<PAGE>














Annual Report 1996
The Narragansett Electric Company

A Subsidiary of
New England Electric System












                         {LOGO} Narragansett Electric
                         A NEES Company

<PAGE>
The Narragansett Electric Company
280 Melrose Street
Providence, Rhode Island 02901

Directors
(As of January 1, 1997)
Joan T. Bok
Chairman of the Board of New England Electric System

Stephen A. Cardi
Treasurer, Cardi Corporation (Construction), Warwick, Rhode
Island

Frances H. Gammell
Senior Vice President, Treasurer, and Secretary, Original
Bradford Soap Works, Inc., West Warwick, Rhode Island

Joseph J. Kirby
Chairman and Chief Executive Officer, Washington Trust Bancorp,
Inc., Westerly, Rhode Island

Robert L. McCabe
President and Chief Executive Officer of the Company

John W. Rowe
President and Chief Executive Officer of New England Electric
System

Richard P. Sergel
Chairman of the Company and Senior Vice President of New England
Electric System

William E. Trueheart
Visiting Scholar of Graduate School of Education, Harvard
University, Cambridge, Massachusetts

John A. Wilson, Jr.
Consultant to and former President of Wanskuck Company (Cable
reel manufacturer), Providence, Rhode Island and Consultant to
Hinkley, Allen, Tobin and Silverstein

Officers
(As of January 1, 1997)

Richard P. Sergel
Chairman of the Company and Senior Vice President of New England
Electric System

Robert L. McCabe 
President and Chief Executive Officer

William Watkins, Jr.
Executive Vice President

Richard W. Frost
Vice President

<PAGE>
Alfred D. Houston
Vice President and Treasurer of the Company and Executive Vice
President and Chief Financial Officer of New England Electric
System

Shannon M. Larson
Vice President

Richard Nadeau
Vice President

Michael F. Ryan
Vice President

Thomas G. Robinson
Secretary of the Company and General Counsel of an affiliate

John G. Cochrane
Assistant Treasurer of the Company and of certain affiliates and
Vice President of an affiliate

Craig L. Eaton
Assistant Secretary

Howard W. McDowell
Controller of the Company and of certain affiliates and Treasurer
of certain affiliates

Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock
Fleet National Bank, Providence, Rhode Island

This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.

<PAGE>
The Narragansett Electric Company

  The Narragansett Electric Company is a wholly-owned subsidiary
of New England Electric System (NEES) operating in Rhode Island.
The Company's business is the distribution and sale of
electricity at retail. Electric service is provided to
approximately 330,000 customers in 27 cities and towns having a
population of approximately 725,000 (1990 Census). The Company's
service area, which includes urban, suburban, and rural areas,
covers approximately 80 percent of Rhode Island, and includes the
cities of Providence, East Providence, Cranston, and Warwick. The
diversified economy of the Company's service area produces
fabricated metal products, electrical and industrial machinery,
transportation equipment, textiles, jewelry, silverware, and
chemical products. In addition, a broad range of professional,
banking, medical, and educational institutions is served.  Rhode
Island legislation passed in 1996 allows utility customers in
Rhode Island to choose their power supplier.  This customer
choice is being phased in over 12 months beginning July 1997. 
Distribution companies, including the Company, would be required
to deliver the power to their customers (see "Industry
Restructuring" section of Financial Review).

  The properties of the Company include an integrated system of
transmission and distribution lines and substations. In addition,
the Company owns a 10 percent share of the 489 megawatt
Manchester Street generating station.  The entire output of this
plant is made available to New England Power Company (NEP), the
Company's wholesale generating affiliate, as part of the
integrated NEES system. Under an all-requirements contract with
NEP, the Company purchases its electric energy requirements from
NEP. The contract provides for the integration of the Company's
generating and transmission facilities with NEP's facilities in
order to achieve maximum economy and reliability. The contract
also provides for the application of credits against the
Company's power bills from NEP for costs associated with the
Company's facilities so integrated.  NEP and the Company agreed
to the divestiture of their fossil and hydroelectric generating
facilities as part of industry restructuring.  The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value.  In addition, the Company's all-requirements
contract with NEP has been amended to allow for early termination
of all-requirements service.  The amendment provides that upon
early termination, the Company's share of the cost of NEP's
above-market generation commitments will be recovered through a
contract termination charge.  This charge will, in turn, be paid
by customers that use the Company's distribution facilities.

<PAGE>
Report of Independent Accountants

The Narragansett Electric Company, Providence, Rhode Island:

  We have audited the accompanying balance sheets of The
Narragansett Electric Company (the Company), a wholly-owned
subsidiary of New England Electric System, as of December 31,
1996 and 1995 and the related statements of income, retained
earnings, and cash flows for each of the three years in the
period ended December 31, 1996. These financial statements are
the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.

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

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



Boston, Massachusetts         COOPERS & LYBRAND L.L.P.
February 28, 1997

<PAGE>
The Narragansett Electric Company
Financial Review

Industry Restructuring
  
  For the past several years, the electric utility business has
been subjected to rapidly increasing competitive pressures
stemming from a number of trends, including the presence of
surplus generating capacity, a disparity in electric rates among
regions of the country, improvements in generation efficiency,
increasing demand for customer choice, and new regulations and
legislation intended to foster competition.

  In the recent past, this competition was most prominent in the
bulk power market, in which nonutility generators have
significantly increased their market share.  Despite increased
competition in the bulk power market, competition in the retail
market has been limited as electric utilities have maintained
exclusive franchises for the retail sale of electricity in
specified service territories.

  In states across the country, including Rhode Island, there
have been proposals to allow retail customers to choose their
electricity supplier, with incumbent utilities required to
deliver that electricity over their transmission and distribution
systems (also known as "retail wheeling").  When electricity
customers are allowed to choose their electricity supplier,
utilities across the country will face the risk that market
prices may not be sufficient to recover the costs of the
commitments incurred to supply customers under a regulated
structure.  The amounts by which costs exceed market prices are
commonly referred to as "stranded costs."

  The Company currently purchases electricity on behalf of its
customers under a wholesale all-requirements contract with the
Company's wholesale generating affiliate, New England Power
Company (NEP).

  As described below, comprehensive legislation was enacted in
Rhode Island which, when all regulatory approvals are in place,
would allow recovery of NEP's above-market commitments to retail
customers in Rhode Island, which make up 22 percent of NEP's all-
requirements sales.

  In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in that state the opportunity
to choose their electricity supplier.  Under the Rhode Island
statute, state accounts, certain new customers, and the largest
manufacturing customers will be able to choose their supplier
beginning on July 1, 1997.  These customers represent
approximately 10 percent of the Company's kilowatt-hour (kWh)
sales.  The balance of Rhode Island customers will be able to
choose their supplier in 1998, with an additional 10 percent of
customers load having choice on January 1 and the remainder on
<PAGE>
July 1.  All Rhode Island customers would have choice of supplier
beginning at an earlier date if retail access becomes available
to 40 percent or more of the kWh sales in New England by that
date.

  The statute calls for NEP's contract with the Company to be
amended to permit a gradual, early termination of
all-requirements service. The amendment provides that, in return,
the Company's 22 percent share of the cost of NEP's above-market
generation commitments (estimated at approximately $1 billion on
a present-value basis) would be recovered through a contract
termination charge.  This charge will, in turn, be paid by
customers that use the Company's distribution facilities.  Those
commitments consist of (i) generating plant commitments, (ii)
regulatory assets, (iii) the above-market component of purchased
power contracts, and (iv) the operating cost of nuclear plants
which cannot be avoided by shutting down the plants, including
nuclear decommissioning.

  Sunk costs associated with generating plants and regulatory
assets would be recovered over a period of 12.5 years.  The
above-market component of purchased power contracts and the
nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond
12 years.  The transition access charge would be reduced to
reflect the net proceeds from the sale of the New England
Electric System (NEES) companies' generating assets.  (See
"Divestiture of Generation Business" section below.)  The initial
transition access charge, before the application of those
proceeds, would be set at 2.8 cents per kWh through December 31,
2000, and is expected to decline thereafter.

  The statute also establishes performance-based rates for
distribution utilities, such as the Company.  Under the statute,
the Company increased distribution rates by approximately $11
million in 1997, and is entitled to a similar increase in 1998.  
In addition, in 1997, the Company's return on equity from
distribution operations will be subject to a floor of 6 percent
and a ceiling of 11 percent.  Earnings over the ceiling will be
shared equally between customers and shareholders up to a maximum
return on equity from distribution operations of 12.5 percent.  
This sharing results in an effective cap on shareholder's return
on equity of 11.75 percent.  To the extent that earnings fall
below the floor, the Company will be authorized to surcharge
customers for the shortfall.

  NEP and the Company filed with the Federal Energy Regulatory
Commission (FERC) an amendment to their all-requirements contract 
in order to implement the statute.  The FERC has set down the
amendment for hearing.  The Company has indicated it is willing
to make certain changes to its plan in Rhode Island to parallel
provisions in a similar Massachusetts settlement.  The
Massachusetts settlement was approved by the Massachusetts
Department of Public Utilities on February 26, 1997.  The
settlement provides for retail choice for Massachusetts customers
<PAGE>
in 1998 and the recovery of NEP's above-market commitments to
serve those customers.  Implementation of other aspects of the
statute is subject to approval of the Rhode Island Public
Utilities Commission (RIPUC).

  A number of proposals for federal legislation related to
industry restructuring have been brought forward for
consideration by the current Congress. The scope and aim of these
vary widely; however, the NEES companies and others will argue
that state settlements should be respected. The Company cannot
predict what federal legislation, if any, may be enacted.

Divestiture of Generation Business

  NEP and the Company agreed to the divestiture of their fossil
and hydroelectric generating facilities as part of industry
restructuring.  Such divestiture must be accomplished within six
months of the later of the commencement of retail choice in
Massachusetts, currently scheduled for January 1, 1988, or the
receipt of all necessary regulatory approvals.  The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value.  Proposals are being solicited for the
acquisition of the nonnuclear generating business, with the
objective of reaching definitive purchase and sale agreements by
mid-1997.  Closing would follow the receipt of regulatory
approvals, which are expected to take at least six to 12 months
following the execution of purchase and sale agreements.  The
Rhode Island statute also requires the Company to transfer its
transmission assets to NEP at net book value.

Risk Factors

  The major risk factors affecting the Company relate to the
possibility of adverse regulatory or judicial decisions or
legislation which limits the level of revenues the Company is
allowed to charge for its services.  While substantial progress
has been made in resolving the uncertainty regarding recovery by
the Company of stranded costs billed to it by NEP, significant
risks remain.  These risks are primarily attributable to the
potential that ultimately the statute, referred to above, will
not be implemented in the manner anticipated by the Company
and/or the possibility of other state or federal legislation
which would increase the risks to the Company above those
contained in the statute.

Accounting Implications

  Historically, electric utility rates have been based on a
utility's costs.  As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general.  Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets, and thereby defer 
<PAGE>
the income statement impact of certain costs expected to be
recovered in future rates.  The Company has recorded
approximately $44 million in net regulatory assets in compliance
with FAS 71.  The Company believes that the continuing rate-
making policies and practices of the RIPUC and the terms of the
Rhode Island statute will enable the Company to recover both its
specific costs of providing ongoing distribution services and
stranded costs billed to it by NEP.  The Company believes that
these factors will allow it to continue to apply FAS 71.  In the
event that future circumstances should cause the application of
FAS 71 to be discontinued, a noncash write-off of previously
established regulatory assets and liabilities would be required.  

Overview

  Net income in 1996 decreased by $1 million.  This decrease was
primarily due to (i) the completion of the amortization, in
accordance with a rate agreement, of the initial effect of
recording unbilled revenues as well as (ii) a decrease in
allowance for funds used during construction (AFDC) primarily due
to the completion in the second half of 1995 of the Manchester
Street Station.  These decreases were partially offset by the
effects of a rate increase that went into effect in late 1995.

  Net income for 1995 increased by $9 million compared with
1994.  This increase reflects the 1995 commencement of the
recovery of the Company's investment in the Manchester Street
Station, and related transmission facilities that went into
service in 1994.   The increase in earnings in 1995 also reflects
the recognition of unbilled revenues over a 21-month period that
ended December 31, 1995.  These increases were partially offset
by increased depreciation expense and increased interest expense.

Operating Revenue

  The following table summarizes the changes in operating
revenue:
             Increase (Decrease) in Operating Revenue

(In Millions)                                         1996          1995
                                                      ----          ----
Sales growth                                           $ 1           $ 2
Fuel recovery                                            3            11
Rate changes                                            11             1
Unbilled revenues recognized
 under rate agreements                                  (8)            2
Purchased power cost adjustment
 (PPCA) mechanism                                       (4)            1
Demand-side management (DSM) recovery                    -            (1)
Other                                                    1             1
                                                       ---           ---
                                                       $ 4           $17
                                                       ===           ===

  KWh sales to ultimate customers increased less than 1 percent
in both 1996 and 1995.

<PAGE>
  The Company's rates contain a fuel clause and a PPCA
provision.  These mechanisms are designed to allow the Company to
pass on to its customers changes in purchased energy costs from
NEP.

  Rate changes primarily represent a $12 million general rate
increase that went into effect in December 1995.  Also, in 1994,
the RIPUC approved a rate agreement for the Company that provided
for the recognition, for accounting purposes, of $14 million of
unbilled revenues over a 21-month period which ended in December
1995.

  The Company has received approval from the RIPUC to recover 
DSM program expenditures in rates on a current basis.  These
expenditures were $10 million, $9 million, and $10 million in
1996, 1995, and 1994, respectively.  Since 1990, the Company has
been allowed to earn incentives based on the results of its DSM
programs.  The Company recorded before-tax incentives of $0.2
million, $0.5 million, and $0.6 million in 1996, 1995, and 1994,
respectively.

Operating Expenses

  The following table summarizes the changes in operating
expenses:
            Increase (Decrease) in Operating Expenses

(In Millions)                                     1996      1995
                                                  ----      ----
  Fuel for generation and electric energy:
     Fuel costs                                             $ 3            $11
     Integrated facilities credit from NEP                    3            (18)
     Purchases and demand charges and other                  (4)             -
  Other operation and maintenance
     DSM                                                      1              -
     Other                                                    1             (2)
  Depreciation                                               (4)             7
  Taxes, other than income taxes                              2              1
  Income taxes                                                1              6
                                                            ---            ---
                                                            $ 3            $ 5
                                                            ===            ===
  The entire output of the Company's 10 percent share of the
Manchester Street generating station is made available to NEP,
and the Company receives a credit on its purchased power bill
from NEP for its fuel and other generation and transmission
costs.  The decrease in these credits in 1996 and a portion of
the increase in 1995 reflects fluctuations in the level of
reimbursable costs being incurred in the dismantlement of the
Company's previously retired South Street generating station.  In
addition, these credits increased in both 1996 and 1995 in
connection with the completion of the Manchester Street Station
in 1995.  Both of these factors are also reflected in the changes
in depreciation expense in 1996 and 1995.

<PAGE>
  The reduction in other operation and maintenance expenses in
1995 reflects decreased distribution system related expenses,
partially offset by increased postretirement benefit expenses.

  The increases in taxes other than income taxes in both 1996
and 1995 is due primarily to increased municipal property taxes. 
The 1996 increase is primarily attributable to the Manchester
Street Station.

Allowance for Funds Used During Construction

  AFDC decreased in both 1996 and 1995.  The 1996 decrease is
due to the completion in 1995 of the Manchester Street Station,
and the 1995 decrease is due to the completion in 1994, of
transmission facilities related to the Manchester Street Station.

Hazardous Waste
  
  The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products.  The Company has been named as a
potentially responsible party by either federal or state
environmental regulatory agencies for three sites at which
hazardous waste is alleged to have been disposed. The Company is
aware of approximately five sites on which gas was manufactured
or manufactured gas was stored that were owned either by the
Company or by its predecessor companies. A more detailed
discussion of potential hazardous waste liabilities is contained
in Note D-2 of the Notes to the Financial Statements. Predicting
the potential costs to investigate and remediate hazardous waste
sites continues to be difficult.  The Company believes that
hazardous waste liabilities for all sites of which it is aware
are not material to its financial position.

Electric and Magnetic Fields (EMF)

  In recent years, concerns have been raised about whether EMF,
which occur near transmission and distribution lines as well as
near household wiring and appliances, cause or contribute to
adverse health effects.  Numerous studies on the effects of these
fields, some of them sponsored by electric utilities (including
NEES companies), have been conducted and are continuing.  In
October 1996, the National Research Council of the National
Academy of Sciences released a report stating no conclusive and
consistent evidence demonstrates that exposures to residential
EMF produce adverse health effects.  It is impossible to predict
the ultimate impact on the Company and the electric utility
industry if further investigations were to demonstrate that the
present electricity delivery system is contributing to increased
risk of cancer or other health problems.

  Several state courts have recognized a cause of action for
damage to property values in transmission line condemnation cases
based on the fear that power lines cause cancer.  It is difficult
to predict what the impact on the Company would be if this cause
of action is recognized in Rhode Island and in contexts other
than condemnation cases.
<PAGE>
Utility Plant Expenditures and Financing

  Cash expenditures for utility plant totaled $53 million in
1996.  The funds necessary for utility plant expenditures during
1996 were primarily provided by net cash from operating
activities, after the payment of dividends.  Cash expenditures
for utility plant for 1997 are estimated to be approximately $45
million.  Internally generated funds are estimated to provide
approximately 70 percent of capital expenditure requirements in
1997.  Cash expenditures for utility plant are also expected to
be funded through the issuance of long-term debt.

  In 1996, the Company issued $2 million of first mortgage bonds
bearing an interest rate of 7.24 percent to refinance higher rate
bonds.  In November 1995, the Company retired $16 million of
first mortgage bonds prior to maturity and incurred premiums of
$1.9 million.

  At December 31, 1996, the Company had $19 million of
short-term debt outstanding including $14 million of commercial
paper borrowings and $5 million of borrowings from affiliates.  
As of December 31, 1996, the Company had lines of credit with
banks totaling $41 million.  There were no borrowings under these
lines of credit at December 31, 1996.


<PAGE>
The Narragansett Electric Company
Statements of Income
<TABLE>
<CAPTION>
Year Ended December 31, (In Thousands)         1996       1995       1994
                                               ----       ----       ----
<S>                                             <C>        <C>        <C>
Operating revenue                          $503,585   $499,113   $481,669
                                           --------   --------   --------
Operating expenses:
 Fuel for generation and purchased electric 
  energy, (principally from New England 
  Power Company, an affiliate)              297,060    294,652    300,888
 Other operation                             71,625     71,814     72,872
 Maintenance                                 13,009     11,174     12,281
 Depreciation                                27,899     31,533     24,813
 Taxes, other than federal income taxes      38,530     36,627     35,818
 Federal income taxes                        11,951     10,888      4,883
                                           --------   --------   --------
   Total operating expenses                 460,074    456,688    451,555
                                           --------   --------   --------
Operating income                             43,511     42,425     30,114
                                           --------   --------   --------
Other income:                                                            
 Allowance for equity funds used 
  during construction                                      106      1,028
 Other income (expense), net                  (732)      (192)      (856)
                                           --------   --------   --------
   Operating and other income                42,779     42,339     30,286
                                           --------   --------   --------
Interest:
 Interest on long-term debt                  17,205     16,627     14,334
 Other interest                               2,883      3,663      2,897
 Allowance for borrowed funds used during
  construction   credit                       (263)    (1,861)    (1,534)
                                           --------   --------   --------
   Total interest                            19,825     18,429     15,697
                                           --------   --------   --------
Net income                                  $22,954    $23,910    $14,589
                                           ========   ========   ========


Statements of Retained Earnings

Year Ended December 31, (In Thousands)         1996       1995       1994
                                               ----       ----       ----
Retained earnings at beginning of year     $108,227    $91,556    $81,659
Net income                                   22,954     23,910     14,589
Dividends declared on cumulative 
 preferred stock                            (2,143)    (2,143)    (2,143)
Dividends declared on common stock, 
 $8.00, $4.50, and $2.25 per share, 
  respectively                              (9,060)    (5,096)    (2,549)
                                           --------   --------   --------
Retained earnings at end of year           $119,978   $108,227    $91,556
                                           ========   ========   ========


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

</TABLE>
<PAGE>
The Narragansett Electric Company
Balance Sheets
<TABLE>
<CAPTION>
At December 31, (In Thousands)                        1996           1995
                                                      ----           ----
Assets
<S>                                                     <C>           <C>
Utility plant, at original cost                     $742,481     $699,906
  Less accumulated provisions for depreciation       187,690      173,391
                                                    --------     --------
                                                     554,791      526,515
  Construction work in progress                        5,392        8,733
                                                    --------     --------
      Net utility plant                              560,183      535,248
                                                    --------     --------
Current assets:  
  Cash                                                 1,727        1,999
  Accounts receivable:
   From sales of electric energy                      54,426       59,760
   Other (including $1,253 and $1,464 from
    affiliates)                                        3,415        9,330
      Less reserves for doubtful accounts              5,149        5,516
                                                    --------     --------
                                                      52,692       63,574
Unbilled revenues (Note A-3)                          15,300       16,500
Fuel, materials, and supplies, at average cost         4,300        6,245
Prepaid and other current assets                      15,919       15,887
                                                    --------     --------
      Total current assets                            89,938      104,205
                                                    --------     --------
Deferred charges and other assets (Note B)            56,881       60,168
                                                    --------     --------
                                                    $707,002     $699,621
                                                    ========     ========
Capitalization and Liabilities

Capitalization:
  Common stock, par value $50 per share, 
   authorized and outstanding 1,132,487 shares       $56,624      $56,624
  Premiums on preferred stocks                           170          170
  Other paid-in capital                               80,000       80,000
  Retained earnings                                  119,978      108,227
                                                    --------     --------
      Total common equity                            256,772      245,021
  Cumulative preferred stock, par value
   $50 per share                                      36,500       36,500
  Long-term debt                                     178,517      210,892
                                                    --------     --------
       Total capitalization                          471,789      492,413
                                                    --------     --------
Current liabilities:
  Long-term debt due in one year                      32,500
  Short-term debt (including $5,300 and $1,000 
    to affiliates)                                    19,025       22,675
  Accounts payable (including $40,425 and 
    $38,510 to affiliates)                            45,221       46,247
Accrued liabilities:
    Taxes                                              3,877        6,380
    Interest                                           5,677        5,847
    Other accrued expenses (Note F)                   11,949       19,558
  Customer deposits                                    5,638        5,691
  Dividends payable                                    2,801        1,102
                                                    --------     --------
      Total current liabilities                      126,688      107,500
                                                    --------     --------
Deferred federal income taxes                         81,880       76,017
Unamortized investment tax credits                     7,517        8,016
Other reserves and deferred credits                   19,128       15,675
Commitments and contingencies (Note D)
                                                    --------     --------
                                                    $707,002     $699,621
                                                    ========     ========

The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
The Narragansett Electric Company
Statements of Cash Flows

<TABLE>
<CAPTION>
Year Ended December 31, (In Thousands)           1996                1995           1994
                                                 ----                ----           ----
<S>                                               <C>                 <C>            <C>
Operating activities:

Net income                                    $22,954             $23,910        $14,589
Adjustments to reconcile net income to 
   net cash provided by operating activities:
  Depreciation                                 27,899              31,533         24,813
  Deferred federal income taxes and 
    investment tax credits, net                 4,177               3,009          3,422
  Allowance for funds used during 
    construction                                (263)             (1,967)        (2,562)
  Amortization of unbilled revenues                               (8,209)        (6,158)
  Decrease (increase) in accounts receivable,
    net and unbilled revenues                  12,082             (2,215)       (14,163)
  Decrease (increase) in fuel, materials, 
    and supplies                                1,945             (1,075)          (598)
  Decrease (increase) in prepaid and 
    other current assets                         (32)             (1,894)        (2,478)
  Increase (decrease) in accounts payable     (1,026)             (9,892)          5,134
  Increase (decrease) in other  
    current liabilities                      (10,335)               9,320         12,312
  Other, net                                    8,236               5,931          5,877
                                            ---------           ---------      ---------
    Net cash provided by operating 
    activities                                $65,637             $48,451        $40,188
                                            ---------           ---------      ---------
Investing activities:

Plant expenditures, excluding allowance for
  funds used during construction            $(52,574)           $(72,897)      $(92,503)
Other investing activities                      (181)               (251)          (911)
                                            ---------           ---------      ---------
   Net cash used in investing activities    $(52,755)           $(73,148)      $(93,414)
                                            ---------           ---------      ---------
Financing activities:

Capital contributions from parent                                 $20,000        $15,000
Dividends paid on common stock               $(7,361)             (4,813)        (2,831)
Dividends paid on preferred stock             (2,143)             (2,143)        (2,143)
Changes in short-term debt                    (3,650)             (7,125)         10,075
Long-term debt   issues                         2,000              38,000         33,000
Long-term debt   retirements                  (2,000)            (16,000)               
Premium on reacquisition of long-term debt                                       (1,936)               
                                            ---------           ---------      ---------
  Net cash provided by (used in)
    financing activities                    $(13,154)             $25,983        $53,101
                                            ---------           ---------      ---------
Net increase (decrease) in cash and 
  cash equivalents                             $(272)              $1,286         $(125)
Cash and cash equivalents at 
  beginning of year                             1,999                 713            838
                                            ---------           ---------      ---------
Cash and cash equivalents at end of year       $1,727              $1,999           $713
                                            =========           =========      =========

Supplementary Information:

Interest paid less amounts capitalized        $18,620             $17,050        $14,015
                                            ---------           ---------      ---------
Federal income taxes paid                      $8,873              $1,084         $2,982
                                            ---------           ---------      ---------

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

Note A - Significant Accounting Policies

1.                              Nature of Operations:

The Company is a wholly-owned subsidiary of New England Electric
System (NEES) operating in Rhode Island. The Company's business
is the distribution and sale of electricity at retail. Electric
service is provided to approximately 330,000 customers in 27
cities and towns having a population of approximately 725,000
(1990 Census). The Company's service area, which includes urban,
suburban, and rural areas, covers approximately 80 percent of
Rhode Island.  The properties of the Company include an
integrated system of transmission and distribution lines and
substations. In addition, the Company owns a 10 percent share of
the 489 megawatt Manchester Street generating station.  The
entire output of this plant is made available to New England
Power Company (NEP), the Company's wholesale generating
affiliate, as part of the integrated NEES system. Under a
contract with NEP, the Company purchases all of its electric
energy requirements from NEP.  The contract provides for the
integration of the Company's generating and transmission
facilities with NEP's facilities in order to achieve maximum
economy and reliability.  The contract also provides for the
application of credits against the Company's power bills from NEP
for costs associated with the Company's facilities so integrated. 
This contract requires either party to give seven years notice
prior to terminating the contract.  (See Note B for a discussion
of industry restructuring and NEP's and the Company's proposed
divestiture of their generating business.)

2.                                System of Accounts:

The accounts of the Company are maintained in accordance with the
Uniform System of Accounts prescribed by regulatory bodies having
jurisdiction.

In preparing the financial statements, management is required to
make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets and revenues and
expenses for the period.  These estimates may differ from actual
amounts if future circumstances cause a change in the assumptions
used to calculate these estimates.

3.                            Electric Sales Revenue:

The Company accrues revenues for electricity delivered but not
yet billed (unbilled revenues).  Included in income were $8
million in 1995 and $6 million in 1994, which represented the
amortization over 21 months of the initial effect of recording
unbilled revenues, in accordance with a rate agreement.  Accrued
revenues are also recorded in accordance with rate adjustment
mechanisms.

<PAGE>
4. Allowance for Funds Used During Construction (AFDC):

The Company capitalizes AFDC as part of construction costs.  AFDC
represents the composite interest and equity costs of capital
funds used to finance that portion of construction costs not yet
eligible for inclusion in rate base. AFDC is capitalized in
"Utility plant" with offsetting noncash credits to "Other income"
and "Interest." This method is in accordance with an established
rate-making practice under which a utility is permitted a return
on, and the recovery of, prudently incurred capital costs through
their ultimate inclusion in rate base and in the provision for
depreciation. The composite AFDC rates were 5.3 percent, 6.2
percent, and 6.8 percent in 1996, 1995, and 1994, respectively.

5.                                      Depreciation:

Depreciation is provided annually on a straight-line basis. The
provision for depreciation as a percentage of weighted average
depreciable property was 4.0 percent, 5.0 percent, and 4.5
percent in 1996, 1995, and 1994, respectively.  The change in the
depreciation rates in 1996 and 1995 is primarily due to the
recognition through depreciation expense of dismantlement costs
for a retired generating facility.

6.                                              Cash:

The Company classifies short-term investments with a maturity of
90 days or less at time of purchase as cash.

Note B - Industry Restructuring

For the past several years, the electric utility business has
been subjected to rapidly increasing competitive pressures
stemming from a number of trends, including the presence of
surplus generating capacity, a disparity in electric rates among
regions of the country, improvements in generation efficiency,
increasing demand for customer choice, and new regulations and
legislation intended to foster competition.

In the recent past, this competition was most prominent in the
bulk power market, in which nonutility generators have
significantly increased their market share.  Despite increased
competition in the bulk power market, competition in the retail
market has been limited as electric utilities have maintained
exclusive franchises for the retail sale of electricity in
specified service territories.

In states across the country, including Rhode Island, there have
been proposals to allow retail customers to choose their
electricity supplier, with incumbent utilities required to
deliver that electricity over their transmission and distribution
systems (also known as "retail wheeling").  When electricity
customers are allowed to choose their electricity supplier,
utilities across the country will face the risk that market
prices may not be sufficient to recover the costs of the 
<PAGE>
commitments incurred to supply customers under a regulated
structure.  The amounts by which costs exceed market prices are
commonly referred to as "stranded costs."

The Company currently purchases electricity on behalf of its
customers under a wholesale all-requirements contract with NEP.  

As described below, comprehensive legislation was enacted in
Rhode Island which, when all regulatory approvals are in place,
would allow recovery of NEP's above-market commitments to retail
customers in Rhode Island, which make up 22 percent of NEP's all-
requirements sales.

In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in that state the opportunity
to choose their electricity supplier.  Under the Rhode Island
statute, state accounts, certain new customers, and the largest
manufacturing customers will be able to choose their supplier
beginning on July 1, 1997.  These customers represent
approximately 10 percent of the Company's kilowatt-hour (kWh)
sales.  The balance of Rhode Island customers will be able to
choose their supplier in 1998, with an additional 10 percent of
customers load having choice on January 1 and the remainder on
July 1. All Rhode Island customers would have choice of supplier
beginning January 1, 1998 if retail access is available to 40
percent or more of the kWh sales in New England by that date.  

The statute calls for NEP's contract with the Company to be
amended to permit a gradual, early termination of
all-requirements service.  The amendment provides that, in
return, the Company's 22 percent share of the cost of NEP's
above-market generation commitments (estimated at approximately
$1 billion on a present-value basis) would be recovered through a
contract termination charge.  This charge will, in turn, be paid
by customers that use the Company's distribution facilities.
Those commitments consist of (i) generating plant commitments,
(ii) regulatory assets, (iii) the above-market component of
purchased power contracts, and (iv) the operating cost of nuclear
plants which cannot be avoided by shutting down the plants,
including nuclear decommissioning.

Sunk costs associated with generating plants and regulatory
assets would be recovered over a period of 12.5 years.  The
above-market component of purchased power contracts and the
nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond
12 years.  The transition access charge would be reduced to
reflect the net proceeds from the sale of the NEES companies'
generating assets. (See "Divestiture of Generation Business"
section below.) The initial transition access charge, before the
application of those proceeds, would be set at 2.8 cents per kWh
through December 31, 2000, and is expected to decline thereafter.

The statute also establishes performance-based rates for
distribution utilities, such as the Company.  Under the statute,
the Company increased distribution rates by approximately $11 
<PAGE>
million in 1997, and is entitled to a similar increase in 1998.  
In addition, in 1997, the Company's return on equity from
distribution operations will be subject to a floor of 6 percent
and a ceiling of 11 percent.  Earnings over the ceiling will be
shared equally between customers and shareholders up to a maximum
return on equity from distribution operations of 12.5 percent.  
This sharing results in an effective cap on shareholder's return
on equity of 11.75 percent.  To the extent that earnings fall
below the floor, the Company will be authorized to surcharge
customers for the shortfall.

NEP and the Company filed with the Federal Energy Regulatory
Commission (FERC) an amendment to their all-requirements contract
in order to implement the statute.  The FERC has set down the
amendment for hearing.  The Company has indicated it is willing
to make certain changes to its plan in Rhode Island to parallel
provisions in a similar Massachusetts settlement.  The
Massachusetts settlement was approved by the Massachusetts
Department of Public Utilities on February 26, 1997.  The
settlement provides for retail choice for Massachusetts customers
in 1998 and the recovery of NEP's above-market commitments to
serve those customers.  Implementation of other aspects of the
statute is subject to approval of the Rhode Island Public
Utilities Commission (RIPUC).

A number of proposals for federal legislation related to industry
restructuring have been brought forward for consideration by the
current Congress. The scope and aim of these vary widely;
however, the NEES companies and others will argue that state
settlements should be respected. The Company cannot predict what
federal legislation, if any, may be enacted.

Divestiture of Generation Business

NEP and the Company agreed to the divestiture of their fossil and
hydroelectric generating facilities as part of industry
restructuring. Such divestiture must be accomplished within six
months of the later of the commencement of retail choice in
Massachusetts, currently scheduled for January 1, 1988, or the
receipt of all necessary regulatory approvals.  The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value.  Proposals are being solicited for the
acquisition of the nonnuclear generating business, with the
objective of reaching definitive purchase and sale agreements by
mid-1997.  Closing would follow the receipt of regulatory
approvals, which are expected to take at least six to 12 months
following the execution of purchase and sale agreements.  The
Rhode Island statute also requires the Company to transfer its
transmission assets to NEP at net book value.

Accounting Implications

Historically, electric utility rates have been based on a
utility's costs.  As a result, electric utilities are subject to
certain accounting standards that are not applicable to other 
<PAGE>
business enterprises in general.  Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets, and thereby defer
the income statement impact of certain costs expected to be
recovered in future rates.  The Company has recorded
approximately $44 million in net regulatory assets in compliance
with FAS 71. The Company believes that the continuing rate-making
policies and practices of the RIPUC and the terms of the Rhode
Island statute will enable the Company to recover both its
specific costs of providing ongoing distribution services and
stranded costs billed to it by NEP.  The Company believes that
these factors will allow it to continue to apply FAS 71.  In the
event that future circumstances should cause the application of
FAS 71 to be discontinued, a noncash write-off of previously
established regulatory assets and liabilities would be required. 


The components of regulatory assets are as follows:
<TABLE>
<CAPTION>
At December 31, (In Thousands)                             1996           1995
                                                           ----           ----
<S>                                                         <C>            <C>
Regulatory assets (liabilities) included in current
 assets and liabilities:
 Rate adjustment mechanisms (see Note F)               $(2,870)            $(7,661)
                                                       --------            --------
Regulatory assets included in deferred charges:
 Deferred SFAS No. 109 costs (see Note C)                30,439              29,251
 Unamortized losses on reacquired debt                   13,287              13,918
 Deferred SFAS No. 106 costs (see Note E 2)               2,487               4,894
 Deferred storm costs                                                         3,676
 Other                                                    5,656               3,900
                                                       --------            --------
                                                         51,869              55,639
                                                       --------            --------
Regulatory liabilities reflected in other reserves and 
 deferred credits - storm fund                          (4,691)                   -
                                                       --------            --------
                                                        $44,308             $47,978
                                                       ========            ========

Amounts included in "Deferred charges and other assets" on the Company's
balance sheets that do not represent regulatory assets totaled $5,012,000 and
$4,529,000 at December 31, 1996 and 1995, respectively.

</TABLE>

Note C - Federal Income Taxes
 
The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns. The Company's
income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by
the Internal Revenue Service (IRS) through 1991.  The returns for
1992 and 1993 are currently under examination by the IRS.

<PAGE>
Total federal income taxes consist of the following components:
<TABLE>
<CAPTION>
Year Ended December 31, (In Thousands)          1996               1995           1994
                                                ----               ----           ----
<S>                                              <C>                <C>            <C>
Income taxes charged to operations:
  Current income taxes                       $ 7,499             $7,560         $1,511
  Deferred income taxes                        4,950              3,831          3,880
  Investment tax credits, net                  (498)              (503)          (508)
                                             -------            -------        -------
   Total income taxes charged to
     operations                               11,951             10,888          4,883
                                             -------            -------        -------
Income taxes charged (credited) to 
"Other income":                                                        
  Current income taxes                         (581)              (348)          (491)
  Deferred income taxes                        (275)              (319)             50
                                             -------            -------        -------
  Total income taxes charged (credited) to
   "Other income"                              (856)              (667)          (441)
                                             -------            -------        -------
   Total federal income taxes                $11,095            $10,221         $4,442
                                             =======            =======        =======

Investment tax credits have been deferred and are being amortized over the
estimated lives of the property giving rise to the credits. 
</TABLE>

Consistent with rate-making policies of the RIPUC, the Company
has adopted comprehensive interperiod tax allocation
(normalization) for most temporary book/tax differences.

<PAGE>
Total federal income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes. 
The reasons for the differences are as follows:
<TABLE>
<CAPTION>
Year Ended December 31, (In Thousands)              1996              1995           1994
                                                    ----              ----           ----
<S>                                                  <C>              <C>            <C>
Computed tax at statutory rate                   $11,917          $11,946         $6,661
Increases (reductions) in 
    tax resulting from:
  Book versus tax depreciation not normalized                 778                    529            653
  Costs associated with utility 
    plant retirements deducted 
    for tax purposes                             (1,341)          (1,768)        (1,872)
  Allowance for equity funds used 
    during construction                                -             (37)          (360)
  Amortization of investment tax credits           (498)            (503)          (508)
  All other differences                              239               54          (132)
                                                 -------          -------        -------
    Total federal income taxes                   $11,095          $10,221         $4,442
                                                 =======          =======        =======

The following table identifies the major components of total deferred income
taxes:

At December 31, (In Millions)                       1996              1995
                                                    ----              ----
Deferred tax asset:
 Plant related                                        $2                $2
 Investment tax credits                                3                 3
 All other                                            13                13
                                                   -----             -----
                                                      18                18
                                                   =====             =====
Deferred tax liability:
 Plant related                                      (67)              (62)
 All other                                          (33)              (32)
                                                   -----             -----
                                                   (100)              (94)
                                                   -----             -----
  Net deferred tax liability                       $(82)             $(76)
                                                   =====             =====

There were no valuation allowances for deferred tax assets deemed necessary.
</TABLE>

Note D - Commitments and Contingencies

1.  Plant Expenditures:

The Company's utility plant expenditures are estimated to be
approximately $45 million in 1997. At December 31, 1996,
substantial commitments had been made relative to future planned
expenditures.

2.  Hazardous Waste:

The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly know as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous
substances.
<PAGE>
The electric utility industry typically utilizes and/or generates
in its operations a range of potentially hazardous products and
by-products.  NEES subsidiaries currently have in place an
internal environmental audit program and an external waste
disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous
products and by-products.

The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
three sites (two of which are located in Massachusetts) at which
hazardous waste is alleged to have been disposed.  The Company is
currently aware of other sites, and may in the future become
aware of additional sites, that it may be held responsible for
remediating.

Gas was manufactured from coal in Rhode Island in the past.  The
Company is aware of five sites on which gas was manufactured or
manufactured gas was stored that were owned either by the Company
or by its predecessor companies.  It is not known to what extent
the Company would be held liable for hazardous wastes, if any,
left at these manufactured gas locations.

Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult.  There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by the Company.  A
preliminary review by a consultant hired by the NEES companies of
the potential cost of investigating and, if necessary,
remediating Rhode Island manufactured gas sites resulted in costs
per site ranging from less than $1 million to $11 million.  An
informal survey of other utilities conducted on behalf of NEES
and its subsidiaries indicated costs in a similar range.  Where
appropriate, the Company intends to seek recovery from its
insurers and from other PRPs, but it is uncertain whether, and to
what extent, such efforts will be successful.  The Company
believes that hazardous waste liabilities for all sites of which
it is aware are not material to its financial position.

In October 1996, the American Institute of Certified Public
Accountants issued new accounting rules for Environmental
Remediation Liabilities which become effective in 1997.  The
Company does not believe these new rules will have a material
effect on its financial position or results of operations.

Note E - Employee Benefits

1.  Pension Plans:

The Company participates with other subsidiaries of NEES in
noncontributory, defined-benefit plans covering substantially all
employees of the Company. The plans provide pension benefits
based on the employee's compensation during the five years prior 
<PAGE>
to retirement. The Company's funding policy is to contribute each
year the net periodic pension cost for that year. However, the
contribution for any year will not be less than the minimum
contribution required by federal law or greater than the maximum
tax deductible amount.

Net pension cost for 1996, 1995, and 1994 included the following
components:
<TABLE>
<CAPTION>
Year Ended December 31, (In Thousands)              1996              1995           1994
                                                    ----              ----           ----
<S>                                                  <C>               <C>            <C>
Service cost   benefits earned
  during the period                               $2,007            $1,963         $1,877
Plus (less):
  Interest cost on projected 
    benefit obligation                             8,954             9,327          8,629
  Return on plan assets at expected 
    long-term rate                               (9,787)           (9,567)        (9,024)
  Amortization                                       165                67            567
                                                 -------           -------        -------
     Net pension cost                             $1,339            $1,790         $2,049
                                                 -------           -------        -------
     Actual return on plan assets                $17,228           $25,192           $809
                                                 =======           =======        =======


                                         1997               1996             1995           1994
                                         ----               ----             ----           ----
Assumptions used to determine
    pension cost:
  Discount rate                           7.25%             7.25%             8.25%          7.25%
  Average rate of increase in 
    future compensation levels            4.13%             4.13%             4.63%          4.35%
  Expected long-term rate of 
  return on assets                        8.50%             8.50%             8.75%          8.75%




</TABLE>

<PAGE>
The funded status of the plans cannot be presented separately for
the Company as the Company participates in the plans with other
NEES subsidiaries.  The following table sets forth the funded
status of the NEES companies' plans at December 31:

<TABLE>
<CAPTION>
Retirement Plans, (In Millions)     1996                1995
                                    ----                ----
<S>                                 <C>                 <C>
                               Union     Non-Union Union    Non-Union
                               Employee  Employee  Employee Employee
                               Plans     Plans     Plans    Plans
                               --------  --------- -------- ---------
Benefits earned
  Actuarial present value of 
     accumulated benefit liability:
    Vested                           $298      $342      $293      $343
    Nonvested                           9        10         8        10
                                     ----      ----      ----      ----
      Total                          $307      $352      $301      $353
                                     ====      ====      ====      ====
Reconciliation of funded status
  Actuarial present value of
    projected benefit liability      $355      $398      $346      $402
  Unrecognized prior service costs    (6)       (3)       (7)       (4)
  SFAS No. 87 transition liability 
    not yet recognized (amortized)      -       (1)                 (1)
  Net gain (loss) not yet recognized
    (amortized)                        25        15       (1)      (23)
                                     ----      ----      ----      ----
                                      374       409       338       374
                                     ----      ----      ----      ----
  Pension fund assets at fair value   384       428       349       392
  SFAS No. 87 transition asset not 
    yet recognized (amortized)       (10)         -      (11)          
                                     ----      ----      ----      ----
                                      374       428       338       392
                                     ----      ----      ----      ----
  Accrued pension/(prepaid) 
    payments recorded on books       $  -     $(19)      $  -     $(18)

</TABLE>

The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates from 1997 and 1996,
respectively, and the 1983 Group Annuity Mortality table.

Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.

2.Postretirement Benefit Plans Other Than Pensions (PBOPs)

The Company provides health care and life insurance coverage to
eligible retired employees. Eligibility is based on certain age
and length of service requirements and in some cases retirees
must contribute to the cost of their coverage.

<PAGE>
The total cost of PBOPs for 1996, 1995, and 1994 included the
following components:
<TABLE>
<CAPTION>

Year Ended December 31, (In Thousands)         1996       1995       1994
                                               ----       ----       ----
<S>                                             <C>        <C>        <C>
Service cost - benefits earned during
  the period                                 $1,030     $1,072     $1,252
Plus (less):
 Interest cost on accumulated
  benefit obligation                          5,034      6,006      5,630
 Return on plan assets at expected
  long-term rate                            (2,803)    (2,080)    (1,640)
 Amortization                                 2,739      3,539      3,716
                                            -------    -------    -------
    Net postretirement benefit cost          $6,000     $8,537     $8,958
                                            =======    =======    =======
    Actual return (loss) on plan assets      $5,469     $6,161      $(23)
                                            =======    =======    =======

                                               1997           1996             1995           1994
                                               ----           ----             ----           ----
Assumptions used to determine
    postretirement benefit cost:
  Discount rate                                7.25%          7.25%             8.25%          7.25%
  Expected long-term rate of return
    on assets                                  8.25%          8.25%             8.50%          8.50%
  Health care cost rate   1994                                                                11.00%
  Health care cost rate   1995 to 1999                 8.00%          8.00%                    8.50%          8.50%
  Health care cost rate   2000 to 2004                 6.25%          6.25%                    8.50%          8.50%
  Health care cost rate   2005 and beyond              5.25%          5.25%                    6.25%          6.25%

The following table sets forth benefits earned and the plans' funded status:

At December 31, (In Millions)                         1996           1995
                                                      ----           ----
Accumulated postretirement benefit obligation:
 Retirees                                              $51            $50
 Fully eligible active plan participants                 5              6
 Other active plan participants                         19             20
                                                      ----           ----
  Total benefits earned                                 75             76
 Unrecognized transition obligation                   (62)           (66)
 Net gain not yet recognized                            22             16
                                                      ----           ----
                                                        35             26
Plan assets at fair value                               42             34
                                                      ----           ----
Prepaid postretirement benefit costs recorded
 on books                                               $7             $8
                                                      ====           ====
</TABLE>

The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates in effect for 1997 and 1996,
respectively.

The assumptions used in the health care cost trends have a
significant effect on the amounts reported.  Increasing the
assumed rates by 1 percent in each year would increase the
accumulated postretirement benefit obligation as of December 31,
1996 by approximately $9 million and the net periodic cost for
1996 by approximately $1 million.
<PAGE>
The Company funds the annual tax-deductible contributions. Plan
assets are invested in equity and debt securities and cash
equivalents.

Note F - Short-term Borrowings and Other Accrued Expenses

At December 31, 1996, the Company had $19 million of short-term
debt outstanding including $14 million in commercial paper
borrowings and $5 million of borrowings from affiliates. NEES and
certain subsidiaries, including the Company, with regulatory
approval, operate a money pool to more effectively utilize cash
resources and to reduce outside short-term borrowings. Short-term
borrowing needs are met first by available funds of the money
pool participants. Borrowing companies pay interest at a rate
designed to approximate the cost of outside short-term
borrowings. Companies which invest in the pool share the interest
earned on a basis proportionate to their average monthly
investment in the money pool. Funds may be withdrawn from or
repaid to the pool at any time without prior notice.

At December 31, 1996, the Company had lines of credit with banks
totaling $41 million. There were no borrowings under these lines
of credit at December 31, 1996.  Fees are paid in lieu of
compensating balances on most lines of credit.

The weighted average rate on outstanding short-term borrowings
was 6.0 percent at December 31, 1996.  The fair value of the
Company's short-term debt equals carrying value.

<TABLE>
<CAPTION>
The components of other accrued expenses are as follows:

At December 31, (In Thousands)                        1996           1995
                                                      ----           ----
<S>                                                    <C>            <C>
Rate adjustment mechanisms                          $4,632        $14,075
Accrued wages and benefits                           7,259          5,483
Other                                                   58              -
                                                   -------        -------
                                                   $11,949        $19,558
                                                   =======        =======
</TABLE>
<PAGE>
Note G - Cumulative Preferred Stock

<TABLE>
<CAPTION>

A summary of cumulative preferred stock at December 31, 1996 and 1995 is as
follows (in thousands of dollars except for share data):

                    Shares
                    Authorized                    Dividends     Call
                    and Outstanding   Amount      Declared      Price
                    ---------------   ------      ------------- -----
                    1996    1995    1996   1995   1996    1995 
                    ----    ----    ----   ----   ----    ----
<S>                   <C>     <C>   <C>     <C>    <C>    <C>    <C>
$50 Par value                       
  4.50% Series        180,000 180,000  $9,000  $9,000   $405   $405       55.000
  4.64% Series        150,000 150,000   7,500   7,500    348    348       52.125
  6.95% Series        400,000 400,000  20,000  20,000  1,390  1,390      (a)
                      ------- ------- ------- ------- ------ ------         
  Total               730,000 730,000 $36,500 $36,500 $2,143 $2,143
                      ======= ======= ======= ======= ====== ======

<FN>
(a)Callable on or after August 1, 2003 at $51.74.
</FN>

The annual dividend requirement for total cumulative preferred stock was
$2,143,000 for 1996 and 1995. 

</TABLE>

<PAGE>
Note H - Long-term Debt
<TABLE>
<CAPTION>

A summary of long-term debt is as follows:
At December 31, (In Thousands)

Series       Rate %       Maturity                       1996        1995
-----------------------------------------------------------------------------
<S>          <C>          <C>                             <C>         <C>
First Mortgage Bonds:
U(92-1)      7.230        June 3, 1997                $10,000     $10,000
U(92-2)      7.210        June 3, 1997                  5,000       5,000
U(92-3)      7.000        June 16, 1997                10,000      10,000
U(92-7)      5.700        September 16, 1997            7,500       7,500
V(95-1)      7.810        February 16, 1998             5,000       5,000
V(94-2)      6.960        May 3, 1999                   2,000       2,000
V(94-3)      6.910        May 4, 1999                   1,000       1,000
U(92-6)      6.630        August 12, 1999               5,000       5,000
U(92-5)      6.980        July 17, 2000                 5,000       5,000
U(92-8)      6.340        September 18, 2000           10,000      10,000
U(92-4)      7.830        June 17, 2002                15,000      15,000
U(93-1)      7.080        January 13, 2003              7,500       7,500
U(93-2)      6.560        April 15, 2003                5,000       5,000
U(93-4)      6.350        July 1, 2003                  5,000       5,000
V(94-4)      7.420        June 15, 2004                 5,000       5,000
V(94-6)      8.330        November 8, 2004             10,000      10,000
U(93-3)      6.650        June 30, 2008                 5,000       5,000
S            9.125        May 1, 2021                  22,200      22,200
T            8.875        August 1, 2021               22,000      24,000
U(93-5)      7.050        September 1, 2023             5,000       5,000
U(94-1)      7.050        February 2, 2024              5,000       5,000
V(94-1)      8.080        May 2, 2024                   5,000       5,000
V(94-5)      8.160        August 9, 2024                5,000       5,000
V(95-2)      7.750        June 2, 2025                 10,000      10,000
V(95-3)      7.500        October 10, 2025              7,000       7,000
W(95-1)      7.300        November 13, 2025            16,000      16,000
W(96-1)      7.240        January 19,2026               2,000           -
Unamortized discounts and premiums                    (1,183)     (1,308)
                                                     --------    --------
 Total long-term debt                                $211,017    $210,892
                                                     ========    ========
 Long-term debt due in one year                        32,500           -
                                                     --------    --------
                                                     $178,517    $210,892
                                                     ========    ========
</TABLE>

Substantially all of the properties and franchises of the Company
are subject to the lien of mortgage indentures under which the
first mortgage bonds have been issued.

The Company will make cash payments of $32,500,000 in 1997,
$5,000,000 in 1998, $8,000,000 in 1999, and $15,000,000 in 2000
to retire maturing mortgage bonds.  There are no cash payments
required in 2001.

At December 31, 1996, the Company's long-term debt had a carrying
value of approximately $211,000,000 and had a fair value of
approximately $203,000,000. The fair market value of the
Company's long-term debt was estimated based on the quoted prices
for similar issues or on the current rates offered to the Company
for debt of the same remaining maturity.

<PAGE>
Note I - Restrictions on Retained Earnings Available for
Dividends on Common Stock

As long as any preferred stock is outstanding, certain
restrictions on payment of dividends on common stock would come
into effect if the "junior stock equity" was, or by reason of
payment of such dividends became, less than 25 percent of "Total
capitalization." However, the junior stock equity at December 31,
1996 was 51 percent of total capitalization and, accordingly,
none of the Company's retained earnings at December 31, 1996 were
restricted as to dividends on common stock under the foregoing
provisions.

Note J - Regulatory Matters

A 1986 Rhode Island Supreme Court decision held that the RIPUC's
rate-making powers include the authority to order refunds of
amounts earned in excess of an allowed return.  As a result, the
RIPUC monitors the Company's earnings on a regular basis.

Note K - Supplementary Income Statement Information

Advertising expenses, expenditures for research and development,
and rents were not material and there were no royalties paid in
1996, 1995, or 1994. Taxes, other than federal income taxes,
charged to operating expenses are set forth by class as follows:

<TABLE>
<CAPTION>
Year Ended December 31,                  1996                 1995             1994
(In Thousands)                           ----                 ----             ----
<S>                                       <C>                  <C>              <C>
Municipal property taxes              $16,546              $15,172          $13,944
State gross earnings tax               18,764               18,617           19,270
Federal and state payroll and
 other taxes                            3,220                2,838            2,604
                                      -------              -------          -------
                                      $38,530              $36,627          $35,818
                                      =======              =======          =======
</TABLE>

New England Power Service Company, an affiliated service company
operating pursuant to the provisions of Section 13 of the Public
Utility Holding Company Act of 1935, furnished services to the
Company at the cost of such services. These costs amounted to
$27,336,438, $29,094,719, and $32,445,000, including capitalized
construction costs of $6,426,000, $6,268,000, and $7,756,000 for
each of the years 1996, 1995, and 1994, respectively.

<PAGE>
The Narragansett Electric Company
Operating Statistics (Unaudited)

<TABLE>
<CAPTION>
Year Ended December 31,           1996      1995      1994      1993      1992
                                  ----      ----      ----      ----      ----
<S>                                <C>       <C>       <C>       <C>       <C>
Sources of Energy (Thousands of kWh)
Net generation for New England
  Power Company, an affiliate  329,883    64,035     5,781     4,506    83,753
Purchased energy:
 From New England Power
  Company (net of
  generation)                4,698,017 4,955,575 5,001,843 4,982,254 4,729,733
 From others                     2,422     2,080     2,909     2,343     2,249
                            --------------------------------------------------
   Total generated and 
    purchased                5,030,322 5,021,690 5,010,533 4,989,103 4,815,735
Losses, company use, etc.    (251,709) (260,960) (263,234) (270,373) (229,106)
                            --------------------------------------------------
   Total sources of energy   4,778,613 4,760,730 4,747,299 4,718,730 4,586,629
                            ==================================================

Sales of Energy (Thousands of kWh)
 Residential                 1,847,111 1,835,085 1,843,970 1,817,675 1,783,754
 Commercial                  2,035,294 2,031,541 1,983,508 1,931,377 1,877,738
 Industrial                    847,877   843,635   868,092   917,305   869,062
 Other                          47,745    49,881    51,138    51,821    55,476
                            --------------------------------------------------
   Total sales to
    ultimate customers       4,778,027 4,760,142 4,746,708 4,718,178 4,586,030
 Sales for resale                  586       588       591       552       599
                            --------------------------------------------------
   Total sales of energy     4,778,613 4,760,730 4,747,299 4,718,730 4,586,629
                            ==================================================
Annual Maximum Demand 
(kW   one hour peak)           929,000 1,031,000 1,005,000   939,000   919,000

Average Annual Use per 
 Residential Customer (kWh)      6,304     6,305     6,397     6,337     6,265

Number of Customers at 
 December 31
 Residential                   294,274   292,659   289,317   287,876   286,228
 Commercial                     33,101    32,412    32,195    31,948    31,534
 Industrial                      1,778     1,792     1,825     1,869     1,914
 Other                             868       873       875       878       941
                            --------------------------------------------------
   Total ultimate customers    330,021   327,736   324,212   322,571   320,617
 Other electric companies 
  (for resale)                       2         2         2         1         3
                            --------------------------------------------------
   Total customers             330,023   327,738   324,214   322,572   320,620
                            ==================================================

Operating Revenue (In Thousands)
 Residential                  $216,103  $205,649  $200,778  $202,522  $196,983
 Commercial                    202,219   198,429   189,059   190,185   183,702
 Industrial                     68,447    72,071    72,136    78,088    76,275
 Other                           7,809     7,236     6,883     6,778     6,587
                            --------------------------------------------------
   Total revenue from 
    ultimate customers         494,578   483,385   468,856   477,573   463,547
 Amortization of unbilled 
  revenues                           -     8,209     6,158         -         -
 Sales for resale                   75        70        68        64        68
                            --------------------------------------------------
   Total revenue from 
    electric sales             494,653   491,664   475,082   477,637   463,615
 Other operating revenue         8,932     7,449     6,587     5,391     4,637
                            --------------------------------------------------
   Total operating revenue    $503,585  $499,113  $481,669  $483,028  $468,252
                            ==================================================

</TABLE>

<PAGE>
The Narragansett Electric Company
Selected Financial Information
<TABLE>
<CAPTION>

Year Ended December 31, (In Millions)      1996    1995   1994     1993   1992
                                           ----    ----   ----     ----   ----
<S>                                         <C>     <C>    <C>      <C>    <C>
Operating revenue:
 Electric sales 
  (excluding fuel cost recovery)           $361    $361   $356     $351   $342
 Fuel cost recovery                         134     131    120      127    121
 Other                                        9       7      6        5      5
                                         ------  ------ ------   ------ ------
Total operating revenue                    $504    $499   $482     $483   $468
Net income                                  $23     $24    $15      $14    $21
Total assets                               $707    $700   $647     $556   $479
Capitalization:
 Common equity                             $257    $245   $208     $183   $176
 Cumulative preferred stock                  36      36     37       37     27
 Long-term debt                             179     211    189      156    143
                                         ------  ------ ------   ------ ------
Total capitalization                       $472    $492   $434     $376   $346
Preferred dividends declared                 $2      $2     $2       $2     $2
Common dividends declared                    $9      $5     $3       $5     $5

</TABLE>

Selected Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>

                                       First      Second      Third     Fourth
(In Thousands)                        Quarter    Quarter    Quarter    Quarter
                                      -------    -------    -------    -------
<S>                                       <C>        <C>        <C>        <C>
1996
Operating revenue                    $127,285   $116,470   $140,481   $119,349
Operating income                      $12,286     $8,245    $13,419     $9,561
Net income                             $6,290     $3,117     $8,169     $5,378

1995
Operating revenue                    $125,020   $116,426   $139,217   $118,450
Operating income                      $12,645     $7,301    $12,699     $9,780
Net income                             $7,766     $3,058     $7,939     $5,147

</TABLE>

Per share data is not relevant because the Company's common stock
is wholly-owned by New England Electric System.

A copy of The Narragansett Electric Company's Annual Report on
Form 10-K to the Securities and Exchange Commission for the year
ended December 31, 1996 will be available on or about April 1,
1997, without charge, upon written request to The Narragansett
Electric Company, Shareholder Services Department, 280 Melrose
Street, Providence, Rhode Island 02901.