $28.2 million in 1996 and $75.9 million in 1995. Interest included in
capital lease rental payments was $13.6 million in 1997, $14.1 million in 1996
and $15.0 million in 1995. Operating lease rental payments charged to expense
were $17.3 million in 1997, $18.3 million in 1996 and $20.9 million in 1995.

Future minimum rental payments, excluding executory costs such as property
taxes, state use taxes, insurance and maintenance, under long-term noncancelable
leases, as of December 31, 1997, are:

---------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------------------------------------------------------
                             Capital       Operating
Year                          Leases          Leases
---------------------------------------------------------------------------
1998                          $181,000      $ 25,800
1999                             8,500        23,200
2000                             7,900        21,000
2001                             5,800        16,500
2002                             3,200         8,000
After 2002                      54,900        26,600
---------------------------------------------------------------------------
Future minimum
lease payments                 261,300      $121,100
                                            ========
Less amount
representing interest           53,300
                              --------
Present value of future
minimum lease payments        $208,000
                              ========

6. Employee Benefits

A. Pension Benefits

The NU system's subsidiaries participate in a uniform noncontributory defined
benefit retirement plan covering all regular NU system employees. Benefits are
based on years of service and the employees' highest eligible compensation
during 60 consecutive months of employment. Total pension (credit)/cost, part of
which was (credited)/charged to utility plant, approximated $(22.5) million in
1997, $9.1 million in 1996 and $0.4 million in 1995. Pension (credit)/costs for
1997, 1996 and 1995 included approximately $(2.6) million, $7.8 million and
$6.8 million, respectively, related to workforce reduction programs.

Currently, the subsidiaries annually fund 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 (credit)/cost are:

----------------------------------------------------------------------------
                                  For the Years Ended December 31,
----------------------------------------------------------------------------
(Thousands of Dollars)               1997      1996        1995
----------------------------------------------------------------------------
Service cost                      $ 32,298   $ 43,206   $ 35,771
Interest cost                       98,621     94,722     89,351
Return on plan assets             (337,198)  (232,604)  (310,997)
Net amortization                   183,752    103,745    186,310
-----------------------------------------------------------------------------
Net pension (credit)/cost        $ (22,527)  $  9,069   $    435
=============================================================================

For calculating pension costs, the following assumptions were used:

-----------------------------------------------------------------------------
                                  For the Years Ended December 31,
-----------------------------------------------------------------------------
                                     1997      1996        1995
-----------------------------------------------------------------------------
Discount rate                        7.75%     7.50%       8.25%
Expected long-term
rate of return                       9.25      8.75        8.50
Compensation/progression rate        4.75      4.75        5.00
=============================================================================

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

----------------------------------------------------------------------------
                                                     At December 31,
----------------------------------------------------------------------------
(Thousands of Dollars)                             1997          1996
----------------------------------------------------------------------------
Accumulated benefit obligation
including vested benefits at
December 31, 1997 and 1996
of $(1,003,157,000) and
$(943,696,000), respectively                  $(1,106,850)   $(1,037,908)
----------------------------------------------------------------------------
Projected benefit obligation                  $(1,392,833)   $(1,321,146)
Market value of plan assets                     1,919,414      1,660,404
-----------------------------------------------------------------------------
Market value in excess of
projected benefit obligation                      526,581        339,258
Unrecognized transition
amount                                            (10,562)       (12,105)
Unrecognized prior service cost                    29,711         31,802
Unrecognized net gain                            (622,916)      (458,654)
----------------------------------------------------------------------------
Accrued pension liability                       $ (77,186)     $ (99,699)
=============================================================================

The following actuarial assumptions were used in calculating the plan's year-end
funded status:
----------------------------------------------------------------------------
                                                     At December 31,
----------------------------------------------------------------------------
                                                    1997          1996
-----------------------------------------------------------------------------
Discount rate                                       7.25%         7.75%
Compensation/progression rate                       4.25          4.75
=============================================================================

B. Postretirement Benefits Other Than Pensions

The NU system's subsidiaries provide 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 NU system 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 cost. The
SFAS 106 obligation has been calculated based on this assumption. Total SFAS 106
benefit costs, part of which were deferred or charged to utility plant,
approximated $28.3 million in 1997, $39.2 million in 1996 and $44.1 million in
1995. NU's subsidiaries are funding SFAS 106 postretirement costs through
external trusts. The subsidiaries are 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,
-----------------------------------------------------------------------------
(Thousands of Dollars)                         1997        1996      1995
-----------------------------------------------------------------------------
Service cost                                 $ 5,746     $ 7,457   $ 7,137
Interest cost                                 20,556      22,698    24,693
Return on plan assets                        (21,452)     (9,330)   (7,812)
Amortization of unrecognized
transition obligation                         15,134      15,134    15,134
Other amortization, net                        8,327       3,194     4,924
----------------------------------------------------------------------------
Net health care and life
insurance cost                              $ 28,311    $ 39,153  $ 44,076
============================================================================


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

-----------------------------------------------------------------------------
                                           For the Years Ended December 31,
-----------------------------------------------------------------------------
                                           1997         1996          1995
-----------------------------------------------------------------------------
Discount rate                              7.75%        7.50%         8.00%
Long-term rate of return --
Health assets, net of tax                  6.00         5.25          5.00
Life assets                                9.25         8.75          8.50
=============================================================================

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

-----------------------------------------------------------------------------
                                         At December 31,
----------------------------------------------------------------------------
(Thousands of Dollars)                               1997         1996
-----------------------------------------------------------------------------
Accumulated postretirement benefit obligation of:
Retirees                                          $(214,624)  $(226,774)
Fully eligible active
employees                                              (529)       (323)
Active employees
not eligible to retire                              (70,806)    (78,985)
----------------------------------------------------------------------------
Total accumulated postretirement
benefit obligation                                 (285,959)   (306,082)
Market value of plan assets                         129,434     105,086
----------------------------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets                                     (156,525)  (200,996)
Unrecognized transition
obligation                                          227,015    242,149
Unrecognized net gain                               (70,391)   (41,457)
----------------------------------------------------------------------------
Prepaid/(accrued) postretirement
benefit obligation                                $      99  $    (304)
============================================================================

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

-----------------------------------------------------------------------------
                                                       At December 31,
-----------------------------------------------------------------------------
                                                      1997         1996
----------------------------------------------------------------------------
Discount rate                                         7.25%        7.75%
Health care cost trend rate (a)                       5.76         7.23
=============================================================================
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 4.40 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, 1997, by $16.1 million and the aggregate
of the service and interest cost components of net periodic postretirement
benefit cost for the year then ended by $1.3 million. The trust holding the
health plan assets is subject to federal income taxes at a 39.6 percent tax
rate.

CL&P, PSNH and WMECO currently are recovering SFAS 106 costs through rates.

C. 401(k) Savings Plan

NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
The company matches, with company stock, employee contributions up to a maximum
of three percent of eligible compensation. The matching contributions made by
the company were $12.0 million for 1997, $11.8 million for 1996 and $12.1
million for 1995.

D. ESOP

NU maintains an ESOP for purposes of allocating shares to employees
participating in the NU system's 401(k) plan. Under this arrangement, NU issued
unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of
which were lent to the ESOP trust for purchase of approximately 10.8 million
newly issued NU common shares (ESOP shares). NU makes principal and interest
payments on the ESOP notes at the same rate that ESOP shares are allocated to
employees.

In 1997 and 1996, the ESOP trust issued approximately 948,000 and 953,000 of NU
common shares, respectively, to satisfy plan obligations to employees totaling
approximately $21.9 million and $22.1 million, respectively. These costs were
charged to the 401(k) plan. As of December 31, 1997 and 1996, the total
allocated ESOP shares were 4,140,751 and 3,192,620, respectively, and total
unallocated ESOP shares were 6,659,434 and 7,607,565, respectively. The fair
market value of unallocated ESOP shares as of December 31, 1997 and 1996 was
approximately $78.7 million and $99.8 million, respectively.

During 1997, the ESOP trust used approximately $3 million in dividends and $41
million in contributions from NU to meet principal and interest payments on ESOP
notes. During March 1997, NU's Board of Trustees suspended the quarterly
dividend on NU's common shares indefinitely, beginning with the second quarter
of 1997. Future principal and interest payments on ESOP notes will be fully
supported by contributions from NU until the dividend is restored.

E. Stock-Based Compensation

During 1997, certain key officers of the company were awarded nonvested stock
grants, totaling 25,700 shares, under which the officers pay nothing to receive
these shares. These officers must stay in employment of the company for a
specified period to receive the shares. During 1996, the same key officers of
the company were awarded nonvested stock grants, for a total of approximately
43,000 shares, for which again no payment was required. Under the 1996 programs,
certain shares became vested immediately with certain restrictions and others
became vested upon the meeting of specified performance goals within a limited
time period. Dividends accruing on the shares of each award are reinvested in
additional shares subject to the same provisions and restrictions. Under
these programs, approximately 3,400 shares were vested at December 31, 1997, and
December 31, 1996.

During August 1997, the company's Board of Trustees approved the granting of
500,000 stock options to the new Chief Executive Officer to purchase common
shares of NU common stock. The exercise price of these options is $9.625 per
share, which equaled the fair value of the company's common stock at the date of
grant. The exercise period for the options granted is ten years from the date of
grant, with vesting from the date of grant as follows: 50 percent after two
years, 75 percent after three years and 100 percent after four years.

The company accounts for its nonvested stock grants and stock options using the
intrinsic-value based method in accordance with Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," (APB 25) under which
approximately $238 thousand and $136 thousand of compensation costs were
recognized in 1997 and 1996, respectively, for the nonvested stock grants. No
compensation costs have been recognized for the stock options award as the
exercise price was equal to the market value of the stock on the date of grant.
In October 1995 the FASB issued SFAS 123, "Accounting for Stock-Based
Compensation," which defines a fair-value based method of accounting for stock-
based compensation. SFAS 123 allows companies to continue accounting for stock-
based compensation using APB 25 but requires pro forma net income and earnings
per share disclosures as if the fair-value based method of accounting under SFAS
123 had been used.

Had compensation costs of the options award been determined under the fair value
alternative method as stated in SFAS 123, the company's pro forma net loss for
the year ended December 31, 1997, would have been increased by approximately $73
thousand. The resulting pro forma impact on the company's loss per share for the
year was not material. The fair value of the options as of the date of grant was
determined using the Black-Scholes option pricing model with the following
assumptions: risk-free interest rate of  6.41 percent, expected life of 10.0
years, expected volatility of 31.89 percent and a dividend yield of 7.42
percent.

7. Sale of Customer Receivables and Accrued Utility Revenues

During 1996, CL&P and WMECO entered into agreements to sell up to $200 million
and $40 million, respectively, of undivided ownership interests in eligible
customer receivables and accrued utility revenues (receivables).

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. By October 31, 1997, both
CL&P and WMECO had restructured their respective sales agreements to comply with
the conditions of SFAS 125 and account for transactions occurring under these
programs as sales of assets. CL&P and WMECO have each established a special
purpose, wholly owned subsidiary whose business consists of the purchase and
resale of receivables. For receivables sold, both CL&P and WMECO have retained
collection responsibilities as agent for the purchaser under each company's
respective agreements. As collections reduce previously sold receivables,  new
receivables may be sold. At December 31, 1997, approximately $70 million and $20
million of receivables had been sold to third-party purchasers by CL&P and
WMECO, respectively, through the use of each company's special purpose, wholly
owned subsidiary, CL&P Receivables Corporation (CRC) and WMECO Receivables
Corporation (WRC). All receivables transferred to both CRC and WRC are assets
owned by CRC and WRC and are not available to pay CL&P's or WMECO's creditors.

For CRC's and WRC's respective sales agreements with the third-party purchasers,
the receivables were sold with limited recourse. Both CRC's and WRC's respective
sales agreements provide for a formula-based loss reserve in which additional
receivables may be assigned to the third-party purchasers for costs such
as bad debt. The third-party purchasers absorb the excess amount in the event
that actual loss experience exceeds the loss reserve. At December 31, 1997,
approximately $7.2 million and $3.0 million of assets had been designated as
collateral by CRC and WRC, respectively. These amounts represent the formula-
based amount of credit exposure at December 31, 1997. Historical losses for bad
debt for both CL&P and WMECO have been substantially less.

During December 1997, Moody's Investors Service downgraded the rating on WMECO's
first mortgage bonds. This downgrade brought WMECO's bond ratings to a level at
which the sponsor of WMECO's accounts receivable program can take various
actions, in its discretion, which would have the practical effect of limiting
WMECO's ability to utilize the facility. To date, the sponsor has not notified
WMECO that it will elect to exercise those rights, and the program is
functioning in its normal mode. The WMECO accounts receivable program could be
terminated if WMECO's first mortgage bond credit ratings experience one more
level of downgrade. CL&P's accounts receivable program could be terminated if
its senior secured debt is downgraded two more steps from its current ratings.

Concentrations of credit risk to the respective purchasers under each company's
agreements with respect to the receivables are limited due to CL&P's and WMECO's
diverse customer base within their respective service territories.

For additional information on accounts receivable programs and CL&P's and
WMECO's ability to utilize these programs, see the MD&A.

8. Commitments and Contingencies

A. Restructuring and Rate Matters

New Hampshire: The 1996 restructuring legislation that the NHPUC is charged with
implementing provides that the NHPUC may not adopt a restructuring plan that
imposes a severe financial hardship on a utility. Management believes that
PSNH is entitled to full recovery of its prudently incurred costs, including
regulatory assets and other strandable costs. It bases this belief both on the
general nature of public utility industry cost-of-service based regulation and
the specific circumstances of the resolution of PSNH's previous bankruptcy
proceedings and its acquisition by NU, including the recoveries provided by the
Rate Agreement and related agreements.

On February 28, 1997, the NHPUC issued its decision related to restructuring the
state's electric utility industry and setting interim stranded cost charges for
PSNH pursuant to legislation enacted in New Hampshire in 1996. In the decision,
the NHPUC announced a departure from cost-based ratemaking and instead adopted a
market-priced approach to ratemaking and stranded cost recovery. Accordingly,
unless the NHPUC modifies its position or the litigation described below results
in necessary modifications to the final plan which leads management to conclude
that the ratemaking approach utilized in the NHPUC's restructuring decision will
not go into effect, PSNH no longer will be subject to the provisions of SFAS 71.
That would result in PSNH writing off from its balance sheet substantially all
of its regulatory assets. The amount of the potential write-off triggered by the
order is currently estimated at over $400 million, after taxes. PSNH does not
believe that under the decision, it would be required to recognize any
additional loss resulting from the impairment of the value of its other long-
lived assets under the provisions of SFAS 121.

On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary restraining
order, preliminary and permanent injunctive relief and for declaratory judgment
in the United States District Court for New Hampshire (District Court). The case
was subsequently transferred to Rhode Island. On March 10, 1997, the Chief
Judge of the Rhode Island federal court issued a temporary restraining order
which stayed the NHPUC's February 28, 1997, decision to the extent it
established a rate-setting methodology that is not designed to recover PSNH's
costs of providing service and would require PSNH to write off any regulatory
assets.

During 1997, a mediation process ended without a resolution. The District Court
had suspended the procedural schedule associated with this court proceeding
pending the resolution of appeals of certain preliminary rulings by the U.S.
Circuit Court of Appeals for the First Circuit (First Circuit). On February 3,
1998, the First Circuit denied the appeals taken by would-be intervenors in
PSNH's federal court proceeding concerning the NHPUC's final plan on
restructuring. The First Circuit affirmed a previous court decision stating that
the opposing interests in this case were adequately represented by the NHPUC or
by PSNH. As a result of this decision, the proceedings in the District Court may
resume. On February 17, 1998, the NHPUC filed a petition for rehearing with the
First Circuit. The temporary restraining order issued by the District Court in
March 1997 will remain in effect until further orders by either court.

During 1997, the NHPUC reopened its proceeding to reconsider certain limited
matters in its restructuring orders. The scope of the PSNH-specific rehearing
proceedings included alternative rate-setting methodologies proposed by the
intervenors; to decide the appropriate methodology to be used to determine
PSNH's interim stranded costs; and to set PSNH's interim stranded cost charges
utilizing the determined methodology. In testimony filed with the NHPUC in
November 1997, PSNH proposed a new methodology to quantify its strandable costs.
Under this proposal, PSNH would divest all owned generation and purchased-power
obligations via auction. To the extent that the auction fails to produce
sufficient revenues to cover the net book value of owned generation and
contractual payment obligations of purchased power, the difference would be
recovered from customers through a non-bypassable distribution charge. The new
proposal also relies upon securitization of certain assets to further reduce
rates.

On December 15, 1997, the NHPUC officially announced that industry restructuring
would not take place on January 1, 1998. Management believes that industry
restructuring will not take place in New Hampshire until the courts resolve
the issues brought before them, or the parties involved reach a settlement.

PSNH and NAEC are parties to a variety of financing agreements providing that
the credit thereunder can be terminated or accelerated if they do not maintain
specified minimum ratios of common equity to capitalization (as defined in each
agreement). In addition, PSNH and NAEC are parties to a variety of financing
agreements providing in effect that the credit thereunder can be terminated or
accelerated if there are actions taken, either by PSNH or NAEC or by the state
of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the Rate
Agreement and/or the Seabrook Power Contracts.

If the NHPUC's February 28, 1997 decision were to become effective, it would,
unless PSNH and NAEC receive waivers from their respective lenders, result in
(i) write-offs that would cause PSNH's common equity to fall below the
contractual minimums, (ii) reductions in income that would cause PSNH's income
to fall below the contractual minimums, (iii) potential violation of the
contractual provisions with respect to actions depriving PSNH and NAEC of the
benefits of the Rate Agreement and (iv) the potential for cross defaults to
other PSNH and NAEC financing documents. Substantially all of PSNH's and NAEC's
debt obligations would be affected.

If these events transpired and if the creditors holding PSNH and NAEC debt
obligations decide to exercise their rights to demand payment, then either
creditors or PSNH and NAEC could initiate proceedings under Chapter 11 of the
bankruptcy laws.

As a result of the NHPUC decision and the potential consequences discussed
above, the reports of our auditors on the individual financial statements of
PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs
indicate that a substantial doubt exists currently about the ability of PSNH and
NAEC to continue as going concerns. The accounts of PSNH and NAEC are included
in the accompanying consolidated financial statements on the basis of a
going concern. While the effect of the implementation of that decision would
have a material adverse impact on NU's financial position, results of operations
and cash flows, it would not in and of itself result in defaults under borrowing
or other financial agreements of NU or its other subsidiaries.

On May 2, 1997, PSNH made a rate filing with the NHPUC. For information
regarding this rate proceeding, see the MD&A.

Massachusetts: During November 1997, the state of Massachusetts enacted a
comprehensive electric utility industry restructuring bill (legislation). On
December 31, 1997, WMECO filed its restructuring plan with the DTE, as required
by the legislation. The WMECO restructuring plan describes the process by which
WMECO will, beginning March 1, 1998, initiate a ten percent rate reduction for
all customer rate classes and allow customers to choose their energy supplier.
As part of the plan, the DTE authorized recovery of certain strandable, above-
market costs (strandable costs). The legislation gives the DTE the authority to
determine the amount of strandable costs that will be eligible for recovery by
utilities. Costs which will qualify as strandable costs and be eligible for
recovery include, but are not limited to, certain above-market costs associated
with generating facilities, costs associated with long-term commitments to
purchase power at above-market prices from small power producers and nonutility
generators, and regulatory assets and associated liabilities related to the
generation portion of WMECO's business.

Under the statute, if a distribution company claims that it is unable to meet a
price reduction of ten percent initially and 15 percent by September 1, 1999,
the distribution company may so state to the DTE and the DTE is provided with
the authority to "explore all possible mechanisms and options within the limits
of the constitution" to achieve the mandated rate reductions. The statute
indicates that allowing a substitute company to provide standard offer service
is one option that can be considered by the DTE.

The costs of transitioning to competition will be mitigated through several
steps, including divesting WMECO's nonnuclear generating assets at an auction to
be held as soon as June 1998, and securitization of approximately $500 million
in strandable costs by September 30, 1998. NU presently expects to participate,
through a competitive affiliate, in the competitive bid process for WMECO's
generation resources. Any net proceeds in excess of book value received from the
divestiture of these units will be used to mitigate strandable costs. As
required by the legislation, WMECO will continue to operate and maintain its
transmission and local distribution network and deliver electricity to all
customers.

As noted above, the legislation has authorized Massachusetts utilities to
finance a portion of the strandable costs through securitization, using rate
reduction bonds. A separate transition charge will be collected over the life of
the bonds to recover principal, interest and issuance costs.

WMECO's ability to recover its strandable costs will depend on several factors,
which include, but are not limited to, continuous recovery of the costs over the
transitional period supported by the legislation, the aggregate amount of
strandable costs which the company will be allowed to recover and the market
price of electricity. Management believes that the company will recover its
strandable costs. However, a change in one or more of these factors could affect
the recovery of strandable costs and may result in a loss to the company.

Connecticut: Although CL&P continues to operate under cost-of-service based
regulation, legislative restructuring initiatives during 1997 and 1998 in its
jurisdiction has created some uncertainty with respect to future rates and the
recovery of strandable investments and certain future costs such as purchase
power obligations. Management is unable to predict the ultimate outcome of
restructuring initiatives, however, it continues to believe that it is probable
that CL&P will fully recover 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 Note 2H, "Summary of Significant
Accounting Policies -- Regulatory Accounting and Assets" and the MD&A.

The DPUC is required to review a utility's rates every four years if there has
not been a rate proceeding during such period. The DPUC has conducted such a
review. For information regarding this review and other rate matters, see the
MD&A.

FERC Rate Proceedings: For information regarding the FERC rate proceedings for
CYAPC and MYAPC, see Note 3, "Nuclear Decommissioning."

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.

Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC 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. The actual date of the return to
service for each of the units is dependent upon the completion of independent
inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes
to return Millstone 3 to service in early spring of 1998 and Millstone 2 three
to four months after Millstone 3. Millstone 1 is currently in extended
maintenance status.

Management cannot predict when the NRC will allow any of the Millstone units to
return to service and thus cannot precisely estimate the total replacement power
costs the companies ultimately will incur. Replacement power costs incurred by
NU attributable to the Millstone outages averaged approximately $28 million per
month during 1997, and for 1998 are projected to average approximately $9
million per month for Millstone 3, $9 million per month for Millstone 2 and $6
million per month for Millstone 1 while the plants remain out of service. CL&P,
WMECO and PSNH will continue to expense their replacement power costs in 1998.

Based on the current estimates of expenditures and restart dates, management
believes the NU system has sufficient resources to fund the restoration of the
Millstone units and related replacement power costs. If the return to service of
Millstone 3 or 2 is delayed substantially beyond the present restart estimates,
if some financing facilities become unavailable because of difficulties in
meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO
encounter additional significant costs or if any other significant deviations
from management's assumptions occur, CL&P and WMECO could be unable to meet
their cash requirements. In those circumstances, management would take even more
stringent actions to reduce costs and cash outflows and attempt to obtain
additional sources of funds. The availability of these funds would be dependent
upon general market conditions and CL&P's and WMECO's respective credit and
financial conditions at that time.

For information regarding Millstone restart costs, see the MD&A.

For information concerning the ability of CL&P and WMECO to access their
borrowing facilities, see the MD&A.

Litigation: Several class-action lawsuits have been filed against the company
and certain present and former officers and employees of NU in connection with
the company's nuclear operations.  Management cannot estimate the
potential outcome of these suits, but believes these suits are without merit and
intends to defend itself vigorously in all these actions.

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 of  operation and maintenance pro-rata in accordance
with their ownership shares. This agreement also provides that CL&P and WMECO
would be liable only for damages to the non-NU owners for a deliberate violation
of the agreement pursuant to authorized corporate action.

On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior
Court against NU and its current and former trustees. The non-NU owners raise a
number of contract, tort and statutory claims arising out of the operation of
Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages,
punitive damages, treble damages and attorneys' fees. Owners representing
approximately two-thirds of the non-NU interests in Millstone 3 claimed
compensatory damages in excess of $200 million. In addition, one of the lawsuits
seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP,
pending the outcome of the lawsuit. Management cannot estimate the potential
outcome of these suits but believes there is no legal basis for the claims and
intends to defend against them vigorously. To date, no reserves have been
established for this litigation. At December 31, 1997, the costs related to this
litigation were estimated to be approximately $100 million for incremental O&M
costs and approximately $100 million for replacement power costs. These costs
are likely to increase as long as Millstone 3 remains out of service.

The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P have been
negotiating since May 1996 over issues related to the operation of Millstone 1
and 2. CMEEC has failed to make payments on its accrued obligations since
October 1996, claiming that CL&P materially breached its contractual
obligations. CL&P has denied the allegations and requested payment. The matter
has gone to arbitration which has been scheduled for July 1998.

CL&P has filed an application with the Connecticut Superior Court in Hartford
requesting the court to grant interim relief to CL&P. CL&P has asked the court
to enforce the contract provisions by ordering CMEEC to pay the outstanding
obligations under the contract (approximately $25 million) and to continue
making payments (approximately $1.8 million per month) during the arbitration
process.

On December 9, 1997, the Superior Court judge issued a decision denying CL&P's
request for an interim payment order. Management cannot predict the outcome of
this litigation and has taken steps to assert its legal rights. CL&P has
requested reargument, in order to present evidence, and has requested that the
Connecticut Superior Court vacate its order. CL&P is prepared to appeal to a
higher court, if necessary, after the reargument.

C. Environmental Matters

The NU system 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. The NU system has an active environmental auditing and training
program and believes that it is in substantial compliance with current
environmental laws and regulations. However, the NU system is subject to certain
pending enforcement actions and governmental investigations in the environmental
area. Management cannot predict the outcome of these enforcement actions and
investigations.

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 the NU system's existing generating units and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the NU system 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 byproducts and wastes. The NU system also may
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 be estimated
accurately.

The NU system has recorded a liability based upon currently available
information for what it believes are its estimated environmental remediation
costs that the NU system's subsidiaries expect to incur 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, 1997, the net liability recorded by the
NU system for its estimated environmental remediation costs, excluding any
possible insurance recoveries or recoveries from third parties, amounted to
approximately $16.2 million, which management has determined to be the most
probable amount within the range of $16.2 million to $28.0 million.

During 1997, NU adopted 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 adoption of the SOP resulted in an increase of
approximately $1.5 million to NU's environmental reserve in 1997.

The NU system 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 the NU system's financial position or future results of operations.

D. Nuclear Insurance Contingencies

Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities in the country covered by the federal government's third-
party liability indemnification program, an owner of a nuclear unit could be
assessed in proportion to its ownership interest in each of its nuclear units up
to $75.5 million. Payments of this assessment would be limited to $10.0 million
in any one year per nuclear incident based upon the owner's pro rata ownership
interest in each of its nuclear units. In addition, the owner would be subject
to an additional five percent or $3.8 million, in proportion to its ownership
interests in each of its nuclear units, if the sum of all claims and costs from
any one nuclear incident exceeds the maximum amount of financial protection.
Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1,
the NU system's maximum liability, including any additional assessments, would
be $244.2 million per incident, of which payments would be limited to $30.8
million per year. In addition, through power purchase contracts with MYAPC,
VYNPC and CYAPC, the NU system would be responsible for up to an additional
$67.4 million per incident, of which payments would be limited to $8.5 million
per year.

Insurance has been purchased to cover the primary cost of repair, replacement or
decontamination of utility property resulting from insured occurrences. The NU
system is subject to retroactive assessments if losses exceed the accumulated
funds available to the insurer. The maximum potential assessment against the
system with respect to losses arising during the current policy year is
approximately $17.1 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. The NU system is subject to
retroactive assessments if losses exceed the accumulated funds available to the
insurer. The maximum potential assessments against the NU system with respect to
losses arising during current policy years are approximately $13.8 million under
the replacement power policies and $24.6 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 an 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 the NU system with respect to
losses arising during the current policy period is approximately $13.0 million.
Effective January 1, 1998, a new worker policy was purchased which is not
subject to retrospective assessments.

E. Construction Program

The construction program is subject to periodic review and revision by
management. The NU system companies currently forecast construction expenditures
of approximately $2.0 billion for the years 1998-2002, including $267 million
for 1998. In addition, the NU system companies estimate that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $360.7 million for the years 1998-2002, including $60.6 million
for 1998. See Note 5, "Leases," for additional information about the financing
of nuclear fuel.

F. Long-Term Contractual Arrangements

Yankee Companies: The NU system companies rely on VY for approximately 1.7
percent of their capacity under long-term contracts. Under the terms of their
agreements, the NU 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 are recovered through the companies' rates.  The
total cost of purchases under contracts with VYNPC amounted to $24.2 million in
1997, $25.5 million in 1996 and $25.3 million in 1995.

The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently
shut down as of August 6, 1997, December 4, 1996, and February 26, 1992,
respectively. See Note 1E, "Summary of Significant Accounting Policies --
Investments and Jointly Owned Electric Utility Plant," for further information
on the Yankee companies, and Note 3, "Nuclear Decommissioning," regarding the
related decommissioning obligations.

Nonutility Generators: CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from nonutiltiy generators
(NUGs). These arrangements have terms from 10 to 30 years, currently expiring in
the years 1998 through 2028, and require the companies to purchase energy at
specified prices or formula rates. For the twelve month period ending December
31, 1997, approximately 14 percent of NU system electricity requirements was met
by NUGs. The total cost of purchases under these arrangements amounted to $447.6
million in 1997, $441.6 million in 1996 and $434.7 million in 1995. These costs
may be deferred for eventual recovery through rates.

New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement to
purchase the capacity and energy of the New Hampshire Electric Cooperative,
Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for
a ten-year period, which began on July 1, 1990. The total cost of purchases
under this agreement was $23.4 million in 1997, $14.6 million in 1996 and $15.8
million in 1995. The total cost of these purchases has been collected
through the FPPAC in accordance with the Rate Agreement. In connection with the
agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for
15 years.

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, PSNH, WMECO and
HWP are obligated to pay, over a 30-year period ending in 2020, their
proportionate shares of the annual O&M and capital costs of these facilities.

Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements are as follows:

-----------------------------------------------------------------------------
(Millions of Dollars)            1998     1999     2000     2001     2002
-----------------------------------------------------------------------------
VYNPC                           $ 28.7   $ 28.9   $ 27.7   $ 30.3   $ 31.5
NUGs                             455.5    471.1    477.5    488.5    498.9
NHEC                              30.0     30.0     14.6      --       --
Hydro-Quebec                      32.6     31.6     30.9     30.0     29.3
=============================================================================

For additional information regarding the recovery of purchased power costs, see
Note 2K, "Summary of Significant Accounting Policies -- Recoverable Energy
Costs."

G. Sale of COE

During 1997, the NU Board of Trustees approved the offering for sale of COE.
COE's revenues and earnings historically have not been material to NU. During
the fourth quarter of 1997, management established a reserve of $25 million  to
reflect the anticipated loss from the sale of a COE investment. NU had a  net
investment in COE of approximately $33.4 million and $57.2 million, as of
December 31, 1997 and 1996, respectively.

9. Market Risk Management

Fuel Price Management: CL&P uses swap, collar, put and call instruments with
financial institutions to hedge against some of the fuel price risk created  by
long-term negotiated energy contracts and nuclear replacement power generation
and fuel purchases. These agreements minimize exposure associated with rising
fuel prices by managing a portion of CL&P's cost of fuel for these negotiated
energy contracts and nuclear replacement power generation and fuel purchases. As
of December 31, 1997, CL&P had outstanding agreements with a total notional
value of approximately $327 million, and a negative mark-to-market position of
approximately $21 million.

The terms of the agreements require CL&P to post cash collateral with its
counterparties in the event of negative mark-to-market positions and lowered
credit ratings. The amount of the collateral is to be returned to CL&P when the
mark-to-market position becomes positive, when CL&P meets specified credit
ratings or when an agreement ends and all open positions are properly settled.
At December 31, 1997, cash collateral in the amount of $15.4 million was posted
under these terms.

Interest Rate Management: NAEC uses swap instruments with financial institutions
to hedge against interest rate risk associated with its $200 million variable-
rate bank note. The interest-rate management instruments employed eliminate the
exposure associated with rising interest rates, and effectively fix the interest
rate for this borrowing arrangement. Under the agreements, NAEC exchanges
quarterly payments based on a differential between a fixed contractual interest
rate and the three-month LIBOR rate at a given time.  As of December 31, 1997,
NAEC had outstanding agreements with a total notional value of $200 million and
a positive mark-to-market position of approximately $104 thousand.

Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
Each respective company will be exposed to credit risk on their respective
market risk-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.

10. Minority Interest in Consolidated Subsidiary

CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously 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.

11. 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 NU system
companies' nuclear decommissioning trusts were adjusted to market by
approximately $69.6 million as of December 31, 1997, and $31.4 million as of
December 31, 1996, with corresponding offsets to the accumulated provision for
depreciation. The amounts adjusted in 1997 and in 1996 represent cumulative
gross unrealized holding gains. The cumulative gross unrealized holding losses
were immaterial for both 1997 and 1996.

Preferred stock and long-term debt: The fair value of the system'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 the system's financial instruments
and the estimated fair values are as follows:

---------------------------------------------------------------------------
                                                 At December 31, 1997
---------------------------------------------------------------------------
                                                 Carrying        Fair
(Thousands of Dollars)                            Amount         Value
---------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption                         $ 136,200     $ 79,141
Preferred stock subject to
mandatory redemption                              276,000      255,180
Long-term debt --
First Mortgage Bonds                            2,228,800    2,210,423
Other long-term debt                            1,668,533    1,691,362
MIPS                                              100,000      100,760
===========================================================================

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

Preferred stock not subject to
mandatory redemption                            $ 136,200    $ 127,045
Preferred stock subject to
mandatory redemption                              301,000      264,304
Long-term debt --
First Mortgage Bonds                            2,196,788    2,163,031
Other long-term debt                            1,718,859    1,741,818
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.



                      Management's Discussion and Analysis

                              Financial Condition

                                    Overview

The length of the ongoing outages at the three Millstone nuclear plants
(Millstone) and the high costs of the  recovery efforts weakened NU's 1997
earnings, balance sheet and cash flows and will continue to have an adverse
impact on NU's financial condition until the units are returned to service.

NU's earnings fell sharply in 1997 for the second consecutive year, primarily as
a result of costs associated with the ongoing Millstone outages.  NU lost
$1.01 per common share in 1997, compared with a profit of $0.30 per common share
in 1996 and $2.24 a share in 1995.

The poorer financial results in 1997 were due primarily to the fact that all
three Millstone units were off line for the entire year in 1997 and spending
associated with the recovery efforts was significantly higher in 1997 than it
was in 1996.  Millstone 3 operated for nearly three months in 1996 and Millstone
2 for nearly two months. As a result, the cost of replacing power ordinarily
generated by the Millstone units rose by approximately $80 million in 1997.  The
total operation and maintenance (O&M) costs at Millstone were approximately $216
million higher in 1997.

The higher Millstone costs have caused the NU system, primarily The Connecticut
Light and Power Company (CL&P) and Western Massachusetts Electric Company
(WMECO), to focus closely on maintaining adequate liquidity and reducing
nonnuclear O&M costs. In 1997 and early 1998, CL&P and WMECO successfully sold
$260 million in first mortgage bonds and renegotiated more than $400 million of
bank credit lines. Additionally, nonnuclear O&M expenses in 1997 were reduced by
about $50 million from 1996.

The SEC has advised NU, CL&P, PSNH and WMECO to adjust for certain costs
associated with the ongoing Millstone outages as they are incurred.  For the
past two years, NU, CL&P, PSNH and WMECO have been reserving for the unavoidable
costs they expected to incur to meet NRC requirements.  These annual statements
have been adjusted in accordance with the SEC's directive.  Management does not
expect implementation of this accounting change to affect the ability of CL&P
and WMECO to meet their financial covenants contained in their $313.75 million
revolving credit arrangement.

In 1998, management expects Millstone-related expenses to fall significantly,
assuming Millstone 3 and Millstone 2 are returned to service at dates close to
current estimates, although the O&M expenses at Millstone 3 and Millstone 2
will be considerably higher than before the station was placed on the Nuclear
Regulatory Commission's (NRC's) watch list.  The actual level of 1998 nuclear
spending at Millstone will depend on when the units return to operation and the
cost of restoring them to service.  The company hopes to restart Millstone 3,
the newest and largest unit at the site, in the early spring of 1998 and
Millstone 2 three to four months after Millstone 3.  The company cannot restart
the Millstone units until it receives formal approval from the NRC.  As part of
an effort to reduce spending in 1998, Millstone 1 has been placed in extended
maintenance status.  Management will review its options with respect to
Millstone 1 in 1998, including restart, early retirement and other options.

Rate reductions in all three states served by NU's operating companies are
likely to offset a portion of the benefit of lower Millstone-related costs.  On
December 1, 1997, Public Service Company of New Hampshire (PSNH) rates were
reduced 6.87 percent as a result of an interim rate order issued by the New
Hampshire Public Utilities Commission (NHPUC).  On March 1, 1998, CL&P rates
were reduced by approximately 1.4 percent to reflect the removal of Millstone 1
from rates, and additional noncash reductions were made to revenue requirements
as a result of an interim rate order issued by the Connecticut Department of
Public Utility Control (DPUC).  Also on March 1, 1998, WMECO reduced retail
rates by 10 percent in compliance with industry restructuring legislation passed
in November 1997 by the Massachusetts Legislature.  Rate cases involving CL&P
and PSNH may result in additional rate adjustments later in 1998.  CL&P's
revenues could be further reduced if substantial delays in restarting Millstone
3 and Millstone 2 result in a DPUC decision to remove those units from rates.

In addition to focusing on maintaining liquidity, management also must attend to
industry restructuring efforts throughout the NU system's service territory.  A
temporary restraining order issued by a U.S. District Court is currently
blocking the NHPUC from implementing a February 1997 restructuring order that
would have resulted in a write-off by PSNH of more than $400 million.
Management hopes to negotiate an alternative restructuring proposal in
1998 that will produce significant PSNH rate reductions and allow retail
customers to choose their electric suppliers, but still give PSNH and North
Atlantic Energy Corporation (NAEC) an opportunity to maintain an adequate
financial condition and earn fair returns on their investments.

The 1997 Massachusetts legislation allowed full retail choice on March 1, 1998.
WMECO expects to recover fully its stranded costs through a combination of
securitization and divestiture of its nonnuclear generating assets.

In Connecticut, restructuring legislation is being considered in the legislative
session that began in February 1998.

Restructuring also is likely to cause other NU subsidiaries to auction their
nuclear and/or nonnuclear generating units.  Despite these potential
requirements, management believes that it could be advantageous for the NU
system to remain in the generation business, which could be accomplished by
acquiring ownership interests in facilities inside and outside New England.

NU's earnings in 1997 also were affected by a $25 million reserve for
anticipated losses on the sale of investments by Charter Oak Energy, Inc., NU's
independent power development subsidiary.

Presently, NU is New England's largest electric utility system with 1.7 million
customers in Connecticut, New Hampshire and Massachusetts.  In 1997, NU
experienced modest economic growth in its retail sales that was offset by the
effects of mild winter weather. In 1998, management expects that the regional
economy will continue to experience modest growth.

Millstone

Outages
The NU system has a 100 percent ownership interest in Millstone 1 and 2
and a 68 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 NRC 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.  The actual date of the return to
service for each of the units is dependent upon the completion of independent
inspections, reviews by the NRC and a vote by the NRC commissioners.

In January 1998, NU declared Millstone 3 physically ready for restart, which
meant that almost all of the restart-required physical work had been completed
in the plant. The NRC currently is conducting a series of inspections to
determine, among other things, whether the plant has effective leadership and
corrective action and employee concerns programs.  The Independent Corrective
Action Verification Program, an NRC-ordered independent review of the plant's
design and licensing bases, is expected to be completed in March 1998.

In 1997, the NU system's share of nonfuel O&M costs expensed for Millstone
increased to approximately $556 million, compared to approximately $340 million
in 1996.

Replacement power costs attributable to the Millstone outages totaled
approximately $340 million in 1997 compared to $260 million expensed in 1996.
These costs for 1998 are forecasted to average approximately $9 million per
month for Millstone 3, $9 million per month for Millstone 2 and $6 million per
month for Millstone 1 while the plants are out of service.

CL&P, WMECO and PSNH have been, and will continue to be, expensing all of the
costs to restart the units including replacement power and nonfuel O&M
expenses.  See "Connecticut Rate Matters" for issues related to the recovery of
Millstone 1 costs.

NU and its subsidiaries are involved in several class action lawsuits and other
litigation in connection with their nuclear operations. See the "Notes to
Consolidated Financial Statements," Note 8B, for further information on this
litigation.

Millstone 1

Management will review its options with respect to Millstone 1 during 1998.  The
issues that management will consider in evaluating its options include the costs
to restart the unit, the economic benefits of the unit's continued operation and
certain Connecticut state law issues.  In the CL&P four year rate review
proceeding (discussed in detail under "Rate Matters"), the DPUC noted that CL&P
may not be able to recover its remaining investment in Millstone 1 if the DPUC
were to determine that the unit had been prematurely shut down due to management
imprudence.  Additionally, there is a Connecticut statute which may limit CL&P's
ability to collect decommissioning charges in the future if Millstone 1 were to
be prematurely retired.

CL&P's net unrecovered Millstone 1 plant cost and the unrecovered
decommissioning costs at December 31, 1997, were approximately $216 million and
$198 million, respectively.

Capacity

During 1996 and continuing into 1997, the NU system companies took measures to
improve their capacity position, including obtaining additional generating
capacity, improving the availability of NU's generating units and improving the
NU system's transmission capability.  During 1997, NU spent approximately $58
million to ensure the availability of adequate generating capacity in
Connecticut and Massachusetts, of which $40 million was expensed. In 1998, NU
does not anticipate the need to take additional measures to ensure adequate
generating capacity.

Liquidity and Capital Resources

Cash provided from operations decreased approximately $438 million in 1997,
compared to 1996, primarily due to higher cash expenditures related to the
Millstone outages, and the pay down in 1997 of the 1996 year end accounts
payable balance.  The 1996 year end accounts payable balance was relatively high
due to costs related to a severe December storm and costs associated with the
Millstone outages that had been incurred but not yet paid by the end of 1996.
Net cash used for financing activities decreased approximately $224 million,
primarily due to suspension of the NU common dividend early in 1997 and an
increase in short-term borrowings.

CL&P and WMECO established facilities in 1996 under which they may sell, from
time to time, up to $200 million and $40 million, respectively, of their
accounts receivable and accrued utility revenues.  As of December 31, 1997, CL&P
and WMECO sold approximately $70 million and $20 million of receivables,
respectively, to third-party purchasers.

NU's, CL&P's and WMECO's three-year revolving credit agreement was amended in
May 1997 (the Credit Agreement). Under the Credit Agreement, CL&P and WMECO are
able to borrow up to approximately $225 million and $90 million, respectively,
subject to a total borrowing limit of $313.75 million for all three borrowers.
NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each
maintained a consolidated operating income to consolidated interest expense
ratio of at least 2.50 to 1 for two consecutive fiscal quarters.  Currently, the
companies cannot meet this requirement. At December 31, 1997, CL&P and WMECO had
$35 million and $15 million outstanding, respectively, under the Credit
Agreement.

In February 1998, because of borrowing restrictions on NU in the Credit
Agreement, NU entered into a separate $25 million, 364-day revolving credit
facility with one bank.

Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has
any financing agreements containing cross defaults based on financial defaults
by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing
agreements containing cross defaults based on financial defaults by NU, CL&P or
WMECO.  Nevertheless, it is possible that investors will take negative operating
results or regulatory developments at one company in the NU system into account
when evaluating other companies in the NU system.  That could, as a practical
matter and despite the contractual and legal separations among the NU companies,
negatively affect each company's access to financial markets.

In December 1997 and January 1998, Moody's Investors Service (Moody's) and
Standard & Poor's (S&P), respectively, downgraded the senior secured debt of
CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO.  This was
the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since
the Millstone units went on the NRC watch list in 1996.  All of the NU system's
securities are rated below investment grade and remain under review for further
downgrade.  Although CL&P and WMECO do not have any plans to issue debt in the
near term, rating agency downgrades generally increase the future cost of
borrowing funds because lenders will want to be compensated for increased risk.
Additionally, this could affect the terms and ability of the NU system companies
to extend existing agreements.

The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in December 1997
brought those ratings to a level at which the sponsor of WMECO's accounts
receivable program can take various actions, in its discretion, which would have
the practical effect of limiting WMECO's ability to utilize the facility. The
WMECO accounts receivable program could  be terminated if WMECO's first mortgage
bond credit ratings experience one more level of downgrade.  CL&P's accounts
receivables program could be terminated if its senior secured debt is downgraded
two more steps from its current ratings.

The NU system companies' ability to borrow under their financing arrangements is
dependent on their satisfaction of contractual borrowing conditions.  The
financial covenants that must be satisfied to permit CL&P and WMECO to borrow
under the Credit Agreement are particularly restrictive and become more
restrictive throughout 1998.  Spending levels in 1998, particularly for the
first half of the year while the Millstone units are expected to be out of
service, will be constrained to levels intended to assure that the financial
covenants in CL&P's and WMECO's Credit Agreement are satisfied.  However, there
is no assurance that these financial covenants will be met as the system may
encounter additional unexpected costs from such areas as storms, reduced
revenues from regulatory actions or the effect of weather on sales levels.

If the return to service of Millstone 3 or Millstone 2 is delayed substantially
beyond the present restart estimates, if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions or
renegotiating extensions, if the system encounters additional significant costs,
or any other significant deviations from management's current assumptions, the
currently available borrowing facilities could be insufficient to meet all of
the NU system's cash requirements. In those circumstances, management would take
even more stringent 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 that time.

Restructuring

The NU system companies continue to operate under cost-of-service based
regulation, however, future rates and the recovery of strandable costs are
issues under various restructuring initiatives in each of the NU system
companies' service territories. Strandable costs are expenditures or commitments
that have been made to meet public service obligations with the expectation that
they would be recovered from customers in the future.  The NU system companies
have exposure to strandable costs for their investments in high-cost nuclear
generating plants, state-mandated purchased power obligations and significant
regulatory assets.  The NU system companies' exposure to strandable investments
and purchased power obligations exceeds their shareholder's equity.  The NU
system's financial strength and resulting ability to compete in a restructured
environment will be negatively affected if the NU system companies are unable to
recover their past investments and commitments.  Even if the NU system companies
are given the opportunity to recover a large portion of their strandable costs,
earnings prospects in a restructured environment will be affected in ways which
cannot be estimated at this time.

The NU system companies are seeking to mitigate the impacts of restructuring by
proposing stable, lower rates while pursuing customer choice options and full
recovery of their strandable costs.  The NU system companies' strategy to
recover strandable costs includes efforts to promote state legislation that will
authorize the issuance of rate reduction bonds that would refinance these
investments and which would be repaid through non-bypassable charges to
customers.  Management is unable to predict the ultimate outcome of these
initiatives which will be subject to regulatory and legislative approvals.
Management believes it is entitled to full recovery of its prudently incurred
costs, including regulatory assets and other strandable costs. See the "Notes to
Consolidated Financial Statements," Note 8A, for the potential accounting
impacts of restructuring.

New Hampshire

In February 1997, the NHPUC issued orders to restructure the state's electric
utility industry and set interim stranded cost charges for PSNH. In the
orders, the NHPUC announced a departure from cost-based ratemaking and adopted a
market-priced approach to stranded cost recovery. PSNH, NU, NAEC, and Northeast
Utilities Service Company (NUSCO) filed for a temporary restraining order,
preliminary and permanent injunctive relief and a declaratory judgment in the
United States District Court of New Hampshire.  The case subsequently was
transferred to the United States District Court of Rhode Island (District Court)
where a temporary restraining order was granted, staying, indefinitely, the
enforcement of the NHPUC's restructuring orders as they affected PSNH.  Certain
appeals to the preliminary ruling have been denied and proceedings in the
District Court are expected to resume.

The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate
methodology to be used to determine PSNH's interim stranded costs and to set
PSNH's interim stranded cost charges utilizing the determined methodology.  The
NHPUC has not indicated when it will issue a decision in these proceedings. On
December 15, 1997, the NHPUC officially announced that industry restructuring
would not take place on January 1, 1998.

As part of the rehearing proceedings, PSNH proposed a new methodology to
quantify its stranded costs. Under this proposal, PSNH would divest its owned
generation and purchased power obligations via auction. To the extent that the
auction fails to produce sufficient revenues to cover the net book value of
owned generation and contractual payment obligations of purchased power, the
difference would be recovered from customers through a non-bypassable
distribution charge.  The new proposal also relies upon securitization of
certain assets to further reduce rates.

On February 20, 1998, PSNH forwarded a settlement offer to representatives from
the state of New Hampshire that was consistent with PSNH's proposal in the
rehearing proceedings including, among other things, a 20 percent rate reduction
at the beginning of 1999, an auction of PSNH's nonnuclear generating units and
Securitization of approximately $1.15 billion of PSNH's stranded costs.

Massachusetts

On November 25, 1997, Massachusetts enacted a comprehensive electric utility
industry restructuring bill. The bill provides that each Massachusetts electric
company, including WMECO, will decrease its rates by 10 percent and allow all
its customers to choose their electric supplier on March 1, 1998.  The statute
requires a further 5 percent rate reduction, adjusted for inflation, by
September 1, 1999.

In addition, the legislation provides, among other things, for: (i) recovery of
strandable costs through a "transition charge" to customers, subject to review
by the Department of Telecommunications and Energy (DTE), formerly the
Department of Public Utilities (DPU, collectively the DTE), (ii) a possible
limitation on WMECO's return on equity should its transition cost charge go
above a certain level, (iii) securitization of allowed strandable costs, and
(iv) divestiture of nonnuclear generation. WMECO hopes it will be able to
complete securitization in 1998.

The statute also provides that an electric company must transfer or separate
ownership of generation, transmission and distribution facilities into
independent affiliates or functionally separate such facilities within 30
business days after federal approval. Additionally, marketing companies formed
by an electric company are to be separate from the electric company and separate
from generation, transmission or distribution affiliates.

On December 31, 1997, WMECO filed its restructuring plan with the DTE consistent
with the Massachusetts restructuring legislation.  The plan sets out the process
by which WMECO, as of March 1, 1998, initiated a 10 percent rate reduction for
all customer rate classes and allowed customers to choose their energy supplier.
WMECO intends to mitigate its strandable costs through several steps, including
divesting WMECO's nonnuclear generating  plants at an auction to be held as soon
as June 30, 1998, and securitization of approximately $500 million of stranded
costs. NU intends to participate through a nonregulated affiliate in the
competitive bid process for WMECO's generation resources.  Any proceeds in
excess of book value received from the divestiture of these units will be used
to mitigate stranded costs.  As required by the legislation, WMECO will continue
to operate and maintain the transmission and local distribution network and
deliver electricity to all customers.  On February 20, 1998, the DTE issued an
order approving, in all material respects, WMECO's restructuring plan on an
interim basis.  A final decision is expected in 1998.

Because WMECO is obligated to reduce rates on March 1, 1998, before the means of
financing for restructuring are completed, WMECO's cash flows and financial
condition will be negatively affected. These impacts would become significant if
there are material delays in, or significantly reduced proceeds from, the
divestiture of nonnuclear generation and securitization.

Connecticut

Massachusetts and New Hampshire have been at the forefront of the restructuring
movement in New England with very different approaches as previously discussed.
In Connecticut, legislators have proposed broad restructuring legislation which
will be considered in the spring of 1998.

Rate Matters

Connecticut

In July 1996, the 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, and agreed to accelerate the amortization of regulatory assets during
the period that the rate freeze remains in effect.  The Settlement provided that
CL&P's target return on equity (ROE) would be 10.7 percent but did not alter
CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a calendar year
exceeds 10.7 percent after the target regulatory asset amortization ($68 million
in 1997) and after adjustment for any incremental NRC billings and any rate
disallowances for nuclear operations, then CL&P shall retain two-thirds of any
surplus and use the remaining one-third to provide a reduction in bills.  CL&P's
actual ROE, as adjusted, fell below the target ROE for 1996 and 1997 and,
therefore, the accelerated amortization of regulatory assets was reduced to the
minimum amounts allowed under the Settlement ($73 million in 1996 and $54
million in 1997).  For each full year that the rate freeze remains in effect,
CL&P agreed to amortize an additional $44 million of regulatory assets.  On July
30, 1997, the DPUC issued a decision in its prudence review of nuclear cost
recovery issues disallowing CL&P's recovery of all of the replacement power
costs associated with the ongoing outages at Millstone.  CL&P has expensed, and
will continue to expense, replacement power costs for the Millstone outages as
they are incurred.

The DPUC is required to review a utility's rates every four years if there has
not been a rate proceeding during such period. In 1997, the DPUC conducted such
a review of CL&P's rates, including an analysis of the possibility of removing
one or more of the Millstone nuclear units from CL&P's rate base.  On December
31, 1997, the DPUC issued its ruling in this matter.  The decision did not
effect a change in CL&P's rates, but set forth findings and conclusions that
could be used to do so in additional proceedings. The most significant
conclusion was that Millstone 1 should be removed from CL&P's rate base, which
would cause an annual revenue reduction of approximately $30.5 million.  The
decision stated that the DPUC would open an interim rate case immediately to
remove Millstone 1 from CL&P's rates and simultaneously to remove an additional
$110.5 million of other expenses from rates related to perceived overearnings.
In February 1998, the DPUC issued a decision reducing CL&P's rates by
approximately 1.4 percent to reflect the removal of Millstone 1 from rates.
This reduction reflects the removal from rates of O&M, depreciation and
investment return related to Millstone 1, net of replacement power costs.  In
addition, the decision requires CL&P to accelerate the amortization of
regulatory assets by $110.5 million, which includes the $44 million from the
1996 Settlement.  The interim rate reduction became effective on March 1, 1998.

CL&P also was directed to file a full rate case on June 1, 1998, to address
potential overearnings amounting to an additional $150 million in 1998.  The
effective date of any rate order will be September 28, 1998.  In addition, the
DPUC has scheduled a hearing for April 1, 1998, to determine the status of
Millstone 3 and Millstone 2.  A similar restart status hearing is anticipated
for June 1, 1998. If the units are not operating by those dates, the DPUC will
consider their removal from rates.

The DPUC also will consider CL&P's analyses of the economic benefits of the
continued operation of Millstone 1 and Millstone 2 in the context of CL&P's next
integrated resource planning proceeding, which begins in April 1998.

New Hampshire

PSNH's Rate Agreement provides for seven base rate increases and a comprehensive
fuel and purchased power adjustment clause (FPPAC). In June 1996, the final base
rate increase of 5.5 percent went into effect. Although the FPPAC continues for
an additional four years beyond the end of the fixed rate period, there is
uncertainty regarding how it will function after that time.

On May 2, 1997, PSNH made a rate filing with the NHPUC requesting base rates to
remain at their current level after May 31, 1997. By order dated November 6,
1997, the NHPUC ordered a temporary rate reduction for PSNH at a revenue level
6.87 percent lower than current rates.  The NHPUC also set an interim return on
equity of 11 percent.  The temporary rates became effective December 1, 1997.  A
final decision, which will be reconciled to July 1, 1997, is not expected to be
issued until September 1998.  A portion of this reduction was offset by an
increase to rates through the FPPAC.

On February 10, 1998, the NHPUC ordered an FPPAC rate for the period December 1,
1997, through May 31, 1998, which increased customer bills by approximately 6
percent.  This rate continues to defer recovery of a substantial portion of
costs for the future.  In addition, recovery of the Seabrook deferred return
(approximately $127 million annually) is scheduled to begin in June 1998.  See
the "Notes to Consolidated Financial Statements," Note 2K, for further
information on the FPPAC.

Massachusetts

In April 1996, the DTE approved a settlement (the Agreement) that included the
continuation through February 1998 of a 2.4 percent rate reduction instituted in
June 1994. Additionally, the Agreement terminated certain pending and potential
reviews of WMECO's generating plant performance and accelerated its amortization
of strandable generation assets by approximately $6 million in 1996 and $10
million in 1997.

On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a
settlement agreement with the Massachusetts Attorney General for a fuel
adjustment clause (FAC) which would allow for a lower rate to WMECO customers
for the billing months of September 1997 through February 1998.  WMECO is not
recovering replacement power costs during this period and has indicated that it
would not seek recovery of any replacement power costs associated with the
Millstone outages. WMECO has been expensing and will continue to expense these
costs.  The Massachusetts restructuring legislation effectively eliminates the
FAC, effective March 1, 1998.

Nuclear Decommissioning

Connecticut Yankee

The NU system has a 49 percent ownership interest in the Connecticut Yankee
nuclear generating facility (CY or the plant). On December 4, 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company 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 would
have expired 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 FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1997, NU's
share of these obligations was approximately $304 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that
CL&P, PSNH and WMECO each will continue to be allowed to recover such FERC
approved costs from their customers. Accordingly, NU has recognized its share of
the estimated costs as a regulatory asset, with a corresponding obligation, on
its balance sheet.

Maine Yankee

The NU system has a 20 percent ownership interest in the Maine Yankee (MY)
nuclear generating facility. On August 6, 1997, the Board of Directors of Maine
Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY.  On January
14, 1998, FERC released a draft order on the MYAPC application to amend its
power contracts with the owner/purchasers and revise its decommissioning and
other charges. FERC has accepted the proposed application for filing and made
the amendments and the proposed charges under the contracts effective on January
15, 1998, subject to refund after hearings. At December 31, 1997, the NU
system's share of the estimated remaining obligation, including decommissioning,
amounted to approximately $173 million. Under the terms of the contracts with
MYAPC, the shareholders' sponsor companies, including CL&P, PSNH and WMECO, are
responsible for their proportionate share of the costs of the unit, including
decommissioning. Management expects that CL&P, PSNH and WMECO will be allowed to
recover these costs from their customers. Accordingly, NU has recognized these
costs as a regulatory asset, with a corresponding obligation on its balance
sheet.

Millstone and Seabrook

NU's estimated cost to decommission its shares of the Millstone plants and
Seabrook is approximately $1.48 billion in year end 1997 dollars. These costs
are being recognized over the lives of the respective units with a portion
currently being recovered through rates. As of December 31, 1997, the market
value of the contributions already made to the decommissioning trusts, including
their investment returns, was approximately $503 million.  See the "Notes to
Consolidated Financial Statements," Note 3, for further information on nuclear
decommissioning, including the NU system's share of costs to decommission the
other regional nuclear generating units.

Environmental Matters

NU's subsidiaries are potentially liable for environmental cleanup costs at a
number of sites inside and outside their service territories. To date, the
future estimated environmental remediation liability has not been material with
respect to the earnings or financial position of the NU system. At December 31,
1997, NU's subsidiaries had recorded an environmental reserve of approximately
$16 million. See the "Notes to Consolidated Financial Statements," Note 8C, for
further information on environmental matters.

Year 2000 Issue

The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU's systems to process critical financial and operational
information incorrectly. The company has assessed and continues to assess the
impact of the Year 2000 issue on its operating and reporting systems. The
assessment of the nuclear operating systems is continuing and is expected to be
completed in the summer of 1998.

The NU system will utilize both internal and external resources to reprogram or
replace and test the software for Year 2000 modifications.  The total estimated
remaining cost of the Year 2000 project is $37 million and is being funded
through operating cash flows.  This estimate does not include any costs for the
replacement or repair of equipment or devices that may be identified during the
assessment process.  The majority of these costs will be expensed as incurred
over the next two years.  To date, the company has incurred and expensed
approximately $4 million related to the assessment of, and preliminary efforts
in connection with, its Year 2000 project.

The costs of the project and the date on which the company plans to complete the
Year 2000 modifications are based on management's best estimates, which were
derived utilizing numerous assumptions of future events, including the continued
availability of certain resources, third-party modification plans and other
factors.  However, there can be no guarantee that these estimates will be
achieved, and actual results could differ materially from those plans. If the NU
system's remediation plan is not successful, there could be a significant
disruption of the NU system's operations.

Risk-Management Instruments

The following discussion about the NU system's risk-management activities
includes forward looking statements that involve risk and uncertainties.  Actual
results could differ materially from those projected in the forward looking
statements.

This analysis presents the hypothetical loss in earnings related to the fuel
price and interest rate market risks not covered by the risk-management
instruments at December 31, 1997. The NU system uses swaps, collars, puts and
calls to manage the market risk exposures associated with changes in fuel prices
and variable interest rates. The NU system does not use these risk-management
instruments for speculative purposes. For more information on NU's use of risk-
management instruments, see the "Notes to Consolidated Financial Statements,"
Notes 2.0 and 9.

Fuel Price Risk-Management Instruments

In the generation of electricity, the most significant variable cost component
is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by a
regulatory fuel price adjustment clause. However, for a specific, well-defined
volume of fuel that is excluded from the fuel price adjustment clause
(unprotected volume), CL&P employs fuel price risk-management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks are created by the sale of
long-term, fixed-price electricity contracts to wholesale customers and the
purchase or generation of replacement power related to the ongoing Millstone
nuclear outages.

At December 31, 1997, CL&P had outstanding agreements with a total notional
value of approximately $327 million. The settlement amounts associated with the
instruments reduced fuel expense by approximately $8 million. CL&P has had
experience using various fuel price risk-management instruments since 1994, most
of which have been in the form of fuel price swaps. At December 31, 1997,
approximately 30 percent of the unprotected volume was covered by fuel price
risk-management instruments (hedge ratio) for 1997. This effectively fixed or
bounded the fuel cost and thus eliminated the market price risk for this covered
volume of fuel. At December 31, 1997, CL&P had a hedge ratio of 44 percent for
1998.

At December 31, 1997, the 56 percent uncovered volume of fuel for 1998, as a
result of not being hedged, is subject to changes in actual market prices.
Therefore, assuming a hypothetical 10 percent increase in the average 1997 price
of fuel in 1998, the result would be a negative pretax impact on earnings of
approximately $12.4 million.

This analysis is based on the broad assumption that the entire uncovered volume
of fuel remains constant and will be purchased on the spot market. This
assumption is subject to change as the uncovered volume of fuel likely will
change during the next year. Other assumptions used in this analysis,
projections of the fuel mix, the amount of long-term sales contracts or the
projected Millstone restart dates, also are subject to change.

Interest Rate Risk-Management Instruments

Several NU subsidiaries hold variable rate long-term notes, exposing the NU
system to interest rate risk. In order to hedge some of this risk, interest rate
risk-management instruments have been entered into on NAEC's $200 million
variable rate note, effectively fixing the interest on this note at 7.823
percent. The remaining variable notes remain unhedged.

At December 31, 1997, NU had a hedge ratio on its long-term variable rate notes
of 21 percent, which is expected to be the same for 1998. The remaining 79
percent of NU's variable notes are unhedged and, as a result, are subject to
actual market rates for 1998. Thus, a 10 percent increase in market interest
rates above the 1997 weighted average variable rate during 1998 would result
in a $3.6 million pretax annual decrease in earnings.

For purposes of this analysis, the hedge ratio for long-term variable rate notes
is calculated by dividing the amount of the hedged long-term note by the total
of all long-term variable notes held at December 31, 1997.


Results of Operations

The components of significant income statement variances for the past two years
are provided in the table below. The relative magnitude of how revenues earned
in 1997 and retained earnings were used by NU's continuing operations in 1997 is
illustrated in the chart on page 21.

                                      Income Statement Variances
                                        (Millions of Dollars)

                           1997 over/(under) 1996      1996 over/(under) 1995
                               Amount Percent               Amount Percent

Operating revenues           $ 43        1%               $ 42         1%
Fuel, purchased and net
interchange power             154       13                 230        25
Other operation                 3        -                 127        13
Maintenance                    86       21                 127        44
Amortization of regulatory
assets, net                     8        7                  (6)       (5)
Federal and state income
taxes                         (94)     (98)               (166)      (63)
Deferred nuclear plants
return (other and
borrowed funds)                (3)     (13)                (13)      (36)
Other income, net             (69)      (a)                 20        (a)
Interest on long-term debt     (3)      (1)                (30)      (10)
Other interest                 (4)     (53)                  1        15
Preferred dividends of
subsidiaries                   (3)     (10)                 (6)      (14)
Net income                   (169)      (a)               (244)      (86)

(a) Percentage greater than 100

Operating Revenues

Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $32
million, primarily due to higher fuel revenues for CL&P as a result of a lower
fuel rate in 1996. Conservation recoveries increased by $17 million, primarily
due to a 1996 reserve for overrecoveries of CL&P demand-side management costs.
Retail kilowatt hour sales were 0.3 percent lower in 1997 as a result of mild
winter weather.

Total operating revenues increased in 1996, primarily due to higher retail
sales, regulatory decisions and higher other revenues, partially offset by lower
fuel recoveries and lower wholesale revenues. Retail sales increased 1.6 percent
($40 million), primarily due to modest economic growth in 1996. Regulatory
decisions increased revenues by $22 million, primarily due to retail rate
increases for CL&P in mid-1995 and PSNH in mid-1995 and 1996, partially offset
by 1996 reserves for CL&P overrecoveries of demand-side management costs. Other
revenues increased $31 million and included higher recognition in 1996 of
reimbursable conservation services and higher transmission revenues. Fuel
recoveries decreased $40 million, primarily due to lower FPPAC revenues for PSNH
as a result of a customer refund ordered by the NHPUC, partially offset by
higher base fuel revenues for PSNH as a result of the PSNH rate increases.
Wholesale revenues decreased $13 million, primarily due to higher
recognition in 1995 of lump-sum payments for the termination of a CL&P long-term
contract and capacity sales contracts that expired in 1995.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased in 1997, primarily
due to replacement power costs associated with the Millstone outages and the
expensing in 1997 of replacement power costs incurred in 1996.

Fuel, purchased and net interchange power expense increased in 1996, primarily
due to replacement power costs associated with the Millstone outages and the
write-off of the generation utilization adjustment clause (GUAC) balance under
the CL&P Settlement.

Other Operation and Maintenance

Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($216 million), higher
costs as a result of Seabrook outages ($23 million) and higher capacity charges
from Maine Yankee ($16 million), partially offset by lower recognition of
nuclear refueling outage costs primarily as a result of the 1996 CL&P Rate
Settlement ($72 million), lower capacity charges from Connecticut Yankee as a
result of a property tax refund ($35 million), lower administrative and general
expenses ($41 million) primarily due to lower pensions and benefit costs, and
lower storm expenses.  Other operation and maintenance expenses increased in
1996, primarily due to higher costs associated with the Millstone restart effort
($116 million) and 1996 costs to ensure adequate generating capacity in
Connecticut ($39 million). In addition, 1996 costs reflect higher storm and
reliability expenditures, higher recognition of conservation expenses and higher
marketing costs.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased in 1997, primarily due to the
completion of the CL&P cogeneration deferrals in 1996, increased amortization in
1997, and the beginning of the amortization of NAEC's Seabrook deferred return
in December 1997, partially offset by the completion of CL&P's Seabrook
amortization and WMECO's Millstone 3 amortization in 1996.

Amortization of regulatory assets, net decreased in 1996, primarily due to the
completion of the Millstone 3 phase-in plans in 1995, partially offset by lower
CL&P cogeneration deferrals and the accelerated amortization of regulatory
assets as a result of the 1996 CL&P Settlement.

Federal and State Income Taxes

Federal and state income taxes decreased in 1997, primarily due to lower book
taxable income.  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 and the expiration of the 1991 federal statute of
limitations. Income tax expense totaled approximately $95 million in 1996,
despite relatively low pretax earnings, due to the tax effect of differences for
certain items, particularly depreciation and the amortization of PSNH
acquisition costs.

Deferred Nuclear Plants Return
The change in deferred nuclear plants return in 1997 was not significant.
Deferred nuclear plants return decreased in 1996, primarily due to additional
Seabrook investment being phased into rates, partially offset by a one-time
adjustment to NAEC's Seabrook deferred return balance of approximately $5
million in 1995.

Other Income, Net

Other income, net decreased in 1997, primarily due to a $25 million reserve for
anticipated losses on the sale of investments by Charter Oak Energy (COE),
equity losses on COE investments, costs associated with the accounts receivable
facility, nonutility marketing and advertising costs and lower miscellaneous
income.

Other income, net increased in 1996, primarily due to higher interest income on
temporary cash investments in 1996, the 1995 write-down of CL&P's wholesale
investment in Millstone 3 and a 1995 increase to the environmental reserve.

Interest on Long-Term Debt

The change in interest on long-term debt in 1997 was not significant. Interest
on long-term debt decreased in 1996, primarily due to reacquisitions and
retirements of long-term debt in 1995.

Other Interest

Other interest expense decreased in 1997 due to 1996 interest expense associated
with an FPPAC refund for PSNH.

Preferred Dividends of Subsidiaries

The change in preferred dividends of subsidiaries was not significant in 1997.
Preferred dividends of subsidiaries decreased in 1996, primarily due to a 1995
charge to earnings for premiums on redeemed preferred stock and a reduction in
preferred stock levels.


1997 Use of Revenue and Retained Earnings

[The following table was originally a pie chart in the printed materials.]

Energy Costs                                     32%
Nonfuel Operation and Maintenance Expenses       28%
Depreciation, Amortization and Other Expenses    13%
Wages and Benefits                               12%
Interest Charges                                  7%
Taxes                                             6%
Common and Preferred Dividends                    2%





NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Statements of Quarterly Financial Data (Restated)
(Unaudited)
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
1997                                                                    Quarter Ended (a)
---------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share data)            March 31    June 30    September 30  December 31
---------------------------------------------------------------------------------------------------------
<S>                                                     <C>           <C>           <C>          <C>
Operating Revenues.....................................$  975,368  $  903,323  $    977,127  $   978,988
---------------------------------------------------------------------------------------------------------
Operating Income.......................................$   69,377  $   23,542  $     46,361  $    51,502
---------------------------------------------------------------------------------------------------------
Net Income/(Loss)......................................$      876  $  (47,017) $    (30,832) $   (52,989)
---------------------------------------------------------------------------------------------------------
Earnings/(Loss) Per Common Share.......................$     0.01  $    (0.37) $      (0.24) $     (0.41)
---------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------
1996
---------------------------------------------------------------------------------------------------------
Operating Revenues.....................................$1,028,202  $  871,904  $    955,518  $   936,524
---------------------------------------------------------------------------------------------------------
Operating Income.......................................$  155,433  $   87,725  $     63,432  $     2,080
---------------------------------------------------------------------------------------------------------
Net Income/(Loss)......................................$   87,674  $   17,572  $     (3,567) $   (62,750)
---------------------------------------------------------------------------------------------------------
Earnings/(Loss) Per Common Share.......................$     0.68  $     0.14  $      (0.03) $     (0.49)
---------------------------------------------------------------------------------------------------------
</TABLE>
Consolidated Generation Statistics
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                               1997        1996        1995         1994         1993
---------------------------------------------------------------------------------------------------------
<S>                                           <C>         <C>         <C>          <C>           <C>
Source of Electric Energy:(kWh-millions)

Nuclear--Steam (b).........................     3,778       9,405      18,235        19,443       22,965
Fossil--Steam..............................    13,155       9,188       9,162         8,292        7,676
Hydro--Conventional........................     1,260       1,544       1,099         1,239        1,140
Hydro--Pumped Storage......................       959       1,217       1,209         1,195        1,269
Internal Combustion........................       184         206          37            13            8
Energy Used for pumping....................    (1,327)     (1,668)     (1,674)       (1,629)      (1,749)
---------------------------------------------------------------------------------------------------------
Net Generation.............................    18,009      19,892      28,068        28,553       31,309
---------------------------------------------------------------------------------------------------------
Purchased and Net Interchange..............    24,377      22,111      14,256        14,028       10,499
Company Use and Unaccounted for............    (2,802)     (2,473)     (2,706)       (2,535)      (2,591)
---------------------------------------------------------------------------------------------------------
Net Energy Sold............................    39,584      39,530      39,618        40,046       39,217
=========================================================================================================
System Capability--MW (b)(c)...............   8,312.0     8,894.0     8,394.8       8,494.8      7,795.3
System PeaK Demand--MW.....................   6,455.5     5,946.9     6,358.2      69,338.5      6,191.0
Nuclear Capacity--MW (b)(c)................   2,785.0     3,117.8     3,239.6       3,272.6      3,110.0
Nuclear Contribution to Total              
 Energy Requirements(%) (b)................      13.0        28.0        52.0          54.0         62.1
Nuclear Capacity Factor(%) (d).............      19.6        38.0        69.9          67.5         80.8
=========================================================================================================

(a) Reclassifications of prior data have been made to conform with the current presentation.
(b) Includes the NU system's entitlements in regional nuclear generating companies, net of capacity
    sales and purchases.
(c) Millstone 1, 2 and 3 have been out of service since November 4, 1995, Febuary 21, 1996 and
    March 30, 1996, respectively. The company has restructured its nuclear organization and is
    currently implementing comprehensive plans to restart the units. The actual date of the return to
    service for each of the units is dependent upon the completion of independent inspections and
    reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service 
    in early spring of 1998 and Millstone 2 three to fours months after Millstone 3. Millstone 1 is 
    currently in extended maintenance status.
(d) Represents the average capacity factor for the nuclear units operated by the NU system.

</TABLE>






NORTHEAST UTILITIES AND SUBSIDIARIES

Selected Consolidated Financial Data
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except             1997         1996
percentages and per share data)       (Restated)   (Restated)       1995         1994         1993
------------------------------------------------------------------------------------------------------
<S>                                   <C>          <C>          <C>          <C>          <C>
Balance Sheet Data:                                                                        
Net Utility Plant (a)................$  6,463,158 $  6,732,165 $  7,000,837 $  7,282,421 $  7,439,159
Total Assets.........................  10,414,412   10,741,748   10,559,574   10,584,880   10,668,164
Total Capitalization (b).............   6,472,504    6,659,617    6,820,624    7,035,989    7,309,898
Obligations Under Capital Leases (b).     207,731      206,165      230,482      239,121      243,760
------------------------------------------------------------------------------------------------------
Income Data:                                                                               
Operating Revenues...................$  3,834,806 $  3,792,148 $  3,750,560 $  3,642,742 $  3,629,093
Net(Loss)/Income.....................    (129,962)      38,929      282,434      286,874      249,953 (c)
------------------------------------------------------------------------------------------------------
Common Shate Data:                     
(Loss)/Earnings per Share............      ($1.01)       $0.30        $2.24        $2.30        $2.02 (c)
Dividends per Share (d)..............       $0.25        $1.38        $1.76        $1.76        $1.76
Number of Shares
 Outstanding--Average................ 129,567,708  127,960,382  126,083,645  124,678,192  123,947,631
Market Price--High...................     $14 1/4      $25 1/4      $25 3/8      $25 3/4      $28 7/8
Market Price--Low....................      $7 5/8       $9 1/2          $21      $20 3/8          $22
Market Price--Closing (end of year)..   $11 13/16      $13 1/8      $24 1/4      $21 5/8      $23 3/4
Book Value per Share (end of year)...      $16.67       $18.02       $19.08       $18.47       $17.89
Rate of Return Earned on Average
 Common Equity (%)...................        (5.8)         1.6         12.0         12.7         11.4
Market-to-Book Ratio (end of year)...         0.7          0.7          1.3          1.2          1.3
------------------------------------------------------------------------------------------------------
Capitalization: 
Common Shareholders' Equity..........          34%          35%          36%          33%          30%
Preferred Stock (b)(e)...............           6            6            7            9            9
Long-Term Debt (b)...................          60           59           57           58           61
------------------------------------------------------------------------------------------------------
Total Capitalization.................         100%         100%         100%         100%         100%
======================================================================================================

(a) Includes the reclassification of the unamortized PSNH
    acquisition costs to net utility plant.
(b) Includes portions due within one year.
(c) Includes the cumulative effect of change in accounting for municipal property
    tax expense, which increased earnings for common shares and earnings per share by
    $51.7 million and $0.42, respectively.
(d) Quarterly dividends were suspended effective March 25, 1997.
(e) Excludes $100 million of Monthly Income Preferred Securities.

</TABLE>


NORTHEAST UTILITIES AND SUBSIDIARIES

Consolidated Sales Statistics
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                           1997        1996        1995         1994 (a)          1993
---------------------------------------------------------------------------------------------------------
<S>                                     <C>         <C>         <C>            <C>             <C>
Revenues: (thousands)                                                                     
Residential.......................... $ 1,499,394 $ 1,501,465 $ 1,469,988    $ 1,430,239     $ 1,385,818
Commercial...........................   1,266,449   1,246,822   1,230,608      1,173,808 (b)   1,043,125
Industrial...........................     560,782     565,900     583,204        559,801 (b)     649,876
Other Utilities......................     329,764     315,577     303,004        330,801         383,129
Streetlighting and Railroads.........      48,867      48,053      47,510         45,943          45,480
Non-Franchised Sales.................      21,476       8,360        -              -               -
Miscellaneous........................      47,446      23,513      50,353         44,140          60,008
---------------------------------------------------------------------------------------------------------
   Total Electric....................   3,774,178   3,709,690   3,684,667      3,584,732       3,567,436
Other................................      60,628      82,458      65,893         58,010          61,657
---------------------------------------------------------------------------------------------------------
   Total............................. $ 3,834,806 $ 3,792,148 $ 3,750,560    $ 3,642,742     $ 3,629,093
=========================================================================================================
Sales: (kWh - millions)                                                                   
Residential..........................      12,099      12,241      12,005         12,231          11,988
Commercial...........................      12,091      12,012      11,737         11,649 (b)      10,304
Industrial...........................       6,801       6,820       6,842          6,729 (b)       7,572
Other Utilities......................       8,034       8,032       8,718          9,123           9,046
Streetlighting and Railroads.........         318         319         316            314             307
Non-Franchised Sales.................         241          50        -              -               -
---------------------------------------------------------------------------------------------------------
   Total.............................      39,584      39,474      39,618         40,046          39,217
=========================================================================================================
Customers: (average)                                                            
Residential..........................   1,535,134   1,532,015   1,526,127      1,513,987       1,503,182
Commercial...........................     159,350     157,347     156,652        154,703 (b)     155,487
Industrial...........................       7,804       7,792       7,861          7,813 (b)       6,272
Other................................       3,929       3,916       3,878          3,818           3,793
---------------------------------------------------------------------------------------------------------
   Total.............................   1,706,217   1,701,070   1,694,518      1,680,321       1,668,734
=========================================================================================================
Average Annual Use                     
   per Residential Customer (kWh)....       7,898       8,005       7,880 (c)      8,152           7,987
=========================================================================================================
Average Annual Bill
   per Residential Customer.......... $    978.72 $    980.19 $    964.88 (c)$    953.23     $    923.32
=========================================================================================================
Average Revenue (in cents) per kWh:    
Residential..........................       12.39       12.27       12.24          11.69           11.56
Commercial...........................       10.47       10.38       10.49          10.08           10.12
Industrial...........................        8.25        8.30        8.52           8.32            8.58
=========================================================================================================

(a) Effective January 1, 1994, the accounting for unbilled revenues was 
    revised to report unbilled revenues by customer class.
(b) Effective January 1, 1994, approximately 1,300 customers previously
    classified as commercial customers were reclassified to industrial
    customers.
(c) Effective January 1, 1996, the amounts shown reflect billed and 
    unbilled sales. 1995 has been restated to reflect this change.
</TABLE>