1997 Annual Report

"Cover with Caption:

        "1997's continuing changes
        to the very underpinning of
        the electric utility industry
       challenged us
               as never before..." "

"Highlights page with caption:
 "...We met every challenge during the year.  And we'll continue to deal
with the changes in our industry in ways dedicated to preserving and
enhancing shareholder value.""

<TABLE>
Highlights
<CAPTION>
                                               1997          1996             1995
<S>                                            <C>            <C>             <C>
FINANCIAL DATA  ($ in thousands)
Operating Revenues                     $   568,513   $    527,068      $   563,363
Consolidated Net Earnings(1)                37,960         30,614           32,626
Return on Average Common Equity               10.2%           8.2%             8.8%
Common Shareholder Equity-
        % of Capitalization (Year-End)        50.4%          45.8%            44.5%
   Total Assets                          1,270,752      1,257,029        1,206,130
   Cash Construction Expenditures           76,118         62,730           77,923

COMMON SHARE DATA
   Consolidated Earnings per Share<F1> $      1.86    $      1.50      $      1.61
   Dividends Paid per Share            $      1.66    $     1.645      $     1.585
   Annual Dividend Rate                $      1.66    $      1.66      $      1.60
   Total Common Shares Outstanding      20,435,997     20,435,997       20,436,764
   Average Common Shares Traded Daily       88,613         91,843           58,573
   Book Value per Share (Year-End)    $      18.27    $     18.19      $     18.36
   Market Price - High                          26 5/8         24 1/4           25 3/8
                - Low                           16 3/8         14 3/4           21 1/2
                - Year-End                      26 1/4         17 3/8           23 5/8

OPERATING DATA
   Total Primary Sales (mWh)             4,546,000      4,491,000        4,441,000
   System Requirements (mWh)             4,765,000      4,699,000        4,668,000
   System Peak Demand (mw)                     933            854              931
   System Reserve Margin (At Peak)            11.5%          34.4%            24.2%
   System Load Factor                         58.3%          62.6%            57.2%
   Customers (Year-End)                    302,059        299,471          297,331
   Employees (Year-End) - Core Electric <F2>   434            468              541
                        -  Energy Related      197            213              253
                        -  Corporate <F2>      549            564              536
                        Total                1,180          1,245            1,330
<FN>
<F1>    See Management's Discussion and Analysis of Financial Condition and
        Results of Operations for details of one-time   impacts to earnings.

<F2>    Reflects employee shift resulting from corporate reorganization
        completed in 1996.
</FN>
</TABLE>

"Caption: "Our customers may choose a new source of electricity, but
they remain our customers." With Map of New England depicting Core Electric
customers as follows:"

Eastern Edison/Brockton
125,000 customers
Abington
Avon
Bridgewater
Brockton
Cohasset
East Bridgewater
Easton
Halifax
Hanson
Hanover
Norwell
Pembroke
Rockland
Scituate
Stoughton
West Bridgewater
Whitman


Eastern Edison/Fall River
59,000 customers
Dighton
Fall River
Somerset
Swansea
Westport



Blackstone Valley Electric
85,000 customers
Central Falls
Cumberland
Lincoln
North Smithfield
Pawtucket
Woonsocket
Burrillville

Newport
Electric
33,000 customers
Jamestown
Middletown
Newport
Portsmouth

About Eastern Utilities Associates


Eastern Utilities Associates (NYSE Symbol: EUA) is a diversified energy
services company whose subsidiaries are known collectively as the EUA System.
To better reflect the new competitive business environment in which it
operates, EUA is organized into four distinct business units covering its
wholesale and retail electric utility businesses, non-utility energy-related
subsidiaries and a corporate unit.

Core Electric Business
The System's core electric utility subsidiaries comprise two business units -
retail and wholesale.  The retail business unit provides electric distribution
service to over 300,000 customers in 597 square miles of southeastern
Massachusetts and northern and coastal Rhode Island as follows:

   -       Blackstone Valley Electric Company: The northern Rhode Island cities
           of Pawtucket and Woonsocket and five neighboring communities.
   -       Eastern Edison Company: Non-contiguous service territories covering
           the southeastern Massachusetts cities of Brockton and Fall River
           plus 20 surrounding towns.
   -       Newport Electric Corporation: Newport, Jamestown, Middletown and
           Portsmouth, Rhode Island.

The wholesale business unit, Montaup Electric Company, has provided electric
generation and high voltage transmission service at wholesale to the
distribution subsidiaries and to two non-affiliated utilities for resale.  EUA
is in the process of dive sting its electric generation business.

Energy-Related Business
This business unit includes the following non-utility energy-related
subsidiaries.

    -       EUA Cogenex Corporation, one of the nation's premier energy
            management companies with contracts nationwide and in Canada, is
            our most active energy-related company.
    -       EUA Ocean State owns a 29.9% partnership interest in the Ocean
            State Power generating station in northern Rhode Island, one of the
            first and most successful non-utility generating plants in the
            country.
    -       EUA Energy Investment Corporation is our vehicle for investing in
            niche-type energy-related companies, including:

            -   EUA BIOTEN, EUA's investment in a general partnership which is
                developing biomass-fueled generating units;
            -   EUA TransCapacity, EUA's investment in a limited partnership
                which has developed and now markets services and computer
                software enabling natural gas industry clients to connect,
                communicate and coordinate with their trading partners via
                electronic data interchange.
            -   Separation Technologies Inc., in which we own a 20% equity
                interest, markets and installs its own proprietary equipment
                for separating unburned carbon from coal fly-ash, enabling the
                customer to sell the fly-ash to secondary markets and reburn
                the carbon.

Corporate
The corporate business unit is made up of the System's parent company " Eastern
Utilities Associates"  and EUA Service Corporation, which provides professional
and technical services to all EUA System companies.



Dear Fellow Shareholders,
1997 was truly a transition year for Eastern Utilities. We are active
participants in the rapid transition from the historic era of regulated
electric utility monopolies to a more competitive age, particularly in the
electric generation business.

  We negotiated major settlement agreements at both the federal and state level
which defined our plans to bring the benefits of competition and immediate rate
reductions to our customers while preserving shareholder value by ensuring
recovery of past investments and commitments in generation resources, commonly
referred to as stranded costs.

To our shareholders (continued)

    By year's end, each of these settlement agreements had been approved by the
respective regulatory bodies, thus removing much of the uncertainty inherent in
such a fundamental change to our core electric business. We look forward to
meeting the challenge of implementing these settlements during 1998.

    In addition, the strategic moves we made in 1996 to return our EUA Cogenex
energy services subsidiary to profitability paid off in 1997 with Cogenex
showing a small profit for the year.

    Consolidated net earnings were $38.0 million, or $1.86 per share, a 24%
improvement from 1996 net earnings of $30.6 million, or $1.50 per share,
despite the continued burden of supporting our 4% ownership interest in the
Millstone 3 nuclear unit in Connecticut which remained shut down throughout
1997.  Internal generation of cash remained strong, providing in excess of 100%
of our cash construction needs during 1997.  Cash flow per share for 1997 was
$5.85 and, coupled with our improving financial performance, enabled us to
maintain the dividend at its current annual rate of $1.66 per share in the
midst of fundamental changes in our core electric business.

    Our success in dealing with restructuring, returning Cogenex to
profitability and improving financial performance were recognized by the
financial community.  Your EUA shares provided you with a 65% total return for
1997, closing the year at a price of $26.25.  This total return ranked fifth
nationwide according to the Edison Electric Institute 100 Index of investor-
owned electric utilities.

Core Electric Business Restructuring
While timing and details differ somewhat, the underlying basics of our
settlement agreements defining how we plan to implement competition in
Massachusetts and Rhode Island are similar. In Rhode Island, large industrial
customers of our Blackstone Valley Electric and Newport Electric distribution
subsidiaries were free to choose their electric supplier starting on July 1,
1997.  Choice of generation supplier was opened to all Rhode Island customers
on January 1, 1998.

    In Massachusetts, where our Eastern Edison distribution subsidiary
operates, legislation was enacted in November 1997 to set the start of retail
competition for all customers at March 1, 1998.

    In addition to providing our distribution customers with choice to select
their electric supplier in the competitive market, we also agreed to implement
rate decreases in both states consistent with legislation and settlement
provisions.

    Also, beginning in 1997 for our Rhode Island retail subsidiaries and in
1998 for Eastern Edison, distribution rates are subject to performance
standards.  Our retail subsidiaries are rewarded or penalized based on their
ability to meet specified standards of safety, reliability and customer service.
We are pleased to report that both our Rhode Island utilities were rewarded
for their performance in 1997.


"Picture of Donald G. Pardus Chairman and Chief Executive Officer"


"Picture of John R. Stevens President and Chief Operating Officer"

"Note in Margin: "Shareholder value in top tier of utility stocks nationwide!""

"Caption: "Our successes in dealing with competition and improved financial
performance resulted in a 65% total return on EUA shares in 1997 - fifth
highest  in the country. Chart depicting Total return to shareholders as
follows:
EUA                         65%
S&P 500 Index               33%
EEI 100 Index               27%
S&P Electric Company Index  26%



    The Federal Energy Regulatory Commission approved terms under which Montaup
Electric, our wholesale generation and transmission company, ended its all-
requirements electric supply agreements with Blackstone Valley Electric,
Eastern Edison and Newport Electric and its partial-requirements contracts with
two non-affiliated utilities.  This approval was necessary to accommodate our
distribution customers' choice of electric supplier.

    Under terms of our Massachusetts, Rhode Island and federal settlement
agreements, we agreed to divest ourselves of Montaup's entire generation
portfolio and to use the net proceeds of the divestiture to reduce the amount
of stranded costs billed to our distribution customers.   In return, the
settlement agreements permit us to recover 100% of the net investment in
generating facilities, with a return, that we made under the prior regulatory
environment.  Some of those investments may have otherwise been unrecoverable
"or stranded" in a competitive market.  This 100% stranded cost recovery is
critical to the financial health of a competitive EUA.

    The settlement agreements are more thoroughly discussed under the heading
Electric Utility Industry Restructuring Initiatives in Management's Discussion
and Analysis of Financial Condition and Review of Operations elsewhere in this
report.

    After divesting its generation assets, Montaup will continue to provide
high voltage transmission service, transporting electricity from independent
generation sources on its way to ultimate consumers.

    Our distribution utilities "Blackstone Valley Electric, Eastern Edison and
Newport Electric" remain regulated by the states in which they operate as
wires companies, and will continue to deliver electricity from a source of the
customer's choosing over our wires in our existing service territories.  We'll
continue to provide our customers with the superior service reliability and
safety to which they are accustomed.

Divestiture of Generation Assets
We began marketing efforts to sell our 1,065 megawatts of owned and purchased
generating capacity, as well as two parcels of real estate suitable for future
power plant development, in July 1997.  Based on early indications from
potential purchasers we anticipated an active auction market for our generation
portfolio.

    By September, we had received preliminary indications of interest from a
number of potential purchasers.  We set an early December deadline for
qualified entities to submit firm offers on all or a portion of the generation
assets owned by Montaup, as well as small diesel generation stations owned by
Newport Electric and a small hydroelectric unit owned by Blackstone Valley
Electric.

"Note in margin: "Essential to continued financial success of EUA.""

    After carefully weighing the bids, we determined in early January of this
year that it would be in the best interests of the retail customers of our
electric utility subsidiaries to re-open the sale process for about 500
megawatts of our wholly- and jointly-owned generating capacity and 300
megawatts of power purchase contracts.  By doing so, we believe we can benefit
from improved conditions for marketing the assets offered.  We expect to have
firm offers in hand later this year.  It will likely be late 1998 or early
1999 before we receive the regulatory approvals necessary to complete the
divestiture.

Energy-Related Businesses
EUA's position at the forefront of the transition to competition in 1997
required an enormous investment of resources and staff to accomplish a
balanced approach to competition.  This major commitment will continue in
1998.  This core business effort runs concurrent with the continued
development of our non-utility energy-related businesses.

    Our EUA Ocean State subsidiary continues to be a solid performer,
contributing $4 million in earnings, or just under 20 cents per share in 1997.
Our 29.9% ownership share of Ocean State Power is not among the generation
assets being offered for sale.

    EUA Cogenex Corporation, which provides energy efficiency products and
energy-management services throughout North America, experienced a significant
rebound in 1997.  Average project size more than doubled, a higher percentage
of project proposals w ere closed, and Cogenex expanded its line of products
and services.  At year's end, Cogenex's wholly-owned subsidiary, EUA Citizens
Conservation Services, which specializes in multi-family installations,
announced a major contract to install energy improvements for the Chicago
Housing Authority.

    While progress was made in the development of our three start-up
energy-related subsidiaries, TransCapacity, BIOTEN and Separation
Technologies, Inc., this progress was below our expectations.

    TransCapacity, our limited partnership which develops and provides computer
software for the natural gas industry, installed its first systems in late
1997.  TransCapacity's systems enable gas pipeline companies to comply with
Federal Energy Regulatory Commission directives requiring electronic data
interchange capabilities.  Delays in requiring compliance with these federal
mandates have been frustrating; 1998 will be critical to the future of
TransCapacity.

    The process of testing the BIOTEN partnership's patented biomass-fired
generating unit in Tennessee continued in 1997 at a slower pace than originally
anticipated.  In February 1998, the testing of the unit suffered a setback that
will delay the process for several months.  Final testing is now expected in
mid-1998.  It is clear that there is a global market for the environmental
benefits of the BIOTEN technology.  BIOTEN's marketing efforts are geared to
capture a portion of this vast market.

"Note in margin: "Ocean State Power: one of the first and most successful
non-utility generating plants.""

    Separation Technologies, Inc., which markets its proprietary high volume
fine-particle materials separation equipment with funding from our EUA Energy
Investment subsidiary, announced installations of its ash-recovery systems at
power plants in North Carolina and Florida - its first forays outside the
company's New England base.  Separation Technologies equipment provides coal-
burning power plants with clean fly-ash, which plant owners can market to
concrete manufacturers, and recovers unburned carbon from the ash for use as a
fuel at the plant.

A different kind of company
EUA today is a far different company from the EUA of four or five years ago.
We've consolidated our management structure so we can react more quickly to
changing conditions.  1997 marked the fourth consecutive year in which we
reduced our workforce.  Since 1993, our workforce has decreased by more than
18% and we will continue to look for opportunities to enhance efficiency.
These changes could not have happened without the dedication and commitment
of our staff, who continue to accomplish more with ever decreasing resources.

     Staff reductions have not and will not impact on our ability to continue
to provide the customers of our distribution utilities with safe, reliable
electric service.  In fact, we were able to provide important assistance in
January of this year when the largest ice storm in Maine's history devastated
the area served by Central Maine Power.  Sixty of our lineworkers and
supervisory personnel with the necessary support equipment were among the first
support Central Maine Power received after the ice storm hit, and were among
the last to return home.  Central Maine Power has been quick to come to our aid
in previous years; we were glad to reciprocate.

We'll meet the continuing challenges of competition
The early start of competition in Rhode Island and Massachusetts gives us a
head start in dealing with the most fundamental changes affecting the way
electric utilities have done business for more than a century.

    Being ahead of the pack provides us the opportunity to work out more
advantageous conditions for recovery of generation-related investments made
under the prior regulatory framework which might be unrecoverable in a
competitive atmosphere (stranded investments) and for divestiture of our
generation assets which will provide us with an immediate cash infusion
enabling us to proceed with changes to our financial structure to better
reflect our conversion from electricity provider to electric service deliverer,
while at the same time reducing the amount of stranded costs billed to our
customers.

"Note in margin: "A responsibility embraced by every member of our EUA team!""

"Caption: "Our customers may now choose the source of the electricity we will
continue to deliver.  We pledge to continue our high standards for the
service we provide." with pictures of EUA customers."


    We said a year ago that EUA was continually being challenged to be flexible
and innovative.  That didn't change in 1997.  And 1998 will be another year of
transition.  Being a leader in the move to competition means there are no
comfortable precedents for us to follow.

    Prior to the start of the competitive revolution, utilities were able to
predict with some accuracy where they would be several years ahead.  The need
to plan energy supply for the population of their service territories required
such foresight.  Today's utility world is very different from that of only a
few years ago.  The only sure prediction for tomorrow's utility is that there
will be even more challenges than there have been to this point.  We will
continue to adapt to conditions and to meet those new challenges.

Our mission remains clear
Our overriding mission during this period of transition remains clear -
maximize shareholder value!  We have in place a dedicated team of employees who
are committed to accomplishing this mission while continuing to provide our
customers with the superior service reliability and safety which over the
years have become synonymous with Eastern Utilities.

On a personal note . . .
We are saddened by the death last year of John F. G. Eichorn, Jr., retired
Chairman of the Board of Trustees and Chief Executive Officer.  Mr. Eichorn led
Eastern Utilities Associates through the oil embargo crisis of the early 1970s
and the tumult surrounding construction of the Seabrook nuclear power
generation station in the '80s.
We will miss his wise counsel.

"Note in margin: "Theres no change in our mission, despite major changes
to our industry.""

/s/ Donald G. Pardus
Donald G. Pardus
Chairman and Chief Executive Officer


/s/ John R. Stevens
John R. Stevens
President and Chief Operating Officer

March 9, 1998

Management's Discussion and Analysis of
Financial Condition and Review of Operations
<TABLE>
Selected Consolidated Financial Data
<CAPTION>

Years Ended December 31,
(In thousands except Common Share Data)      1997            1996           1995           1994         1993
<S>                                 <C>              <C>             <C>          <C>           <C>
INCOME STATEMENT DATA:
  Operating Revenues                 $     568,513    $   527,068    $    563,363      $  564,278 $    566,477
  Operating Income<F1>                      58,807         55,841          71,728          73,795       75,649
  Consolidated Net Earnings<F1>             37,960         30,614          32,626          47,370       44,931

BALANCE SHEET DATA:
  Plant in Service                       1,079,361      1,067,056        1,037,662      1,020,859    1,016,453
  Construction Work in Progress              5,538          3,839            7,570          8,389        8,728
  Gross Utility Plant                    1,084,899      1,070,895        1,045,232      1,029,248    1,025,181
  Accumulated Depreciation and
    Amortization                           376,722        350,816          324,146        304,034      296,995
    Net Utility Plant                      708,177        720,079          721,086        725,214      728,186
        Total Assets                     1,270,752      1,257,029        1,206,130      1,234,049    1,203,137

CAPITALIZATION:
  Long-Term Debt - Net                     332,802        406,337          434,871        455,412      496,816
  Redeemable Preferred Stock - Net          27,612         27,035           26,255         25,390       25,053
  Non-Redeemable Preferred Stock - Net       6,900          6,900            6,900          6,900        6,900
  Common Equity                            373,467        371,813          375,229        365,443      333,165
         Total Capitalization              740,781        812,085          843,255        853,145      861,934
        Short-Term Debt                     61,484         51,848           39,540         31,678       37,168

COMMON SHARE DATA:
  Consolidated Basic and Diluted Earnings
    per Average Common Share<F1>       $      1.86    $      1.50     $       1.61    $      2.41   $     2.44
  Average Number of Shares Outstanding  20,435,997     20,436,217       20,238,961     19,671,970   18,391,147
  Return on Average Common Equity             10.2%           8.2%             8.8%          13.6%        15.0%
  Market Price    - High                        26 5/8         24 1/4           25             27 3/8       29 7/8
                  - Low                         16 3/8         14 3/4           21 1/2         21 3/8       23 7/8
                  - Year-End                    26 1/4         17 3/8           23 5/8         22           28
   Dividends Paid per Share             $     1.66    $     1.645   $       1.585     $     1.515   $     1.42
<FN>
<F1> See Management's Discussion and Analysis of Financial Condition and Results
     of Operations for details of one-time impacts to earnings.
</FN>
</TABLE>

Management's Discussion and Analysis of
Financial Condition and Review of Operations

Overview
Consolidated net earnings for 1997 increased $7.3 million to $38.0 million, or
$1.86 per share, on revenues of $568.5 million, a 24% increase over 1996
earnings of $30.6 million, or $1.50 per share, on revenues of $527.1 million.
The results for both years include one-time earnings impacts, discussed below
and listed in the following table.

                                                                 1996
                                      1997           Net Earnings   Earnings
                           Net Earnings   Earnings      (Loss)       (Loss)
                              (000's)     Per Share     (000's)     Per Share
Core Electric Business     $  35,188      $  1.73    $  37,595     $   1.84
Energy Related Business           49         0.00       (2,738)       (0.13)
Corporate                      1,243         0.06         (571)       (0.03)
  From Operations          $  36,480      $  1.79    $  34,286     $   1.68
One-Time Impacts:
  Joint Venture Termination    1,480         0.07
  Cogenex Charge                                        (3,672)       (0.18)
Consolidated               $  37,960      $  1.86    $  30,614      $  1.50


Major impacts on earnings by business unit are described in the following
paragraphs.

Termination of Power Marketing Joint Venture
In the third quarter of 1997, EUA announced the termination of a power
marketing joint venture with an affiliate of Duke Energy Corporation, the
establishment of contingency reserves related to certain of its energy-related
business activities and other expense reserves.  Collectively, these actions
resulted in a net after-tax gain of $1.5 million in third quarter 1997
earnings.

1996 EUA Cogenex Charge to Earnings
Difficulties in turning project proposals into signed contracts, the virtual
elimination of utility-sponsored demand side management programs and
termination of two joint ventures had hampered EUA Cogenex Corporation (EUA
Cogenex) 1996 earnings.  As a result, a write-off of certain start-up costs of
abandoned joint ventures, and expenses related to certain project proposals
along with a reduction in carrying value of certain ongoing projects
necessitated by market conditions resulted in a $5.9 million pre-tax ($3.7
million after-tax or 18 cents per share) charge to earnings in the second
quarter of 1996.

Net Earnings and Earnings Per Share by business unit for 1997 and 1996 were as
follows:

"Caption: "Every EUA employee remains dedicated to continuing to capitalize
on competitive opportunities and overcoming any obstacles that could detract
from our performance." with pictures of EUA employees"


Operating Revenues
The following table sets forth estimates of the factors which contributed to
the change in Operating Revenues from 1995 through 1997:

                                              Increase (Decrease)
                                              From Prior Years
($ in millions)                               1997            1996
Operating Revenue change attributable to:
Core Electric Business:
  Purchased Power Recovery                   $    1.3        $  (7.0)
  Recovery of Fuel Costs                         12.1            0.2
  Recovery of C&LM Expenses                       3.2           (5.4)
  Unit Contracts and Sales to NEPOOL              6.3            0.6
  Kilowatthour (kWh) Sales and Other             13.0           (1.5)
Energy Related Business:
  EUA Cogenex and EUA Energy Investment           5.5          (23.2)
Total Operating Revenues                      $  41.4        $ (36.3)



    Core Electric Business:  The revenues attributable to Purchased Power
Recovery reflect our retail companies' recovery of purchased power capacity
costs.  Revenues attributable to Recovery of Fuel Costs and conservation and
load management (C&LM) expenses result from the operation of adjustment
clauses.  The change in such revenues reflects corresponding underlying changes
in costs.

    Revenues attributable to Unit Contracts and sales to the New England Power
Pool (NEPOOL) reflect energy revenues from such short-term contracts and
interchange sales with NEPOOL.  The change in revenues associated with kWh
Sales and Other reflects the effect of kWh sales and demand billings on base
revenues, Consumer Price Index base rate increases effective January 1, 1997
for Blackstone and Newport of 1.9% and 2.2%, respectively, and changes in other
operating revenues, including off-system contract demand sales.

    Energy Related Business: EUA Cogenex revenues, which account for the
majority of the Energy Related Business Unit revenues, increased by
approximately $5.0 million in 1997.  This increase was due primarily to
increased revenue of EUA Citizens, Cogenex-Canada and the Cogenex partnerships
aggregating $10.7 million.  Project sales at the Cogenex Division also
increased.  Offsetting these increases somewhat were decreased revenues of EUA
Day, Renova (formerly EUA Nova) and Cogenex-West (formerly EUA Highland)
aggregating $5.8 million.  Also impacting Energy Related Business revenues
were increased revenues of EUA TransCapacity of approximately $500,000.


    EUA Cogenex revenues decreased by $23.2 million in 1996.  This decrease
was due primarily to lower project sales of approximately $18.8 million, the
absence of cogeneration revenues which amounted to $5.5 million in 1995,
resulting from EUA Cogenex's decision to discontinue cogeneration operations
in September 1995, and decreased Renova revenues of $7.9 million.  These
decreases were offset somewhat by increased revenues of Cogenex-West, EUA
Citizens and EUA Day aggregating $8.8 million.

Core Electric Business kWh Sales
Primary kWh sales of electricity by EUA's Core Electric Business Unit increased
1.2% in 1997 compared to the prior year.  This change was led by increases of
2.4% in the residential and industrial customer classes.  Total energy sales
increased 4.6% in 1997, due mainly to increased sales to NEPOOL and increased
short-term unit contract energy sales.  These NEPOOL interchange and short-term
unit contract sales essentially recover fuel costs and have little or no
earnings impacts.

Primary kWh sales of electricity increased by 1.1% in 1996 compared to 1995,
led by a 2.6% gain in sales to our residential customers.  Total energy sales
including NEPOOL interchange and short-term unit contract sales increased by
2.0%.

Expenses
Fuel and Purchased Power:  The EUA System's most significant expense items
continue to be fuel and purchased power expenses of our Core Electric Business
which together comprised about 45% of total operating expenses in 1997.

Percentage changes in kWh Sales by class of customer for the past two years
were as follows:

                         Percent Increase (Decrease) from Prior Year
                                     1997          1996
Residential                           2.4           2.6
Commercial                           (0.7)         (0.5)
Industrial                            2.4           0.1
Other Electric Utilities             (9.0)         15.7
Other                                 7.4           2.6
Total Primary Sales                   1.2           1.1
Losses and Company Use                5.1          (8.6)
Total System Requirements             1.4           0.7
Unit Contracts                       33.7          16.2
Total Energy Sales                    4.6           2.0

Fuel expense of the Core Electric Business increased by approximately $18.6
million or 20.1% in 1997, due primarily to a 4.6% increase in total energy
generated and purchased.  Outages of nuclear units in 1997 contributed to a
greater dependence on higher cost fossil fuels for energy requirements,
resulting in an increase in average fuel costs of 16.3% in 1997.  The increase
of $1.3 million or 1.4% in 1996, was due primarily to a 2.0% increase in total
energy generated and purchased.

Purchased Power demand expense increased approximately $700,000 or less
than 1% in 1997.  This change is primarily due to increased billings from the
Pilgrim and Maine Yankee nuclear units and Potter #2 fossil unit aggregating
$6.5 million.  These increases were offset by decreased billings from
Connecticut Yankee and Ocean State Power (OSP) of approximately $3.0 million
and $2.8 million, respectively.  Purchased Power demand expense decreased $6.8
million or 5.4% in 1996.  The decrease is due primarily to the impact of lower
billings from the Pilgrim nuclear unit of approximately $4.2 million, which
included a prior period refund, and decreased billings from OSP and Maine
Yankee aggregating $2.5 million.

Other Operation and Maintenance (O&M):  O&M expenses for 1997 increased by
$14.4 million or 8.0% compared to 1996.  Total O&M expenses are comprised of
three components:  Direct Controllable, Indirect and Energy Related.

O&M expenses by component for 1997, 1996 and 1995 were as follows:

($ in millions)            1997       1996        1995
Direct Controllable     $  89.1   $   87.5    $   83.4
Indirect                   51.1       36.7        41.3
Energy Related             52.7       55.7        62.7
Total O&M               $ 192.9    $ 179.9     $ 187.4


Direct Controllable expenses of our Core Electric and Corporate Business units
represent 45.9% of total 1997 O&M expenses and include expense items such as
salaries, fringe benefits, insurance and maintenance.  In 1997, direct
expenses increased approximately $1.6 million compared to 1996, primarily due
to increased legal expenses in 1997.  In 1996 direct expenses increased by
$4.1 million due primarily to incremental storm expenses related to an unusual
number of severe storms which struck our retail service territories in that
year, costs related to the electric industry restructuring activities and
increased assessments by the Federal Energy Regulatory Commission (FERC).

Indirect expenses include items over which we have limited short-term control.
Indirects include such expense items as O&M expenses related to Montaup
Electric Company's (Montaup) joint ownership interests in generating facilities
such as Seabrook I and Millstone 3 (see Note H of Notes to Consolidated
Financial Statements for other jointly-owned units), power contracts where
transmission rental fees are fix ed and C&LM expenses that are fully recovered
in revenues.  Indirect expenses increased by approximately $14.4 million in
1997.  This change was primarily due to increased jointly owned unit expense of
approximately $9.0 million, of which approximately $5.0 million is related to
the Millstone 3 outage and the remainder is due to increased expenses related
to the scheduled maintenance outages at the Canal and Seabrook units.  Also
impacting the change were increased C&LM expenses of approximately $3.3
million, approximately $1.2 million of transmission expenses related to new
transmission tariffs implemented by FERC in 1997 to accommodate utility
industry restructuring, and increased pension related expenses of approximately
$700,000.  Indirect expenses decreased by $4.6 million in 1996.  The decrease
included lower C&LM and Montaup power contract expenses aggregating $6.4
million, somewhat offset by jointly owned unit expenses, which included
incremental outage costs of Millstone 3.

The Energy Related component relates to O&M expenses of our Energy Related
Business unit where changes are tied to changes in business activity.  EUA
Cogenex continues to be the most active of our Energy Related businesses and
incurred 92% of the total O&M expenses of this business unit in 1997.  Energy
Related expenses decreased by approximately $3.0 million in 1997.  This
decrease was due primarily to decreased employee levels and other ongoing cost
control efforts of the EUA Cogenex Division of approximately $2.2 million,
decreased expenses of Renova of approximately $1.6 million, resulting from
decreased operating activity, offset by increased expenses of Cogenex-West of
approximately $300,000 as a result of increased marketing activity .  Energy
Related expenses decreased by $7.0 million in 1996.  The change included
decreases in EUA Cogenex sales-related expenses of $10.8 million, decreased
Renova costs of goods sold of $5.6 million and the absence of cogeneration
related expenses , which amounted to $4.6 million in 1995.  EUA Energy
Investment Corporation (EUA Energy Investment) expenses decreased by $400,000
in 1996.  These decreases were offset somewhat by the June 1996 EUA Cogenex
charge of $5.9 million and increased expenses of Cogenex-West and EUA Citizens
aggregating $7.9 million.

Voluntary Retirement Incentives:  In June 1997, an early retirement offer was
accepted by a group of nine employees who were eligible for but not offered a
Voluntary Retirement Incentive offer completed in 1995.  The pre-tax cost of
the 1997 offer, recorded in the second quarter, was approximately $1.4 million.
The 1995 Voluntary Retirement Incentive resulted in a pre-tax charge of $4.5
million.

"Note in margin: "Based on our 4% ownership share in the unit.""


    Depreciation and Amortization: Depreciation and Amortization expense
increased by approximately $1.5 million in 1997 due primarily to higher
depreciable plant balances at our Core Electric companies and a $500,000
increase in EUA Cogenex depreciation directly related to increased project
revenue.  Depreciation and Amortization expense in 1996 was relatively
unchanged from the 1995 level.

    Income Taxes:  EUA files a consolidated federal income tax return for the
EUA System. The composite federal and state effective income tax rate for 1997
was relatively unchanged at 35.8% versus to 35.1% in 1996.

    Other Income (Deductions) - Net:  Other Income and (Deductions) - Net
increased approximately $5.9 million in 1997.  This was primarily due to the
net positive impact of the power marketing joint venture termination in 1997,
increased interest income related to the favorable resolution of a
Massachusetts corporate income tax dispute in 1997, and the impact of changes
to the EUA Cogenex pension and post-retirement welfare benefit plans offset by
gains recorded in 1996 from the sale of Seabrook II equipment jointly owned by
Montaup.  Other Income and (Deductions) - Net increased $ 2.5 million in 1996.
Approximately $1.7 million of this increase was due to the sale of Seabrook II
equipment jointly owned by Montaup.  In addition, an increase in EUA Cogenex
interest income was partially offset by the impact of the write-off of EUA
Cogenex's joint venture start-up costs, included in the June 1996 $5.9 million
charge.

    Interest Charges:  Net interest charges for 1997 were relatively unchanged
from the 1996 level.  Decreased long-term debt interest resulting from normal
cash sinking fund payments was offset by higher interest expense related to
increased short-term debt and decreased capitalized interest by EUA Cogenex.
Net interest charges for 1996 decreased approximately $2.3 million from 1995
amounts. This decrease was primarily due to the December 1995 maturity of $25
million of 9-9 1/4% Unsecured Medium Term Notes and $10 million of 8.9% First
Mortgage and Collateral Trust Bonds of Eastern Edison Company (Eastern Edison),
offset somewhat by a decrease in capitalized interest by EUA Cogenex and higher
interest expense related to increased short-term debt.

Financial Condition and Liquidity:  The EUA System's need for permanent capital
is primarily related to investments in facilities required to meet the needs of
its existing and future customers.  These needs will diminish to the extent
that EUA divests all or a portion of its generation assets.

"Note in margin: "Internal generation of cash remains strong!""


Core Electric Business:  For 1997, 1996 and 1995, Core Electric Business cash
construction expenditures were $21.9 million, $33.3 million, and $31.5 million,
respectively.

Internally generated funds available after the payment of dividends supplied
approximately 133%, 118%, and 210% of these cash construction requirements in
1997, 1996 and 1995, respectively.  Various laws, regulations and contract
provisions limit the use of EUA's internally generated funds such that the
funds generated by one subsidiary are not generally available to fund the
operations of another subsidiary.

Cash construction expenditures of the Core Electric Business for 1998, 1999 and
2000 are estimated to be approximately $29.7 million, $25.2 million and $21.9
million, respectively, and are expected to be financed with internally
generated funds.

In addition to construction expenditures, projected requirements for scheduled
cash sinking fund payments and mandatory redemption of securities of the Core
Electric Business for 1998 through 2002 are $62.2 million, $11.6 million, $2.3
million, $4.1 million and $38.4 million, respectively.

Energy Related Business:  Capital expenditures of our Energy Related Business
amounted to $51.9 million, $28.1 million and $44.7 million, in 1997, 1996 and
1995, respectively.  Internally generated funds supplied 88%, 72% and 69%, of
cash capital requirements in 1997, 1996, and 1995, respectively.  Estimated
capital expenditures of the Energy Related Business are $56.3 million, $67.2
million, and $69.5 million in 1998, 1999 and 2000, respectively.  Internally
generated funds are expected to supply approximately 110% of 1998 estimated
capital requirements.

In addition to capital expenditures and energy related investments, projected
requirements for scheduled cash sinking fund payments and mandatory redemption
of securities of the Energy Related Business are $9.2 million in 1998 and 1999,
$59.2 million in 2000, $9.2 million in 2001 and $6.0 million in 2002.

On September 30, 1997, EUA Cogenex used short-term borrowings to fund the
maturity of $15 million of 7.22% Unsecured Notes.

Corporate:  Construction activity of the Corporate Business unit is minimal.
Projected requirements for scheduled cash sinking fund payments for the
corporate operations for each of the five years following 1997 are $1.1
million.

Short-Term Lines of Credit:   In July 1997, several EUA System companies
entered into a three-year revolving credit agreement allowing for borrowings
in aggregate of up to $120 million.  As of December 31, 1997, various financial
institutions have committed up to $75 million under the revolving credit
facility.

Year-End Short-Term Debt outstanding by business unit:

($ in thousands)                     1997           1996
Core Electric Business          $   7,075       $  3,670
Energy Related Business            44,609         24,341
Corporate                           9,800         23,837
Total                            $ 61,484       $ 51,848


EUA expects to repay the outstanding balances of short-term indebtedness
through internally generated funds.

Energy Related Businesses
Net Earnings and Earnings Per Share contributions of EUA's Energy Related
Businesses for 1997 and 1996 were as follows:

EUA Cogenex:  EUA Cogenex provides energy efficiency products and energy
management services throughout North America.  Strategic moves made in 1996
returned EUA Cogenex to profitability in 1997.  EUA Cogenex's earnings
increased approximately $3.1 million in 1997 due largely to 1996 staff
reductions, the refocusing of its national sales force and benefits resulting
from changes to pension and post-retirement welfare plans in 1997.

EUA Ocean State:  EUA Ocean State owns 29.9% of each of the partnerships which
developed and operate Units I and II of OSP, twin 250-megawatt gas-fired
generating units in northern Rhode Island.  Both units have provided a premium
return since their respective in-service dates of December 31, 1990, and
October 1, 1991.  The slight change in EUA Ocean State earnings contribution
was due to a lower investment base billed by the project in 1997.

EUA Energy Investment:  EUA Energy Investment was organized to seek out
investments in energy related businesses.  The change in Energy Investment's
earnings contribution was due to decreased losses at EUA TransCapacity, offset
by increased development costs at EUA BIOTEN.

                                       1997                          1996
                           Net Earnings   Earnings     Net Earnings  Earnings
                             (Loss)        (Loss)       (Loss)        (Loss)
                             (000's)     Per Share     (000's)       Per Share
EUA Cogenex               $    202      $     0.01   $ (2,850)(1)   $(0.14)(1)
EUA Ocean State              3,967            0.19      4,152         0.20
EUA Energy Investment      (3,741)           (0.18)    (3,990)       (0.19)
EUA Energy Services          (354)           (0.02)       (50)       (0.00)
EUA Telecommunications        (25)           (0.00)
From Operations                49             0.00     (2,738)       (0.13)
Cogenex Charge                                         (3,672)       (0.18)
Energy Related Business    $   49        $    0.00    $(6,410)      $(0.31)

(1) Excludes June 1996, after-tax charge to earnings of $3.7 million or
    18 cents per share.

EUA Energy Services:  The loss generated by EUA Energy Services was related to
startup costs of the now terminated power marketing joint venture with an
affiliate of Duke Energy Corporation.

EUA Telecommunications:  The small loss generated by EUA Telecommunications is
related to startup costs of this subsidiary in 1997.

Electric Utility Industry Restructuring Unbundled Services:  The electric
utility industry in both Massachusetts and Rhode Island, the states in
which EUA provides electric services, is transitioning from a traditional
rate regulated environment to a competitive marketplace.  Traditional electric
utility services - generation, transmission and distribution - have been
unbundled into separate and distinct services. The generation, or supply,
function is now competitive with customers able to choose their own
electricity supplier at market prices.  The transmission and
distribution functions remain regulated services.  The local distribution
company is responsible for providing distribution services to the ultimate
electricity consumer within its franchised service territory and t he
transmission company is required to provide open access, non-discriminatory
transmission services to generation or supply companies.

Stranded Costs:  Stranded costs represent prudently incurred costs of
generation which are now above their current economic value.  In both
Massachusetts and Rhode Island (see discussions below) stranded costs have been
defined to include items such as above market net investments in generation
assets, generation related regulatory assets, nuclear decommissioning and above
market commitments under current power purchase contracts.  A December 19, 1997
order from FERC provides Montaup, the EUA System's generation company, with
full recovery of its stranded costs.  Stranded costs are recovered via a
Contract Termination Charge (CTC) under a contract termination agreement which
replaced the all-requirements contracts formerly in force between Montaup and
its retail affiliates.  In its order, FERC approved settlement agreements
between Montaup, its retail affiliates and consumer representatives in
Massachusetts and Rhode Island.  Both states' regulatory bodies have approved
retail settlements in accordance with enabling state legislation.  At December
31, 1997 Montaup estimated its stranded costs, including unmitigated investment
in owned generation, generation related regulatory assets, above-market
purchase power commitments, nuclear decommissioning and transition expenses to
be approximately $1 billion on a present value basis.  This estimate is subject
to significant uncertainties including the future market price of electricity.
See "Divestiture" below for a discussion of stranded cost mitigation.

"Note in margin: "The key to an open competitive market among electricity
providers.""


Rhode Island - Retail:  On August 7, 1996, the Governor of Rhode Island signed
into law the Utility Restructuring Act of 1996 (URA).  The URA provides for
customer choice of electricity supplier in several phases commencing July 1,
1997 for certain customers and culminating with choice for all customers by
July 1, 1998, or sooner.  Under the URA, the local distribution company retains
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory.  For customers
who do not choose an alternative supplier, the local distribution company must
arrange for standard offer service.  Distribution companies are providers of
last resort service for customers who are unable to obtain their own supply.

The URA provides for full recovery of stranded costs, through a
non-bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000.  The costs of net, above-market generation assets and
regulatory assets will be recovered, with a return, through a fixed component
of the transition charge from January 1, 1998, through December 31, 2009.  A
variable component of the transition charge will recover, on a reconciling
basis, among other things, nuclear decommissioning and above market purchased
power commitments from January 1, 1998, through the life of the respective unit
or contract.  The URA also provides for commitments to demand side management
initiatives and renewables, low-income customer protections, divestiture of at
least 15% of owned non-nuclear generating units as a valuation basis for
mitigation of stranded cost recovery, and performance-based ratemaking (PBR)
standards for electric distribution companies to be in effect
until the end of 1998.  These performance-based standards provide for a 6%
minimum and an approximate 12% maximum allowed return on equity for Blackstone
Valley Electric Company (Blackstone) and Newport Electric Corporation
(Newport), EUA's Rhode Island Distribution Companies (R.I. Distribution
Companies).  In addition, the URA provides for adjustments to electric
distribution companies' base rates using the prior year's Consumer Price Index
for 1997 and 1998 and other performance factors.  Under this provision of the
law, rates were increased 1.3% for customers of both Blackstone and Newport
effective January 1, 1998.

In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the Rhode Island Public Utilities Commission (RIPUC),
outlining the terms of the settlement.  The settlement was submitted to the
RIPUC in two separate filings which were approved on April 21, 1997 and
December 17, 1997, respectively.  In addition to complying with the URA, the
settlement, similar in many respects to the settlement negotiated in
Massachusetts, described below, provided for a 4% rate reduction for Newport's
customers and a 13% rate reduction for Blackstone's customers effective
January 1, 1998, amendments to Blackstone and Newport power contracts with
Montaup to replace all-requirements provisions with a CTC concurrent with
retail access and the filing of a plan to divest all of Montaup's generating
assets.  The net proceeds of the divestiture will be used to mitigate the
amount of Montaup's stranded costs to be recovered through the CTC.  See
"Divestiture" below for a discussion of Montaup's divestiture process.

    On December 17, 1997, the RIPUC approved a retail settlement which included
a distribution rate freeze through December 31, 2000, except for any temporary
credit or surcharge resulting from PBR implementation or the standard offer
reconciliation, and retail access for all customers commencing January 1, 1998.
In addition to the approval of wholesale power contract amendments by FERC,
received on December 19, 1997 (See "FERC -Wholesale" below), any disposition of
generation assets resulting from the agreements or the URA would also require
the approval of the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935.

Massachusetts - Retail:  On December 23, 1996, Eastern Edison and Montaup
reached an agreement in principle with the Attorney General of Massachusetts
and the Massachusetts Department of Energy Resources (MADOER) and filed a MOU
with the Massachusetts Department of Telecommunications and Energy (DTE)
(formerly the Department of Public Utilities) outlining the terms of a plan,
similar in many aspects to the URA, which would allow retail customers to
choose their supplier of electricity in 1998 an d provide Eastern Edison and
Montaup full recovery of stranded costs.  On May 16, 1997 an Offer of
Settlement was filed with the DTE.

The Offer of Settlement provided all of Eastern Edison's customers the ability
to choose an alternative supplier of electricity beginning as soon as January
1, 1998.  Until a customer chooses an alternative supplier, that customer would
receive standard offer service which would be priced to guarantee at least a
10% reduction in electricity rates.  Eastern Edison would be required to
arrange for standard offer service through December 31, 2004 and would purchase
power for standard offer service from suppliers through a competitive bidding
process.  Montaup has guaranteed standard offer supply at a fixed price
schedule for the duration of the standard offer period.  For competitive
suppliers to be eligible to provide supplies for standard offer service, their
prices must be competitive with the fixed prices guaranteed by Montaup.  In the
event that some, or all, of the standard offer requirement is not awarded to
competitive suppliers, Montaup has an obligation to provide such requirement at
the indicated fixed price schedule, so called backstop service.  This backstop
service will be assigned proportionately to purchasers of Montaup's generating
capacity.  The agreement is also designed to achieve full divestiture of
Montaup's generating assets via implementation of a plan, that would require
(1) functional separation by Montaup of its generating and transmission
businesses, and (2) full market valuation and sale of all non-nuclear
generating assets through an auction or equivalent process.

"Note in margin "Rhode Island leads the way to competition...""

    On March 1, 1998, concurrent with retail choice in Massachusetts, Montaup's
FERC-approved, all-requirements wholesale contract with Eastern Edison was
terminated.  In its place, Montaup is billing Eastern Edison a CTC designed to
recover, among other things, Montaup's stranded costs.  Eastern Edison recovers
the CTC through a non-bypassable transition access charge to all of its
distribution customers.  The transition access charge will be reduced by the
fair market value of Montaup's generating assets as determined by selling,
spinning off, or otherwise disposing of such generating facilities.  See
"Divestiture" below.

Embedded costs associated with generating plants and regulatory assets are
recovered, with a return, over a period of twelve years ending December 31,
2009.  Purchased power contracts and nuclear decommissioning costs are
recovered as incurred over the life of those obligations, a period expected to
extend beyond twelve years.  The initial transition access charge is set at
3.04 cents per kWh through December 31, 2000, and is expected to decline
thereafter.

The agreement also establishes a performance component for Eastern Edison,
incorporating a floor and cap on allowed return on equity.  Under the
agreement, Eastern Edison's distribution rates are frozen until December 31,
2000.  Subsequent to the commencement of retail choice, Eastern Edison's annual
return on equity is subject to a floor of 6% and a ceiling of 11.75%.

On November 25, 1997, the Governor of Massachusetts signed the Electric
Industry Restructuring Act (the Act) into law.  The Act directed the DTE to
require electric companies to accommodate retail access to generation services
and choice of supplier by March 1, 1998 and to require electric companies to
file restructuring plans to do so.  The Act also provides for a 10% reduction
in electric rates commencing March 1, 1998 and an additional 5% reduction,
adjusted for inflation, commencing September 1, 1999.  The additional 5%
reduction may be accomplished with benefits from asset divestiture and/or
securitization.

On December 23, 1997, the DTE approved the Settlement as being in substantial
compliance with the Act.  Retail access commenced on March 1, 1998 for Eastern
Edison's retail customers.

"Note in margin: "...followed closely by Massachusetts""

In January 1998, several parties filed motions for reconsideration of Eastern
Edison's approved settlement agreement and motions to extend the judicial
appeal period with the DTE.  The motions for reconsideration claim that
provisions of the approved plan involving consumer rates, cost recovery,
energy efficiency and reliability do not meet standards set forth in the Act.
The DTE denied one party's motions and that party has appealed the DTE's
ruling to the Massachusetts Supreme Judicial Court.  Management cannot predict
the ultimate outcome of the pending motions for reconsideration, or judicial
appeal.

The Office of the Attorney General has certified a referendum petition to
repeal the Act as a matter appropriate for a referendum initiative.  A petition
was filed with the Election Division of the Office of the Secretary of State in
February 1998.  A question on repealing the Act will be presented to voters on
the November 1998 ballot.  EUA and the electric industry in Massachusetts will
actively oppose repeal.  Management cannot predict the outcome of the November
ballot question.

FERC - Wholesale:  On May 1, 1997, Montaup and the R.I. Distribution Companies
jointly filed amendments to their FERC-approved all-requirements power
contracts.  The filing included a calculation for a CTC to recover stranded
costs and a provision for standard offer service for resale to retail customers
who do not choose an alternate generation supplier as discussed under
"Massachusetts-Retail" above.  These provisions replaced the services offered
by the all-requirements contracts upon full retail access pursuant to the URA.
The filing also included hold harmless provisions for Montaup's other wholesale
customers and for retail customers of the R.I. Distribution Companies and lost
revenue provisions, which allow for recovery of any of Montaup's lost revenues
for the period from the initial phases of retail access in Rhode Island through
completion of Montaup's divestiture process.  This filing allowed the R.I.
Distribution Companies to implement on July 1, 1997, the phase-in provisions of
the URA and prevented any cross-subsidies by their retail customers who were
excluded from the groups of customers given retail choice prior to January 1,
1998 and by Montaup's other customers.

On May 30, 1997, elements of the Massachusetts Settlement Agreement, including
the CTC calculation, which fall under the jurisdiction of FERC were filed with
FERC.

The May 1st and May 30th filings were consolidated by FERC and on October 29,
1997, settlement agreements among Montaup, its affiliated and non-affiliated
customers, the Massachusetts Attorney General, the MADOER, the RIDIV and RIPUC
were submitted for FERC approval.  These settlements represent a comprehensive
resolution of federal/wholesale issues of electric utility industry
restructuring based on the settlement agreements in Massachusetts and Rhode
Island.  FERC approved the settlements on December 19, 1997, accommodating
retail choice for EUA's retail customers in Massachusetts and Rhode Island.

"Note in margin: "We chose to negotiate rather than litigate""

Divestiture:  Montaup began marketing its portfolio of generation assets in
July 1997, and subsequently received bids from a number of potential
purchasers.  On January 23, 1998, based on a review of the offers and
discussions with potential purchasers, Montaup announced that it was reopening
the sales process on the majority of its generating assets.  The process is
expected to require four to six months to execute a purchase and sale
agreement.  The net proceeds of the sale, as defined in the settlement
agreements, will be used to mitigate Montaup's CTC to its retail affiliates via
a Residual Value Credit (RVC).  The RVC will reduce the fixed component of the
CTC for the net proceeds, with a return, in equal annual amounts over the
period commencing on the date the RVC is implemented through December 31, 2009.
Subject to regulatory approvals, Montaup anticipates the sale will be completed
in early 1999.

Accounting Issues:  Historically, electric rates have been designed to recover
a utility's full cost of providing electric service including recovery of
investment in plant assets.  Also, in a regulated environment, electric
utilities are subject to certain accounting rules that are not applicable to
other industries.  These accounting rules allow regulated companies, in
appropriate circumstances, to establish regulatory assets and liabilities,
which defer the current financial impact of certain costs that are expected to
be recovered in future rates. The SEC has raised issues concerning the
continued applicability of these standards with certain other electric
utilities in other states facing restructuring.

In July 1997, the Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) reached a consensus regarding certain issues raised related
to the application of Statement of Financial Accounting Standards No. 71
(FAS71), "Accounting for the Effects of Certain Types of Regulation."  The EITF
determined that when sufficient detail is available for an enterprise to
reasonably determine, from legislation and enabling rate orders, how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should discontinue the application of FAS71 to that
deregulated portion of its business.  The EITF also concluded that utilities
can continue to carry previously recorded regulatory assets on t heir balance
sheet if regulators have guaranteed a regulated cash flow stream to recover the
cost of those assets.

In light of approved restructuring settlement agreements and restructuring
legislation in both Massachusetts and Rhode Island, EUA has determined that
Montaup no longer will apply the provisions for FAS71 to the generation portion
of its business.  Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition.  EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.

In addition, if legislative or regulatory changes and/or competition result in
electric rates which do not fully recover a company's costs, a write-down of
plant assets could be required pursuant to Financial Accounting Standard No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of."  EUA does not anticipate any write-down of plant
assets as a result of approved restructuring plans or enacted legislation at
this time.

Environmental Matters
EUA's Core Electric Business subsidiaries and other companies owning generating
units from which power is obtained are subject, like other electric utilities,
to environmental and land use regulations at the federal, state and local
levels.  The federal Environmental Protection Agency (EPA), and certain state
and local authorities, have jurisdiction over releases of pollutants,
contaminants and hazardous substances into the environment and have broad
authority to set rules and regulations in connection therewith, such as the
Clean Air Act Amendments of 1990, which could require installation of pollution
control devices and remedial actions.  In 1994, EUA instituted an environmental
audit program to ensure compliance with environmental laws and regulations and
to identify and reduce liability with respect to those requirements.

Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by such authorities.  The EUA System
typically provides for the disposal of such substances through licensed
contractors, but statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for clean-up costs.
Subsidiaries of EUA have been notified with respect to a number of sites where
they may be responsible for such costs, including sites where they may have
joint and several liability with other responsible parties.  It is the policy
of the EUA System companies to notify liability insurers and to initiate
claims.  However, EUA is unable to predict whether liability, if any, will be
assumed by, or can be enforced against, insurance carriers in these matters.
As of December 31, 1997, the EUA System had incurred costs of approximately
$6.7 million in connection with these sites.  These amounts have been financed
primarily by internally generated cash.  The EUA System is currently amortizing
substantially all of its incurred costs over a five-year period consistent with
prior regulatory recovery periods and is recovering certain of those costs in
rates.

EUA estimates that additional costs of up to $1.3 million may be incurred at
these sites through 1998 by its subsidiaries.  Estimates beyond 1998 cannot be
made since site studies, which are the basis of these estimates, have not been
completed.

"Note in margin: "Program is an essential element in our environmental
stewardship policy""

In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million.  The clean-up costs were incurred by the Commonwealth of
Massachusetts at a site in which Blackstone has been named as a responsible
party.  See Note J of "Notes to Consolidated Financial Statements" for further
discussion.

A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found everywhere there is electricity.  Research to date has not conclusively
established a dire ct causal relationship between EMF exposure and human
health.  Additional studies, which are intended to provide a better
understanding of the subject, are continuing.  Management cannot predict the
ultimate outcome of the EMF issue.

Nuclear Power Issues
Montaup has a 4.01% ownership interest in Millstone 3, an 1154-mw nuclear unit
that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast).  Subsidiaries of Northeast are
the lead participants in Millstone 3.  On March 30, 1996, it was necessary to
shut down the unit following an engineering evaluation which determined that
four safety-related valves would not be able to perform their design function
during certain postulated events.

The Nuclear Regulatory Commission (NRC) has raised numerous issues with respect
to the unit and certain of the other nuclear units operated by Northeast.  The
NRC informed Northeast that it was establishing a Special Projects Office to
oversee inspection and licensing activities at Millstone and directed Northeast
to submit a plan for disposition of safety issues raised by employees and
retain an independent third-party to oversee implementation of this plan.

In March of 1997, Northeast announced that Millstone 3 had been designated as
the lead unit in the recovery process of the three Millstone nuclear units that
are currently out of service.  Millstone 3 is the largest of the three units
currently out of service, and its return to service will most benefit the
energy needs of the New England region.

On January 8, 1998, Northeast announced that Millstone 3 was "physically ready
for restart" indicating that virtually all of the restart-required physical
work had been completed.  Northeast indicated that a small amount of systems
work needs to be completed prior to restart.  Various NRC and independent
inspections are required prior to restart. EUA cannot predict when the plant
will be restarted.  While Millstone 3 is out of service, Montaup will continue
to incur incremental replacement power costs estimated at up to $1 million per
month.

Montaup has been paying its share of Millstone 3's O&M expenses on a
reservation of right basis.  The fact that Montaup makes payment for these
expenses is not an admission of financial responsibility for expenses incurred
or to be incurred due to the outage.

In August 1997, nine non-operating owners, including Montaup, who together own
approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees.  CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
which agreed to be responsible for the proper operation of the unit.

The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC.  The
arbitration and lawsuits seek to recover costs associated with replacement
power and O&M costs resulting from the shutdown of Millstone 3.  The non-
operating owners conservatively estimate that their losses will exceed $200
million.

EUA cannot predict the ultimate outcome of the NRC inquiries or legal
proceedings brought against CL&P, WMECO and Northeast or the impact which they
may have on Montaup and the EUA System.

On August 6, 1997, as the result of an economic evaluation, the Maine Yankee
Board of Directors voted to permanently close that nuclear plant.  Montaup has
a 4.0% equity ownership in Maine Yankee with a book value of approximately $3.2
million at December 31, 1997.  Montaup's share of the total estimated costs for
the permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee, is approximately $35.4 million and is included with
Other Liabilities on the Consolidated Balance Sheet for the period ending
December 31, 1997.  Also, due to anticipated recoverability, a regulatory asset
has been recorded for the same amount and is included with Other Assets.  The
recovery of this estimated amount is subject to approval of FERC.  Montaup
cannot predict the ultimate outcome of FERC's review.

Also, as a result of the shutdown, Montaup and the other equity owners of Maine
Yankee have been notified by the Secondary Purchasers that they will no longer
make payments for purchased power to Maine Yankee.  The Secondary Purchase
Contracts are be tween the equity owners as a group and 30 municipalities
throughout New England.  The equity owners are currently making payments to
Maine Yankee to cover the payments that would be made by the municipals.

"Note in margin: "To reduce continued additional costs of outage and recover
funds we've already spent""

On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation of
Arbitration to the equity owners of Maine Yankee.  On December 15, 1997, the
equity owners as a group filed at FERC a Complaint and Petition for
Investigation, Contract Modification, and Declaratory Order.  The equity owners
are seeking an order from FERC declaring that the Secondary Purchasers remain
responsible for payments due under the Purchase Contracts and directing the
Secondary Purchasers to make such payments.  The equity owners also seek a
modification of the Purchase Contracts to extend the termination date or
otherwise to ensure that the equity owners may fully recover from the Secondary
Purchasers a share of the costs of shutting down and decommissioning the Maine
Yankee plant that is proportional to the Secondary Purchasers' entitlements to
energy from the plant.  Management does not believe that this contract issue
will have a material effect on EUA's future operating results or financial
position and cannot predict its ultimate outcome at this time.

Recent actions by the NRC, some of which are cited above, indicate that the NRC
has become more critical and active in its oversight of nuclear power plants.
EUA is unable to predict at this time, what, if any, ramifications these NRC
actions will h ave on any of the other nuclear power plants in which Montaup
has an ownership interest or power contract.

Montaup is recovering through rates its share of estimated decommissioning
costs for the Millstone 3 and Seabrook I nuclear generating units.  Montaup's
share of the currently allowed estimated total costs to decommission Millstone
3 is approximately $21.9 million in 1997 dollars and Seabrook I is
approximately $13.7 million in 1997 dollars.  These figures are based on
studies performed for the lead owners of the units.  Montaup also pays into
decommissioning reserves, pursuant to contractual arrangements, at other
nuclear generating facilities in which it has an equity ownership interest or
life-of-unit entitlement.  Such expenses are currently recovered through rates.

In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in federal
appeals court seeking a court order to require the Department of Energy (DOE)
to immediately establish a program for the disposal of spent nuclear fuel.
Yankee Atomic and Connecticut Yankee are also seeking damages of approximately
$70 million and $90 million, respectively.  Under the Nuclear Waste Policy Act
of 1992, the DOE was to provide for the disposal of radioactive wastes and
spent nuclear fuel starting in 1998 and has collected funds from owners of
nuclear facilities to do so.  Management cannot predict the ultimate outcome of
this issue.

Year 2000 Issue
EUA has conducted a comprehensive review of its computer systems to identify
the systems that could be affected by the Year 2000 Issue and is developing an
implementation plan to resolve the issue.  The Year 2000 Issue is the result of
computer programs being written using two digits rather than four to define the
applicable year.  Any programs that have time-sensitive software may recognize
a date using "00" as the year 1900 rather than the year 2000.  This could
result in a major system failure or miscalculations.  EUA believes that, with
modifications to existing software and conversions to new software, the Year
2000 problem will not pose significant operational problems for its computer
systems as so modified and converted.  It is anticipated that all reprogramming
efforts will be complete by the spring of 1999, allowing adequate time for
testing.  In addition, notices have been sent to EUA's primary processing
vendors seeking assurance that plans are being developed to address processing
of transactions in the year 2000.  Management does not believe the year 2000
compliance expense will be material to EUA's future operating results or future
financial condition.

New Accounting Standards
In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains, and losses) in a set of general-purpose
financial statements.  This Statement requires that all items that are required
to be recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the same
prominence as other financial statements.  This Statement is effective for
fiscal years beginning after December 15, 1997, and EUA will adopt Statement
130 in the first quarter of 1998.

Other
EUA occasionally makes forward-looking projections of expected future
performance or statements of our plans and objectives.  These forward-looking
statements may be contained in filings with the SEC, press releases and oral
statements.  Actual results could differ materially from these statements.
Therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.



"Management's Discussion and Analysis of Financial Condition and Review of
Operations" provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Consolidated Financial Statements" and "Notes to Consolidated Financial
Statements" to arrive at a more complete understanding of such matters.



Financial Table of Contents


Consolidated Statements of Income                               30
Consolidated Statements of Cash Flows                           31
Consolidated Balance Sheets                                     32
Consolidated Statements of Retained Earnings                    33
Consolidated Statements of Equity Capital and Preferred Stock   33
Consolidated Statements of Indebtedness                         34
Notes to Consolidated Financial Statements                      35
Report of Independent Accountants                               44
Report of Management                                            44
Quarterly Financial and Common Share Information                45
Consolidated Operating and Financial Statistics                 46
Shareholder Information                                         48
Trustees and Officers                             Inside Back Cover

<TABLE>
Consolidated Statements of Income
<CAPTION>

($ in thousands except Common Shares and per Share Amounts)
Years Ended December 31,                1997            1996            1995
<S>                                     <C>             <C>               <C>

OPERATING REVENUES              $       568,513 $       527,068 $       563,363
OPERATING EXPENSES:
  Fuel                                  110,724          92,166          90,888
  Purchased Power-Demand                119,485         118,830         125,616
  Other Operation                       162,464         154,831         163,907
  Voluntary Retirement Incentives         1,416                           4,505
  Maintenance                            30,432          25,047          23,468
  Depreciation and Amortization          46,941          45,478          45,492
  Taxes - Other Than Income              24,021          23,933          20,744
  Income Taxes                           14,223          10,942          17,015
          Total Operating Expenses      509,706         471,227         491,635
  Operating Income                       58,807          55,841          71,728
  Equity in Earnings of Jointly
     Owned Companies                      9,466          10,698          12,063
Allowance for Other Funds Used
  During Construction                       162             452             538
  Loss on Disposal of Cogeneration
     Operations                                                         (18,086)
  Income Tax Impact of Loss on
     Disposal of Cogeneration
  Operations                                                              7,588
  Other Income (Deductions) - Net        10,986           5,054           2,574
     Income Before Interest Charges      79,421          72,045          76,405
INTEREST CHARGES:
      Interest on Long-Term Debt         32,198          34,035          38,216
     Amortization of Debt Expense
       and Premium - Net                  2,548           2,620           2,752
     Other Interest Expense               5,245           4,199           3,167
     Allowance for Borrowed Funds
       Used During Construction (Credit)   (835)         (1,735)         (2,677)
      Net Interest Charges               39,156          39,119          41,458
Net Income                               40,265          32,926          34,947
Preferred Dividends of Subsidiaries       2,305           2,312           2,321
Consolidated Net Earnings        $       37,960  $       30,614  $       32,626
Average Common Shares Outstanding    20,435,997      20,436,217      20,238,961
Consolidated Basic and Diluted
     Earnings per Share          $         1.86    $       1.50  $         1.61
Dividends Paid per Share         $         1.66    $      1.645  $        1.585

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

<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>


Years Ended December 31, ($ in thousands)  1997           1996            1995
<S>                                         <C>            <C>              <C>

CASH FLOW FROM OPERATING ACTIVITIES:
Net Income                       $       40,265    $     32,926  $       34,947
Adjustments to Reconcile Net Income
to Net Cash Provided from Op. Act.:
  Depreciation and Amortization          51,615          50,690          52,413
  Amortization of Nuclear Fuel            1,067           1,676           3,647
  Deferred Taxes                         (6,317)         11,610            (985)
  Non-cash Expenses/(Gains) on Sales
   Inv. in Energy Savings Projects       15,993           8,262          (1,264)
  Loss on Disposal of Cog. Ops.                                          18,086
  Investment Tax Credit, Net             (1,201)         (1,207)         (1,212)
  Allowance for Other Funds
   Used During Construction                (162)           (452)           (538)
  Collections and Sales of Project
  Notes and Leases Receivable            19,148           7,776          17,748
  Other -  Net                           (5,726)          6,373           5,129
Changes in Operating Assets and Liabilities:
  Accounts Receivable                    (2,494)         (5,777)          5,729
  Materials and Supplies                  2,929           2,385          (1,280)
  Accounts Payable                        1,225          (1,958)          1,543
  Taxes Accrued                              59          (1,539)         (1,921)
  Other - Net                              (664)          4,930         (19,079)
     Net Cash Provided from
           Operating Activities         115,737         115,695         112,963
CASH FLOW FROM INVESTING ACTIVITIES:
   Construction Expenditures            (76,118)        (62,730)        (77,923)
   Collections on Notes and Lease
     Receivables of EUA Cogenex          10,076           3,665           3,125
   Proceeds from Disposal of
     Cogeneration Assets                                                 11,501
   Other Investments                        312          (3,889)         (2,300)
      Net Cash (Used in) Investing
           Activities                   (65,730)        (62,954)        (65,597)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuances:
   Common Shares                                                          5,985
Redemptions:
   Long-Term Debt                       (28,617)        (20,617)        (42,725)
   Preferred Stock                                          (90)           (100)
Prem.on Reacquisition and Fin. Exp.                         (15)            (63)
EUA Common Share Dividends Paid         (33,924)        (33,618)        (32,050)
Subsidiary Preferred Dividends Paid      (2,305)         (2,314)         (2,324)
Net Increase in Short-Term Debt           9,636          12,308           7,862
      Net Cash (Used in)
         Financing Activities           (55,210)        (44,346)        (63,415)
NET (DECREASE) INCREASE IN CASH AND
        TEMPORARY CASH INVESTMENTS:      (5,203)          8,395         (16,049)
Cash and Temporary Cash Investments at
        Beginning of Year                12,455           4,060          20,109
Cash and Temporary Cash Investments at
        End of Year                       7,252          12,455           4,060
Cash Paid during the year for:
  Interest (Net of Amounts Capitalized) $55,172  $       40,658    $     39,306
  Income Taxes                          $28,921  $       11,530    $      9,412
Conversion of Investments in Energy Savings Projects
  to Notes and Leases Receivable        $ 5,404  $        7,779    $     19,324

The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>

Years Ended December 31, ($ in thousands)            1997               1996
<S>                                     <C>                 <C>

ASSETS
Utility Plant and Other Investments:
  Utility Plant in Service            $         1,079,361    $       1,067,056
  Less Accumulated Provisions for
      Depreciation and Amortization               376,722              350,816
       Net Utility Plant in Service               702,639              716,240
  Construction Work in Progress                     5,538                3,839
  Net Utility Plant                               708,177              720,079
  Non-utility Property - Net                       71,516               72,653
  Investments in Jointly Owned Companies           69,749               71,626
  Other                                            62,834               68,031
       Total Utility Plant and Other Investments  912,276              932,389
Current Assets:
  Cash and Temporary Cash Investments               7,252               12,455
  Accounts Receivable:
          Customers, Net                           64,214               66,089
          Accrued Unbilled Revenues                14,103               10,282
          Other                                    14,329               13,782
  Notes Receivable                                 27,693               24,691
  Materials and Supplies (at average cost):
  Fuel                                              4,304                6,924
  Plant Materials and Operating Supplies            6,897                7,207
  Other Current Assets                              7,177                7,668
          Total Current Assets                    145,969              149,098
  Other Assets                                    212,507              175,542
       Total Assets                     $       1,270,752       $    1,257,029
LIABILITIES AND CAPITALIZATION
Capitalization:
  Common Equity                         $         373,467       $      371,813
  Non-Redeemable Preferred Stock
     of Subsidiaries - Net                          6,900                6,900
  Redeemable Preferred Stock
     of Subsidiaries - Net                         27,612               27,035
  Long-Term Debt - Net                            332,802              406,337
          Total Capitalization                    740,781              812,085
Current Liabilities:
  Short-Term Debt                                  61,484               51,848
  Long-Term Debt Due Within One Year               72,518               27,512
  Accounts Payable                                 35,036               33,811
  Taxes Accrued                                     3,063                3,004
  Interest Accrued                                  8,624                9,612
  Other Current Liabilities                        33,327               26,772
          Total Current Liabilities               214,052              152,559
Other Liabilities                                 152,526              123,209
Accumulated Deferred Taxes                        163,393              169,176
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization    $       1,270,752      $     1,257,029

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

<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>

Years Ended December 31, ($ in thousands)         1997           1996           1995
<S>                                     <C>             <C>            <C>

Retained Earnings - Beginning of Year   $       52,404  $       56,228  $       56,617
Consolidated Net Earnings                       37,960          30,614          32,626
   Total                                        90,364          86,842          89,243
Dividends Paid - EUA Common Shares              33,924          33,618          32,050
Other                                              378             820             965
Retained Earnings - Accumulated since
  June 1991 Accounting Reorganization   $       56,062  $       52,404  $       56,228
</TABLE>
<TABLE>

Consolidated Statements of Equity Capital & Preferred Stock
<CAPTION>

Years Ended December 31, ($ in thousands)      1997            1996
<S>                                        <C>             <C>
EASTERN UTILITIES ASSOCIATES:
Common Shares:
 $5 par value 36,000,000 shares authorized, 20,435,997 shares outstanding
          in 1997 and 1996                 $       102,180   $       102,180
Other Paid-In Capital                              219,156           221,160
Common Share Expense                               (3,931)            (3,931)
Retained Earnings - Accumulated since June
     1991 Accounting Reorganization                56,062             52,404
                Total Common Equity               373,467            371,813
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
Non-Redeemable Preferred:
        Blackstone Valley Electric Company:
        4.25% $100 par value 35,000 shares <F1>     3,500              3,500
        5.60% $100 par value 25,000 shares <F1>     2,500              2,500
        Premium                                       129                129
        Newport Electric Corporation:
        3.75% $100 par value 7,689 shares <F1>        769                769
        Premium                                         2                  2
      Total Non-Redeemable Preferred Stock          6,900              6,900
Redeemable Preferred:
        Eastern Edison Company:
         65/8% $100 par value 300,000 shares <F2>  30,000             30,000
         Expense, Net of Premium                     (335)              (335)
        Preferred Stock Redemption Costs           (2,053)            (2,630)
       Total Redeemable Preferred Stock            27,612             27,035
       Total Preferred Stock of Subsidiaries   $   34,512           $ 33,935
<FN>
<F1> Authorized and Outstanding.
<F2> Authorized 400,000 shares.  Outstanding 300,000 at December 31, 1997.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Indebtedness
<CAPTION>

Years Ended December 31, ($ in thousands)                1997           1996
<S>                                                       <C>            <C>

EUA Service Corporation:
    10.2% Secured Notes due 2008                $       7,900   $       10,100
EUA Cogenex Corporation:
    7.22% Unsecured Notes due 1997                                      15,000
    7.0% Unsecured Notes due 2000                       50,000          50,000
    9.6% Unsecured Notes due 2001                       12,800          16,000
    10.56% Unsecured Notes due 2005                     28,000          31,500
EUA Ocean State Corporation:
    9.59% Unsecured Notes due 2011                      28,590          31,067
Blackstone Valley Electric Company:
 First Mortgage Bonds:
    9 1/2% due 2004 (Series B)                          10,500          12,000
    10.35% due 2010 (Series C)                          18,000          18,000
 Variable Rate Demand Bonds due 2014(1)                  6,500           6,500
Eastern Edison Company
 First Mortgage and Collateral Trust Bonds:
    5 7/8% due 1998                                     20,000          20,000
    5 3/4% due 1998                                     40,000          40,000
    7.78 % Secured Medium Term Notes due 2002           35,000          35,000
    6 7/8% due 2003                                     40,000          40,000
    6.35% due 2003                                       8,000           8,000
    8.0% due 2023                                       40,000          40,000
 Pollution Control Revenue Bonds:
    5 7/8% due 2008                                     40,000          40,000
Newport Electric Corporation:
 First Mortgage Bonds:
    9.0% due 1999                                        1,386           1,386
    9.8% due 1999                                        8,000           8,000
    8.95% due 2001                                       2,600           3,250
 Small Business Administration Loan:
    6.5% due 2005                                          628             719
 Variable Rate Revenue Refunding Bonds due 2011 <F1>     7,925           7,925
Unamortized (Discount) - Net                              (509)           (598)
                                                       405,320         433,849
Less Portion Due Within One Year                        72,518          27,512
      Total Long-Term Debt - Net               $       332,802 $       406,337
<FN>
<F1>  Weighted average interest rate was 3.7% for 1997 and 3.5% for 1996.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>



(A) Nature of Operations and Summary of Significant Accounting Policies:
General:  Eastern Utilities Associates (EUA) is a diversified energy services
holding company.  Its subsidiaries are principally engaged in the generation,
transmission, distribution and sale of electricity; energy related services
such as energy management; and promoting the conservation and efficient use of
energy.

Estimates:  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 assets and 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.

Basis of Consolidation:  The consolidated financial statements include the
accounts of EUA and all subsidiaries.  All material intercompany transactions
between the consolidated subsidiaries have been eliminated.

System of Accounts:  The accounts of EUA and its consolidated subsidiaries are
maintained in accordance with the uniform system of accounts prescribed by the
regulatory bodies having jurisdiction.

Jointly Owned Companies:   Montaup Electric Company (Montaup) follows the
equity method of accounting for its stock ownership investments in jointly
owned companies including four regional nuclear generating companies.
Montaup's investments in these nuclear generating companies range from 2.5% to
4.5%.  Three of the four facilities have been permanently shut down and are in
the process of decommissioning.  Montaup is entitled to electricity produced
from the remaining facility based on its ownership interest and is billed for
its entitlement pursuant to a contractual agreement which is approved by the
Federal Energy Regulatory Commission (FERC).

In December 1996, the Board of Directors of Connecticut Yankee voted to retire
the generating station.  Connecticut Yankee certified to the Nuclear Regulatory
Commission (NRC) that it had permanently closed power generation operations and
removed fuel from the reactor.  Montaup has a 4.5% equity ownership in
Connecticut Yankee.  Montaup's share of the total estimated costs for the
permanent shutdown, decommissioning, and recovery of the investment in
Connecticut Yankee is approximately $27.4 mil lion and is included with Other
Liabilities on the Consolidated Balance Sheet as of December 31, 1997.  Also,
due to recoverability, a regulatory asset has been recorded for the same amount
and is included with Other Assets.  The recovery of this estimated amount,
elements of which have been disputed by certain intervening parties, is subject
to approval of FERC.  Montaup cannot predict the ultimate outcome of FERC's
review.

In August 1997, as the result of an economic evaluation, the Maine Yankee Board
of Directors voted to permanently close that nuclear plant.  Montaup has a 4.0%
equity ownership in Maine Yankee.  Montaup's share of the total estimated costs
for the permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee is approximately $35.4 million and is included with
Other Liabilities on the Consolidated Balance Sheet as of December 31, 1997.
Also, due to recoverability, a regulatory asset has been recorded for the same
amount and is included with Other Assets.  The recovery of this estimated
amount, elements of which have been disputed by certain intervening parties,
is subject to approval of FERC.  Montaup cannot predict the ultimate outcome of
FERC's review.

Montaup also has a stock ownership investment of 3.27% in each of two companies
which own and operate certain transmission facilities between the Hydro Quebec
electric system and New England.

EUA Ocean State Corporation (EUA Ocean State) follows the equity method of
accounting for its 29.9% partnership interest in the Ocean State Power Project
(OSP).  Also, EUA Energy Investment follows the equity method of accounting for
its 40% partners hip interest in BIOTEN, G.P. and for its 20% stock ownership
in Separation Technologies, Inc.  These ownership interests and Montaup's stock
ownership investments are included in "Investments in Jointly Owned Companies"
on the Consolidated Balance Sheet.

Plant and Depreciation:  Utility plant is stated at original cost.  The cost of
additions to utility plant includes contracted work, direct labor and material,
allocable overhead, allowance for funds used during construction and indirect
charges for engineering and supervision.  For financial statement purposes,
depreciation is computed on the straight-line method based on estimated useful
lives of the various classes of property.  On a consolidated basis, provisions
for depreciation on utility plant were equivalent to a composite rate of
approximately 3.6% in 1997, 3.7% in 1996, and 3.6% in 1995, based on the
average depreciable property balances at the beginning and end of each year.
Beginning in 1998, coincident with billing a contract termination charge (CTC)
to its retail affiliates, Montaup will commence depreciating its investment in
generation related assets recoverable through the CTC over a twelve-year
period.  Non-utility property and equipment of EUA Cogenex Corporation (EUA
Cogenex) is stated at original cost.  For financial statement purposes,
depreciation on office furniture and equipment, computer equipment and real
property is computed on the straight-line method based on estimated useful
lives ranging from five to forty years.  Project equipment is depreciated over
the term of the applicable contracts or based on the estimated useful lives,
whichever is shorter, ranging from five to fifteen years.

Other Assets:  The components of Other Assets at December 31, 1997 and 1996 are
detailed as follows:

($ in thousands)                              1997            1996
Regulatory Assets:
 Unamortized losses on reacquired debt   $   12,299      $   14,088
 Unrecovered plant and
  decommissioning costs                      68,345          41,914
 Deferred FAS 109 costs (Note B)             57,732          58,712
 Deferred FAS 106 costs                       3,310           4,054
 Mendon Road judgment (Note J)                6,154           6,154
 Other regulatory assets                     15,524           6,363
 Total regulatory assets                    163,364         131,285
Other deferred charges and assets:
  Split dollar life insurance premiums       15,502           7,699
  Unamortized debt expenses                   3,954           4,625
  Goodwill                                    6,642           6,848
  Other                                      23,045          25,085
     Total Other Assets                   $ 212,507       $ 175,542


Notes to Consolidated Financial Statements (continued)
December 31, 1997, 1996 and 1995

Regulatory Accounting:  EUA's Core Electric companies are subject to certain
accounting rules that are not applicable to other industries.  These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact of
certain costs that are expected to be recovered in future rates.  In light of
approved restructuring settlement agreements and restructuring legislation in
both Massachusetts and Rhode Island, EUA has determined that Montaup no longer
will apply the provisions of Financial Accounting Standards Board's (FASB)
Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting for the
Effects of Certain Types of Regulation" for the generation portion of its
business.  Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition.  EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.

Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest:
AFUDC represents the estimated cost of borrowed and equity funds used to
finance the EUA System's construction program.  In accordance with regulatory
accounting, AFUDC is capitalized as a cost of utility plant in the same manner
as certain general and administrative costs.  AFUDC is not an item of current
cash income but is recovered over the service life of utility plant in the form
of increased revenues collected as a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 8.0% in 1997, 9.0% in 1996 and
9.2% in 1995.  The caption "Allowance for Borrowed Funds Used During
Construction" also includes interest capitalized for non-regulated entities in
accordance with FASB Statement No. 34.

Operating Revenues:  Utility revenues are based on billing rates authorized by
applicable federal and state regulatory commissions.  Eastern Edison Company
(Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue
the estimated amount of unbilled revenues at the end of each month to match
costs and revenues more closely.  Montaup recognizes revenues when billed.  In
1998, Montaup and the Retail Subsidiaries also began accruing revenues
consistent with provisions of approved settlement agreements and enabling state
legislation.

EUA Cogenex's revenues are recognized based on financial arrangements
established by each individual contract.  Under paid-from-savings contracts,
revenues are recognized as energy savings are realized by customers.  Revenue
from the sale of energy savings projects and sales-type leases are recognized
when the sales are complete.  Interest on the financing portion of the
contracts is recognized as earned at rates established at the outset of the
financing arrangement.  All construction and installation costs are recognized
as contract expenses when the contract revenues are recorded.  In circumstances
in which material uncertainties exist as to contract profitability, cost
recovery accounting is followed and revenues received under such con tracts are
first accounted for as recovery of costs to the extent incurred.

Federal Income Taxes:  EUA and its subsidiaries generally reflect in income the
estimated amount of taxes currently payable, and provide for deferred taxes on
certain items subject to temporary timing differences to the extent permitted
by the various regulatory agencies.  EUA's rate-regulated subsidiaries
amortize previously deferred investment tax credits (ITC) over the productive
lives of the related assets.  Beginning in 1998, Montaup will amortize
previously deferred ITC related to generation investments recoverable through
the CTC over a twelve-year period.

Cash and Temporary Cash Investments:  EUA considers all highly liquid
investments and temporary cash investments with a maturity of three months or
less when acquired to be cash equivalents.

(B) Income Taxes:
EUA adopted FASB Statement No. 109, "Accounting for Income Taxes" (FAS109),
which requires recognition of deferred income taxes for temporary differences
that are reported in different years for financial reporting and tax purposes
using the liability method.  Under the liability method, deferred tax
liabilities or assets are computed using the tax rates that will be in effect
when temporary differences reverse.  Generally, for regulated companies, the
change in tax rates may not be immediately recognized in operating results
because of ratemaking treatment and provisions in the Tax Reform Act of 1986.
Total deferred tax assets and liabilities for 1997 and 1996 are comprised
as follows:

                       Deferred Tax                     Deferred Tax
                           Assets                       Liabilities
($ in thousands)        1997    1996                         1997    1996
Plant Related                          Plant Related
    Differences     $18,947  $19,816     Differences     $191,274   $190,155
Alternative                            Refinancing
     Minimum Tax                 852     Costs              1,406      1,623
NOL
     Carryforward     2,294    1,655   Pensions             1,500      1,313
Pensions              4,868    4,012
Acquisitions          3,650    3,965
Other                14,264    5,657     Other             13,236     12,042
  Total             $44,023  $35,957   Total             $207,416   $205,133

As of December 31, 1997 and 1996, EUA has recorded on its Consolidated Balance
Sheet a regulatory liability to ratepayers of approximately $18.8 million and
$21.2 million, respectively.  These amounts primarily represent excess deferred
income taxes resulting from the reduction in the federal income tax rate and
also include deferred taxes provided on investment tax credits.  Also at
December 31, 1997 and 1996, a regulatory asset of approximately $57.7 million
and $58.7 million, respectively, has been recorded, representing the cumulative
amount of federal income taxes on temporary depreciation differences which were
previously flowed through to ratepayers.


Notes to Consolidated Financial Statements (continued)
December 31, 1997, 1996 and 1995

Components of income tax expense for the year 1997, 1996, and 1995  are as
follows:

($ in thousands)                   1997         1996           1995
Federal:
   Current              $       17,249  $       (231)   $      10,335
   Deferred                     (4,901)         9,838           6,456
   Investment Tax Credit, Net   (1,120)        (1,125)         (1,130)
                                11,228          8,482          15,661
State:
   Current                       3,623          2,823           2,579
   Deferred                       (628)          (363)         (1,225)
                                 2,995          2,460           1,354
Charged to Operations           14,223         10,942          17,015
Charged to Other Income:
   Current                       9,142          4,798           4,353
   Deferred                       (789)         2,135          (6,217)
   Investment Tax Credit, Net      (81)           (82)            (82)
                                 8,272          6,851          (1,946)
Total Income Tax Expense  $     22,495  $      17,793   $      15,069

Total income tax expense was different from the amounts computed
by applying federal income tax statutory rates to book income subject
to tax for the following reasons:

($ in thousands)                                    1997       1996       1995
Federal Income Tax Computed at Statutory Rates  $ 21,966   $ 17,751  $  17,506
(Decrease) Increase in Tax from:
 Equity Component of AFUDC                           (57)      (189)      (187)
 Depreciation Differences                            (12)         2        118
 Amortization and Utilization of ITC              (1,201)    (1,207)    (1,212)
 State Taxes, Net of Federal Income Tax Benefit    2,092      1,952        (44)
 Other                                              (293)      (516)    (1,112)
Total Income Tax Expense                        $ 22,495   $ 17,793  $  15,069

(C) Capital Stock:
There was no change in the number of common shares outstanding during 1997.
The changes in the number of common shares outstanding and related increases in
Other Paid-In Capital during the years ended December 31, 1996, and 1995 were
as follows:

Number of Common Shares Issued
          Dividend         Highland
        Reinvestment and   Energy       Common           Other
        and Employee        Group       Shares           Paid-In
        Savings           Acquisition   At Par (000)    Capital (000)
1996       (767)                        $    (4)        $     4
1995    323,526             176,258       2,499           7,683

In October 1995, FASB issued Statement No. 123, "Accounting for Stock-Based
Compensation" (FAS123).  This Statement establishes a fair-value based method
of accounting for stock compensation plans.  As permitted, the Company accounts
for its stock-based compensation, as discussed below, using the method
prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees" (APB25).

The Company established a Restricted Stock Plan in 1989.  Under the Restricted
Stock Plan, executives and certain key employees may be granted restricted
common shares of the Company.  In 1997 and 1995, approximately 95,000 shares
and 61,000 shares, respectively, of restricted common shares, valued at
approximately $2.4 million and $1.4 million, respectively, were granted.
The shares issued are restricted for a period ranging from two to five years
and all shares are subject to forfeiture if specified employment services are
not met.  There are no exercise prices related to these share grants.  During
the applicable restriction period, the recipient has all the voting, dividend,
and other rights of a record holder except that the shares are nontransferable.
The annual compensation expense related to these grant awards was immaterial
for 1997, 1996, and 1995.  There are no material differences in the Company
recording its annual compensation expense under APB25 from the requirements
under FAS123.

The preferred stock provisions of the Retail Subsidiaries place certain
restrictions upon the payment of dividends on common stock by each company.
At December 31, 1997 and 1996, each company was in excess of the minimum
requirements which would make these restrictions effective.

In the event of involuntary liquidation, the holders of non-redeemable
preferred stock of the Retail Subsidiaries are entitled to $100 per share plus
accrued dividends.  In the event of voluntary liquidation, or if redeemed at
the option of these companies, each share of the non-redeemable preferred
stock is entitled to accrued dividends plus the following:

Company               Issue      Amount
Blackstone:     4.25% issue     $104.40
                5.60% issue      103.82
Newport:        3.75% issue      103.50

(D) Redeemable Preferred Stock:
Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003.  The redemption price is $100 per share plus accrued dividends.  All
outstanding shares of the 6 5/8% issue are subject to mandatory redemption on
September 1, 2008, at a price of $100 per share plus accrued dividends.  In the
event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred Stock
are entitled to $100 per share plus accrued dividends.

(E) Long-Term Debt:
The various mortgage bond issues of Blackstone, Eastern Edison, and Newport are
collateralized by substantially all of their utility plant.

In addition, Eastern Edison's bonds are collateralized by securities of
Montaup, which are wholly-owned by Eastern Edison, in the principal amount of
approximately $236 million.

Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable
Letter of Credit which expires on January 21, 1999.  The letter of credit
permits an extension of one year upon mutual agreement of the bank and
Blackstone.

Newport's Variable Rate Electric Energy Facilities Revenue Refunding Bonds are
collateralized by an irrevocable Letter of Credit which expires on January 6,
1999, and permits an extension of one year upon mutual agreement of the bank
and Newport.  EUA Service Corporation's (EUA Service) 10.2% Secured Notes due
2008 are collateralized by certain real estate and property of the company.

In September, EUA Cogenex used short-term borrowings to redeem $15 million of
7.22% Unsecured Notes at maturity.

The EUA System's aggregate amount of current cash sinking fund requirements and
maturities of long-term debt, (excluding amounts that may be satisfied by
available property additions) for each of the five years following 1997 are:
$72.5 million in 19 98, $21.9 million in 1999, $62.5 million in 2000, $14.3
million in 2001 and $45.5 million in 2002.

EUA Cogenex was not in compliance with the interest coverage covenant contained
in certain of its unsecured note agreements at December 31, 1997.  EUA Cogenex
has reached agreement with lenders to modify the interest coverage covenant
contained in these note agreements through January 1, 1999, and to waive the
default.  EUA Cogenex expects to be in compliance during 1998.

(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate:

Cash and Temporary Cash Investments:  The carrying amount approximates fair
value because of the short-term maturity of these instruments.

Long Term Notes Receivable and Net Investment in Sales-Type Leases:  The fair
value of these assets are based on market rates of similar securities.

Preferred Stock and Long-Term Debt of Subsidiaries:  The fair value of the
System's redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1997 and 1996.

The estimated fair values of the System's financial instruments at December 31,
1997 and 1996, were as follows:

                                    Carrying Amount            Fair Value
($ in thousands)                  1997         1996         1997       1996
Cash and Temporary
        Cash Investments     $    7,252   $  12,455     $  7,252    $ 12,455
Long-Term Notes Receivable
        and Net Investment
        in Sales-Type Leases     46,192      52,599       47,200      54,869
Redeemable Preferred Stock       30,000      30,000       31,613      30,300
Long-Term Debt                  405,829     434,447      429,035     450,419

(G) Lines Of Credit:
In July 1997, several EUA System companies entered into a three-year revolving
credit agreement allowing for borrowings in aggregate of up to $120 million.
As of December 31, 1997, various financial institutions have committed up to
$75 million under the revolving credit facility.  At December 31, 1997 under
the revolving credit agreement the EUA System had short-term borrowings
available of approximately $13.5 million.  During 1997, the weighted average
interest rate for short-term borrowings was 5.6%.

(H) Jointly Owned Facilities:
At December 31, 1997, in addition to the stock ownership interests discussed in
Note A, Nature of Operations and Summary of Significant Accounting Policies -
Jointly Owned Companies, Montaup and Newport had direct ownership interests in
the following electric generating facilities:
                                          Accumulated     Net
                               Utility    Provision for  Utility   Construction
                      Percent  Plant in   Depreciation   Plant in  Work in
($ in thousands)      Owned    Service   & Amortization  Service   Progress
Montaup:
   Canal Unit 2       50.00%  $  85,750       $ 44,498   $  41,252  $  227
   Wyman Unit 4        1.96%      4,054          2,253       1,801
   Seabrook Unit I     2.90%    194,679         34,400     160,279     325
   Millstone Unit 3    4.01%    178,918         54,844     124,074     285
Newport:
   Wyman Unit 4        0.67%      1,315            768         547

The foregoing amounts represent Montaup's and Newport's interest in each
facility, including nuclear fuel where appropriate, and are included on the
like-captioned lines on the Consolidated Balance Sheet.  At December 31, 1997,
Montaup's total net in vestment in nuclear fuel of the Seabrook and Millstone
Units amounted to $2.2 million and $1.8 million, respectively.

Montaup's and Newport's shares of related operating and maintenance expenses
with respect to units reflected in the preceding table are included in the
corresponding operating expenses.

(I) Financial Information By Business Segments:
The Core Electric Business includes results of the electric utility operations
of Blackstone, Eastern Edison, Newport and Montaup.

Energy Related Business includes results of our diversified energy-related
subsidiaries, EUA Cogenex, EUA Ocean State, EUA Energy Investment Corporation
(EUA Energy), EUA Energy Services and EUA Telecommunications.

Corporate results include the operations of EUA Service and EUA Parent.

<TABLE>
<CAPTION>
                         Pre-Tax                        Depreciation    Cash         Equity in
                         Operating    Operating  Income     and         Construction  Subsidiary
($ in thousands)         Revenues      Income    Taxes   Amortization   Expenditures  Earnings
<S>                     <C>            <C>       <C>     <C>            <C>           <C>

Year Ended
  December 31, 1997
    Core Electric       $  506,696   $ 78,795   $20,303     $36,069       $21,870      $  1,599
    Energy Related          61,817     (3,785)      547      10,858        51,941         7,867
    Corporate               (1,980)     1,645        14       2,307
        Total            $ 568,513   $ 73,030   $22,495     $46,941       $76,118      $  9,466
Year Ended
  December 31, 1996
    Core Electric       $ 470,719    $ 80,042   $21,039     $35,178       $ 33,337     $  1,587
    Energy Related         56,349     (11,536)   (3,888)     10,290         28,121        9,111
    Corporate              (1,723)        642        10       1,272
        Total           $ 527,068    $ 66,783   $17,793     $45,478       $ 62,730     $ 10,698
Year Ended
  December 31, 1995
    Core Electric       $ 483,864    $ 86,505   $20,724     $34,218       $ 31,466     $  1,646
    Energy Related         79,499       3,377    (5,658)     11,265         44,684       10,417
    Corporate              (1,139)          3         9       1,773
        Total           $ 563,363    $ 88,743   $15,069     $45,492       $ 77,923      $12,063

</TABLE>

Years ended December 31, ($ in thousands)          1997           1996
Total Plant and Other Investments
    Core Electric                           $   703,132     $   715,796
    Energy Related                              187,752         196,236
    Corporate                                    21,392          20,357
        Total Plant and Other Investments       912,276         932,389
Other Assets
    Core Electric                               257,888         232,443
    Energy Related                               73,109          66,212
    Corporate                                    27,479          25,985
        Total Other Assets                      358,476         324,640
Total Assets                                 $1,270,752      $1,257,029


(J) Commitments And Contingencies:
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs:
The owners (or lead participants) of the nuclear units in which Montaup has
an interest have made, or expect to make, various arrangements for the
acquisition of uranium concentrate, the conversion, enrichment, fabrication and
utilization of nuclear fuel and the disposition of that fuel after use.  The
owners (or lead participants) of United States nuclear units have entered into
contracts with the Department of Energy (DOE) for disposal of spent nuclear
fuel in accordance with the Nuclear Waste Policy Act of 1982 (NWPA).  The NWPA
requires (subject to various contingencies) that the federal government design,
license, construct and operate a permanent repository for high level
radioactive wastes and spent nuclear fuel and establish a prescribed fee for
the disposal of such wastes and nuclear fuel.  The NWPA specifies that the DOE
provide for the disposal of such waste and spent nuclear fuel starting in 1998.
Objections on environmental and other grounds have been asserted against
proposals for storage as well as disposal of spent nuclear fuel.  The DOE now
estimates that a permanent disposal site for spent fuel will not be ready to
accept fuel for storage or disposal until as late as the year 2010.  In early
1998 a number of utilities filed suit in federal appeals court seeking, among
other things, an order requiring the DOE to immediately establish a program for
the disposal of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone
3 and a 2.9% interest in Seabrook I.  Northeast Utilities, the operator of the
units, indicates that Millstone 3 has sufficient on-site storage facilities
which, with rack additions, can accommodate its spent fuel for the projected
life of the unit.  At the Seabrook Project, there is on-site storage capacity
which, with rack additions, will be sufficient to at least the year 2011.

The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest.  These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through rates.

Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I.  Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $21.9 million in
1997 dollars, and Seabrook I is $13.7 million in 1997 dollars.  These figures
are based on studies performed for the lead owners of the units.  Montaup also
pays into decommissioning reserves pursuant to contractual arrangements with
other nuclear generating facilities in which it has an equity ownership
interest or life of the unit entitlement.  Such expenses are currently
recoverable through rates.

Pensions:  EUA maintains a noncontributory defined benefit pension plan
covering most of the employees of the EUA System (Retirement Plan).  Retirement
Plan benefits are based on years of service and average compensation over the
four years prior to retirement.  It is the EUA System's policy to fund the
Retirement Plan on a current basis in amounts determined to meet the funding
standards established by the Employee Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1997 and 1995 voluntary retirement incentive offers, for 1997,
1996 and 1995 included the following components:

($ in thousands)                     1997            1996            1995
Service cost-benefits earned
        during the period       $   2,816       $   3,126       $   2,776
Interest cost on projected
        benefit obligations        10,116           9,765           9,391
Actual (return) on assets         (29,898)        (16,451)        (36,220)
Net amortization and deferrals     16,347           4,060          24,392
Net periodic pension
        (income) expense             (619)            500             339
Voluntary Retirement Incentive                                      1,653
Subsidiary curtailment               (131)
Total periodic pension
        (income) expense        $    (750)     $      500       $   1,992

Assumptions used to determine pension costs:
Discount Rate                        7.50%           7.25%           8.25%
Compensation Increase Rate           4.25%           4.25%           4.75%
Long-Term Return on Assets           9.50%           9.50%           9.50%

The following table sets forth the actuarial present value of benefit
obligations and funded status at December 31, 1997, 1996 and 1995:

($ in thousands)                      1997            1996         1995
Accumulated benefit obligations
Vested                             $ (126,302)     $ (118,739)     $(117,060)
Non-vested                               (266)           (254)          (271)
Total                              $ (126,568)     $ (118,993)     $ (117,331)
Projected benefit obligations      $ (144,915)     $ (136,286)     $ (135,415)
Plan assets at fair value,
        primarily stocks and bonds    182,795         161,300         152,308
Unrecognized net (gain)               (41,399)        (29,963)        (21,769)
Unamortized net assets at January 1     3,832           4,513           4,939
Net pension assets (liability)     $      313      $     (436)     $       63

The discount rate used to determine pension obligations, effective January 1,
1998 was changed to 7.25% and was used to calculate the plan's funded status at
December 31, 1997.

The voluntary retirement incentives also resulted in $1.3 million and $1.6
million of non-qualified pension benefits which were expensed in 1997 and 1995.
At December 31, 1997, approximately $2.6 million was included in other
liabilities for these unfunded benefits.

EUA also maintains non-qualified supplemental retirement plans for certain
officers and trustees of the EUA System (Supplemental Plans).  Benefits
provided under the Supplemental Plans are based primarily on compensation at
retirement date.  EUA maintains life insurance on certain participants of the
Supplemental Plans to fund in whole, or in part, its future liabilities under
the Supplemental Plans.  As of December 31, 1997, approximately $5.7 million
was included in accrued expenses and other liabilities for these plans.
Expenses related to the Supplemental Plans were $1.9 million in 1997, and $1.5
million in both 1996 and 1995.  EUA also provides a defined contribution 401(k)
savings plan for substantially all employees.  EUA's matching percentage of
employees' voluntary contributions to the plan, amounted to $1.5 million in
1997, $1.3 million in 1996, and $1.4 million in 1995.

Post-Retirement Benefits:  Retired employees are entitled to participate in
health care and life insurance benefit plans.  Health care benefits are subject
to deductibles and other limitations.  Health care and life insurance benefits
are partially funded by EUA System companies for all qualified employees.

The EUA System adopted Statement of Financial Accounting Standard No. 106,
"Accounting for Post-Retirement Benefits Other Than Pensions," (FAS106) as of
January 1, 1993.  This standard establishes accounting and reporting standards
for such post-retirement benefits as health care and life insurance.  Under
FAS106 the present value of future benefits is recorded as a periodic expense
over employee service periods through the date they become fully eligible for
benefits.  With respect to periods prior to adopting FAS106, EUA elected to
recognize accrued costs (the Transition Obligation) over a period of 20 years,
as permitted by FAS106.  The resultant annual expense, including amortization
of the Transition Obligation and net of capitalized and deferred amounts, was
approximately $6.1 million in 1997, $6.1 million in 1996, and $6.3 million in
1995.

The total cost of post-retirement benefits other than pensions, including
amounts related to the 1997 and 1995 voluntary retirement incentive offers,
for 1997, 1996 and 1995 includes the following components:


($ in thousands)                            1997           1996          1995
Service cost                          $       949     $   1,123     $     996
Interest cost                               4,434         4,449         4,822
Actual (return) on plan assets             (1,433)         (253)         (671)
Amortization of transition obligation       3,289         3,313         3,312
Other amortizations & deferrals - net        (663)       (1,211)         (970)
Net periodic post-retirement benefit cost   6,576         7,421         7,489
Voluntary Retirement Incentives               172                         832
Subsidiary curtailment                       (548)
Total periodic post-retirement
        benefit costs                  $    6,200     $   7,421     $   8,321

Assumptions used to determine post-retirement benefit costs
        Discount rate                        7.50%         7.25%         8.25%
        Health care cost trend rate
                - near-term                  7.00%         9.00%        11.00%
                - long-term                  5.00%         5.00%         5.00%
        Compensation increase rate           4.25%         4.25%         4.75%
        Long-term return on assets
                - union                      8.75%         8.50%         8.50%
                - non-union                  7.75%         7.50%         5.50%

Reconciliation of funded status:
($ in thousands)                              1997          1996          1995
Accumulated post-retirement
        benefit obligation (APBO):
        Retirees                         $(38,701)     $(36,518)     $(40,817)
        Active employees fully
                eligible for benefits      (6,753)       (5,952)       (9,760)
        Other active employees            (19,372)      (19,652)      (20,115)
Total                                    $(64,826)     $(62,122)     $(70,692)

Plan assets at fair value, primarily
        notes and bonds                    23,729        17,743        12,614
Unrecognized transition obligation         49,335        53,001        56,314
Unrecognized net loss (gain)              (16,233)      (17,551)       (7,575)
(Accrued)/prepaid post-retirement
        benefit cost                    $  (7,995)     $ (8,929)     $ (9,339)

The discount rate used to determine post-retirement benefit obligations
effective January 1, 1998 was changed to 7.25% and was used to calculate the
funded status of post-retirement benefits at December 31, 1997.

Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1997 by $800,000 and
increase the total accumulated post-retirement benefit obligation by $7.2
million.

The EUA System has also established separate irrevocable external Voluntary
Employees' Beneficiary Association Trust Funds for union and non-union
retirees.  Contributions to the funds commenced in March 1993 and totaled
approximately $7.1 million in 1997, $7.8 million in 1996 and $7.1 million
during 1995.

Long-Term Purchased Power Contracts:  The EUA System is committed under long-
term purchased power contracts, expiring on various dates through September
2021, to pay demand charges whether or not energy is received.  Under terms in
effect at December 31, 1997, the aggregate annual minimum commitments for such
contracts are approximately $114 million in 1998, $110 million in 1999, $107
million in 2000, $108 million in 2001, $108 million in 2002, and will aggregate
$1.0 billion for the ensuing years.  In addition, the EUA System is required to
pay additional amounts depending on the actual amount of energy received under
such contracts.  The demand costs associated with these contracts are reflected
as Purchased Power-Demand on the Consolidated Statement of Income.  Such costs
are currently recoverable through rates.

Environmental Matters:  There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities.  The EUA System generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs.  Subsidiaries
of EUA have been notified with respect to a number of sites where they may be
responsible for such costs, including sites where they may have joint and
several liability with other responsible parties.  It is the policy of the EUA
System companies to notify liability insurers and to initiate claims.  EUA is
unable to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carriers in these matters.

On December 13, 1994, the United States District Court for the District of
Massachusetts (District Court) issued a judgment against Blackstone, finding
Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the
full amount of response costs incurred by the Commonwealth in the cleanup of a
by-product of manufactured gas at a site at Mendon Road in Attleboro,
Massachusetts.  The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment.  The total liability is
approximately $5.9 million, including approximately $3.6 million in interest
which has accumulated since 1985.  Due to the uncertainty of the ultimate
outcome of this proceeding and anticipated recoverability, Blacks tone recorded
the $5.9 million District Court judgment as a deferred debit.  This amount is
included with Other Assets on the Consolidated Balance Sheet at December 31,
1997 and 1996.

Blackstone filed a Notice of Appeal of the District Court's judgment and filed
its brief with the United States Court of Appeals for the First Circuit (First
Circuit) on February 24, 1995.  On October 6, 1995, the First Circuit vacated
the District Court's judgment and ordered the District Court to refer the
matter to the EPA to determine whether the chemical substance, ferric
ferrocyanide (FFC), contained within the by-product is a hazardous substance.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account.  The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment.  No additional interest expense will accrue
on the judgment amount.

On January 28, 1994, Blackstone filed a complaint in the District Court,
seeking, among other relief, contribution and reimbursement from Stone &
Webster Inc., of New York City and several of its affiliated companies (Stone &
Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any
damages incurred by Blackstone regarding the Mendon Road site.  On November 7,
1994, the Court denied motions to dismiss the complaint which were filed by
Stone & Webster and Valley.  This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance.

In addition, Blackstone has notified certain liability insurers and has filed
claims with respect to the Mendon Road site, as well as other sites.
Blackstone reached settlement with one carrier for reimbursement of legal costs
related to the Mendon Road case.  In January 1996, Blackstone received the
proceeds of the settlement.

As of December 31, 1997, the EUA System had incurred costs of approximately
$6.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with the investigation and clean-up of these sites, substantially all of which
relate to Blackstone.  These amounts have been financed primarily by internally
generated cash.  Blackstone is currently amortizing all of its incurred costs
over a five-year period consistent with prior regulatory recovery periods and
is recovering certain of those costs in rates.

EUA estimates that additional costs of up to $1.3 million (excluding the $5.9
million Mendon Road judgment) may be incurred at these sites through 1998,
substantially all of which relates to sites at which Blackstone is a
potentially responsible part y.  Estimates beyond 1998 cannot be made since
site studies, which are the basis of these estimates, have not been completed.
As a result of the recoverability of cleanup costs in rates and the uncertainty
regarding both its estimated liability, as well as its potential contributions
from insurance carriers and other responsible parties, EUA does not believe
that the ultimate impact of the environmental costs will be material to the
financial position of the EUA System or to any individual subsidiary and thus
no loss provision is required at this time.

The Clean Air Act Amendments created new regulatory programs and generally
updated and strengthened air pollution control laws.  These amendments expanded
the regulatory role of the EPA regarding emissions from electric generating
facilities and a host of other sources.  EUA System generating facilities were
first affected in 1995, when EPA regulations took effect for facilities owned
by the EUA System.  Montaup's coal-fired Somerset Unit 6 is utilizing lower
sulfur content coal to meet the 1995 air standards.  EUA does not anticipate
the impact from the Amendments to be material to the financial position of the
EUA System.

In July 1997, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards.  The effect that such standards will
have on the EUA System cannot be determined by management at this time.

Eastern Edison, Montaup, the Massachusetts Attorney General and Division of
Energy Resources entered into a settlement regarding electric utility industry
restructuring in Massachusetts.  The settlement includes a plan for emissions
reductions relate d to Montaup's Somerset Station Units 5 and 6, and to
Montaup's 50% ownership share of Canal Electric's Unit 2.  The basis for SO2
and NOx emission reductions in the proposed settlement is an allowance cap
calculation.  Montaup may meet its allowance caps by any combination of control
technologies, fuel switching, operational changes, and/or the use of purchased
or surplus allowances.  The settlement was approved by FERC on December 19,
1997.

In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight northeast states including
Massachusetts and Rhode Island, issued recommendations for NOx controls for
existing utility boiler s required to meet the ozone non-attainment
requirements of the Clean Air Act.  The NESCAUM recommendations are more
restrictive than the Clean Air Act requirements.  The Massachusetts Department
of Environmental Management has amended its regulation s to require that
Reasonably Available Control Technology (RACT) be implemented at all stationary
sources potentially emitting 50 tons or more per year of NOx.  Similar
regulations have been issued in Rhode Island.  Montaup has initiated
compliance, through, among other things, selective noncatalytic reduction
processes.

A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity.  While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association.  On October 31, 1996, the National Academy of Sciences issued a
literature review of all research to date, Possible Health Effects of Exposure
to Residential Electric and Magnetic Fields.  Its most widely reported
conclusion stated,  "No clear, convincing evidence exists to show that
residential exposures to EMF are a threat to human health." Additional studies,
which are intended to provide a better understanding of EMF, are continuing.

Some states have enacted regulations to limit the strength of magnetic fields
at the edge of transmission line rights-of-way.  Rhode Island has enacted a
statute which authorizes and directs the Energy Facility Siting Board to
establish rules and regulations governing construction of high voltage
transmission lines of 69 kv or more.  Management cannot predict the ultimate
outcome of the EMF issue.

Guarantee of Financial Obligations:  EUA has guaranteed or entered into equity
maintenance agreements in connection with certain obligations of its
subsidiaries.  EUA has guaranteed the repayment of EUA Cogenex's $28.0 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $28.6 million,
9.59% unsecured long-term notes due 2011.  In addition, EUA has entered into
equity maintenance agreements in connection with the issuance of EUA Service's
10.2% Secured Notes and EUA Cogenex's 9.6% Unsecured Notes.  Under the December
1992 settlement agreement with EUA Power, EUA reaffirmed its guarantee of up to
$10 million of EUA Power's share of the decommissioning costs of Seabrook I and
any costs of cancellation of Seabrook I or Seabrook II.  EUA guaranteed this
obligation in 1990 in order to secure the release to EUA Power of a $10 million
fund established by EUA Power at the time EUA Power acquired its Seabrook
interest.  EUA has not provided a reserve for this guarantee because management
believes it unlikely that EUA will ever be required to honor the guarantee.

Montaup is a 3.27% equity participant in two companies which own and operate
transmission facilities interconnecting New England and the Hydro Quebec system
in Canada.  Montaup has guaranteed approximately $4.5 million of the
outstanding debt of these two companies.  In addition, Montaup and Newport have
minimum rental commitments which total approximately $12 million and $1.5
million, respectively under a noncancelable transmission facilities support
agreement for years subsequent to 1997.

Other:  In the fourth quarter of 1996 EUA Cogenex was notified by
Ridgewood/Mass.  Corporation that it intended to seek damages related to
certain claims and alleged misrepresentations by EUA Cogenex regarding the sale
of its cogeneration portfolio.  As part of the "Agreement for Assignment for
Beneficial Interests," Ridgewood exercised these rights under the mandatory
arbitration clause contained within said agreement.  A date has not been
determined for the arbitration proceedings at this time.  EUA Cogenex has filed
a counter-claim against Ridgewood for its failure to pay for certain
transitional expenses as stipulated in the "Assignment Agreement." In 1997, the
American Arbitration Association set a preliminary hearing date of June 14,
1998.  Management cannot determine at this time the ultimate outcome of these
proceedings.

On January 10, 1997, the Internal Revenue Service (IRS) issued a report in
connection with its examination of the consolidated income tax returns of EUA
for 1992 and 1993.  The report includes an adjustment to disallow EUA's
inclusion of its investment in EUA Power's Preferred Stock as a deduction in
determining Excess Loss Account (ELA) taxable income relating to the redemption
of EUA Power's Common and Preferred Stock in 1993.  The IRS has taken the
position that the redemption of the Preferred Stock resulted in a capital loss
transaction and not a deduction in determining ELA.  The Company disagrees with
the IRS's position and filed a protest in March 1997.  On February 24, 1998,
EUA met with an IRS appeals officer to discuss resolution of this matter and
awaits a decision.  EUA believes that it will ultimately prevail in this
matter.  However, if the ultimate resolution of this matter is a favorable
decision for the IRS and EUA has not generated sufficient capital gain
transactions to offset the capital loss then EUA would be required to record a
charge that could have a material impact on financial results in the year of
the charge but would not materially impact the financial position of the
company.

In early 1997, ten plaintiffs brought suit against numerous defendants,
including EUA, for injuries and illness allegedly caused by exposure to
asbestos over approximately a thirty-year period, at premises, including some
owned by EUA companies.  The total damages claimed in all of these complaints
was $25 million in compensatory and punitive damages, plus exemplary damages an
d interest  and costs.  Each complaint names between fifteen and twenty-eight
defendants, including EUA.  These complaints have been referred to the
applicable insurance companies.  Counsel has been retained by the insurers and
is actively defending all cases.  Three cases have been dismissed as against
the EUA Companies, with prejudice.  EUA cannot predict the ultimate outcome of
this matter at this time.

The Office of the Attorney General has certified a referendum petition to
repeal the Massachusetts Electric Industry Restructuring Act as a matter
appropriate for a referendum initiative.  A petition was filed with the
Election Division of the Office of the Secretary of State in February 1998.  A
question on repealing the Act will be presented to voters on the November 1998
ballot.  EUA and the electric industry in Massachusetts will actively oppose
repeal.  Management cannot predict the outcome of the November ballot question.

Report of Independent Accountants

To the Trustees and Shareholders of Eastern Utilities Associates

We have audited the accompanying consolidated balance sheets and consolidated
statements of equity capital and preferred stock and indebtedness of Eastern
Utilities Associates and subsidiaries (the Company) as of December 31, 1997 and
1996, and the r elated consolidated statements of income, retained earnings and
cash flows 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 ex press 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 consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of the
Company as of December 31, 1997 and 1996, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.



/s/Coopers & Lybrand L.L.P.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998




Report of Management

The management of Eastern Utilities Associates is responsible for the
consolidated financial statements and related information included in this
annual report.  The financial statements are prepared in accordance with
generally accepted accounting principles and include amounts based on the best
estimates and judgments of management, giving appropriate consideration to
materiality.  Financial information included elsewhere in this annual report is
consistent with the financial statements.

The EUA System maintains an accounting system and related internal controls
which are designed to provide reasonable assurances as to the reliability of
financial records and the protection of assets.  The System's staff of internal
auditors conducts reviews to maintain the effectiveness of internal control
procedures.

Coopers & Lybrand L.L.P., an independent accounting firm, is engaged by EUA to
audit and express an opinion on our financial statements.  Their audit includes
a review of internal controls to the extent required by generally accepted
auditing standards for such audit.

The Audit Committee of the Board of Trustees, which consists solely of outside
Trustees, meets with management, internal auditors and Coopers & Lybrand L.L.P.
to discuss auditing, internal controls and financial reporting matters.  The
internal audit ors and Coopers & Lybrand L.L.P. have free access to the Audit
Committee without management present.

<TABLE>

Quarterly Financial and Common Share Information (unaudited)

($ in thousands except per Share and Share Price Amounts)

<CAPTION>
                                                                          Earnings per  Dividends     Common Share
                                                          Consolidated    Average Paid  per           Market Price
                        Operating    Operating    Net        Net          Common        Common
                        Revenues     Income      Income    Earnings       Share         Share         High      Low
<S>                     <C>          <C>         <C>       <C>            <C>           <C>           <C>       <C>

FOR THE QUARTERS
ENDED 1997:
 December 31            $ 145,878   $ 15,378     $11,158     $10,582       $ 0.52       $ 0.415      26  5/8  20 1/8
 September 30             142,026     15,896      11,542      10,966         0.54         0.415      19 15/16 18 7/16
 June 30                  138,856     11,327       6,510       5,933         0.29         0.415      18  1/2  16 3/8
 March 31                 141,753     16,206      11,055      10,479         0.51         0.415      19  5/8  17 1/4

FOR THE QUARTERS
ENDED 1996:
  December 31           $ 138,407   $ 14,208      $ 8,312    $ 7,735       $ 0.38       $ 0.415      17 1/2   16
  September 30            131,076     13,328        9,389      8,811         0.43         0.415      19 1/2   14 3/4
  June 30                 122,785     10,024        3,299      2,720         0.13         0.415      21 7/8   18 1/2
  March 31                134,800     18,281       11,926     11,348         0.56         0.40       24 1/4   20 5/8
</TABLE>

<TABLE>
Consolidated Operating and Financial Statistics
<CAPTION>

Years Ended December 31,                 1997      1996      1995       1994      1993      1992      1987
<S>                                      <C>      <C>       <C>        <C>        <C>      <C>        <C>

ENERGY GENERATED
AND PURCHASED (millions of kWh):
 Generated
   - by Somerset Station                 845        719        679        658       319       936     1,294
   - by Nuclear Units                    570        977        752      1,008     1,033     1,050       390
   - by Jointly-Owned Units            1,350        848      1,410      1,615     1,809     2,105     2,050
   - by Life of the Unit Contracts       805        526        236        648       602       793       569
   - by Newport                                                                                 1         1
 Interchange with NEPOOL                 372        381        573        295       360       157       236
 Purchased Power - Unit Power          1,514      1,765      1,463      1,526     1,396     1,489       207
   Total Generated and Purchased       5,456      5,216      5,113      5,750     5,520     6,531     4,746
OPERATING REVENUES
($ in thousands):
    Residential                    $ 203,315  $ 192,569  $ 193,233  $ 190,662 $ 189,470 $ 176,538 $ 124,047
    Commercial                       168,680    164,096    169,841    169,241   179,145   170,034   114,857
    Industrial                        82,587     80,417     83,061     81,500    81,445    76,946    72,218
    Other Electric Utilities           6,035      5,411      5,447      4,900     5,098     5,103    18,740
    Other                             25,574     14,281     17,482     17,282    21,790    21,314    11,192
      Total Primary Sales Revenues   486,191    456,774    469,064    463,585   476,948   449,935   341,054
        Unit Contracts                20,505     13,945     14,800     26,213    22,617    47,875    23,372
        Non-Electric                  61,817     56,349     79,499     74,480    66,912    44,154     2,703
      Total Operating Revenues     $ 568,513  $ 527,068  $ 563,363  $ 564,278 $ 566,477 $ 541,964 $ 367,129
ENERGY SALES (millions of kWh):
        Residential                    1,783      1,740      1,697      1,678     1,624     1,575     1,328
        Commercial                     1,653      1,665      1,674      1,671     1,704     1,704     1,325
        Industrial                       889        868        867        850       816       785       863
        Other Electric Utilities          79         86         75         74        61        68       365
        Other                            142        132        128         137      147       147        28
        Total Primary Sales            4,546      4,491      4,441       4,410    4,352     4,279     3,909
   Losses and Company Use                219        208        227         233      247       241       231
        Total System Requirements      4,765      4,699      4,668       4,643    4,599     4,520     4,140
        Unit Contracts                   691        517        445       1,107      921     2,011       606
                Total Energy Sales     5,456      5,216      5,113       5,750    5,520     6,531     4,746
NUMBER OF CUSTOMERS:
        Residential                  272,608    270,319    268,203     263,054  259,654   257,026   221,480
        Commercial                    27,599     27,331     27,401      29,004   30,805    32,851    25,480
        Industrial                    1,810       1,779      1,685       1,603    1,294     1,197     1,237
        Other Electric Utilities          8           8          8          12       12        15         7
        Other                            34          34         34          34       34        34        29
                Total Customers     302,059     299,471    297,331     293,707  291,799   291,123   248,233
Average Annual Revenue
        per Residential Customer ($)    746         712        720         725      730       687       560
Average Annual Use per Residential
        Customer (kWh)                6,540       6,437      6,327       6,379    6,254     6,128     5,996
AVERAGE REVENUE
PER KWH (cent):
        Residential                   11.40       11.06      11.39       11.36    11.67     11.21      9.34
        Commercial                    10.20        9.86      10.15       10.13    10.51      9.98      8.67
        Industrial                     9.29        9.26       9.58        9.59     9.98      9.80      8.37

</TABLE>
<TABLE>
Consolidated Operating and Financial Statistics
<CAPTION>

Years Ended December 31,                    1997         1996        1995       1994         1993        1992       1987
<S>                                        <C>          <C>         <C>          <C>        <C>         <C>         <C>

CAPITALIZATION ($ in thousands):
   Bonds - Net                       $   215,252  $    277,313  $   279,374 $   288,449  $  300,389 $  306,898 $  267,500
   Other Long-Term Debt - Net            117,550       129,024      155,497     166,963     196,427    156,060    211,717
           Total Long-Term Debt - Net    332,802       406,337      434,871     455,412     496,816    462,958    479,217
        Preferred Stock - Net             34,512        33,935       33,155      32,290      31,953     44,346     44,931
                Common Equity            373,467       371,813      375,229     365,443     333,165    266,855    285,383
                Total Capitalization $   740,781   $   812,085  $   843,255 $   853,145 $   861,934 $  774,159 $  809,531
CAPITALIZATION RATIOS (%):
  Long-Term Debt                              45            50           52          53          57         60         59
  Preferred Stock                              5             4            4           4           4          6          6
  Common Equity                               50            46           44          43          39         34         35
COMMON SHARE DATA:
  Earnings per Average
          Common Share ($)                  1.86          1.50         1.61        2.41        2.44       2.00       3.46
  Dividends per Share ($)                   1.66         1.645        1.585       1.515        1.42       1.36       2.27
  Payout (%)                                89.2         109.7         98.4        62.9        58.2       68.0       65.6
  Average Common
          Shares Outstanding          20,435,997    20,436,217   20,238,961  19,671,970  18,391,147 17,039,224 12,596,381
  Total Common Shares
          Outstanding                 20,435,997    20,435,997   20,436,764  19,936,980  19,032,598 17,237,788 12,966,062
  Book Value per Share ($)                 18.27         18.19        18.36       18.33       17.50      15.48      22.01
  Percent Earned On Average
          Common Equity                     10.2           8.2          8.8        13.6        15.0       13.2       17.1
  Market Price ($):
          High                                26 5/8        24 1/4       25          27 3/8      29 7/8     25 1/4     40 1/2
          Low                                 16 3/8        14 3/4       21 1/2      21 3/8      23 7/8     20 3/8     24
          Year End                            26 1/4        17 3/8       23 5/8      22          28         24 3/4     28
Miscellaneous ($ in thousands):
  Total Construction Expenditures ($)         76,280    63,182       78,461      50,870      76,770     71,914    126,856
  Cash Construction Expenditures ($)          76,118    62,730       77,923      50,519      76,391     71,365     68,929
  Internally Generated Funds ($)              85,637    77,545       90,883      79,274      79,691     48,933     14,554
  Internally Generated Funds as
          a % of Cash Construction (%)         112.5     123.6        116.6       156.9       104.3       68.6       21.1
  Installed Capability - mw                    1,075<F1> 1,208        1,191       1,212       1,256<F2>  1,325      1,091
  Less: Unit Contract Sales - mw                  35        60           35          85          85         85        108
  System Capability - mw                       1,040     1,148        1,156       1,127       1,171      1,240        983
  System Peak Demand - mw                        933       854          931         921         854        849        782
  Reserve Margin (%)                            11.5      34.4         24.2        22.4        37.1       46.1       25.8
  System Load Factor (%)                        58.3      62.6         57.2        57.5        61.5       57.5       60.4
  Sources of Energy (%):
                Nuclear                         17.0      29.0         28.2        33.8        34.0       34.1       15.1
                Coal                            17.9      14.7         14.7        11.7        5.4        18.6       31.1
                Oil                             31.2      19.8         25.5        20.0        28.3       12.7       53.8
                Gas                             28.2      30.8         26.5        28.4        26.0       29.3
                Other                           5.7       5.7          5.1         6.1         6.3        5.3
  Cost of Fuel (Mills per kWh):
                Nuclear                          5.7       5.0          6.3         6.1         7.5        7.7        9.2
                Coal                            18.6      19.6         20.3        20.9        24.1       21.2       20.5
                Oil                             31.0      37.7         30.2        27.1        25.5       26.0       28.3
                Gas                             16.4      14.4         14.3        14.1        15.1       13.0
                All Fuels Combined              19.2      16.7         16.7        14.5        15.5       14.8       23.0
<FN>
<F1> Due to the extended outage of the Milestone 3 Nuclear Unit, our 46 mw
     ownership share was not included in installed capability.
<F2> Excludes the 69 mw Somerset Station Unit #5 which was placed in
     deactivated reserve on January 25, 1994.
</FN>

</TABLE>

Shareholder Information

Shares of Eastern Utilities Associates are listed on the New York and Pacific
Stock Exchanges, under the ticker symbol EUA.  As of February 1, 1998, there
were 11,130 common shareholders of record.

Form 10-K
A copy of EUA's 1997 Annual Report on Form 10K filed with the Securities and
Exchange Commission is available to shareholders without charge by writing to
us.

Annual Meeting
The 1998 Annual Meeting of Shareholders will be held on
Monday, May 18, 1998, at 9:30 a.m., in the
Enterprise Room, 5th Floor
State Street Bank and Trust Company
225 Franklin Street
Boston, Massachusetts

Registrar, Transfer Agent and Dividend Disbursing Agent for Common and
Preferred Shares

Investor Relations
The First National Bank of Boston
c/o Boston EquiServe
P.O. Box 8040
Boston, MA 02266-8040
1-800-736-3001 (Toll-Free)

Lost or Stolen Stock Certificates
If your stock certificate is lost, destroyed or stolen, you should notify the
transfer agent immediately so a "stop transfer" order can be placed on the
missing certificate.  The transfer agent then will send you the required
documents to obtain a re placement certificate.

Dividends
Schedule of anticipated record and payment dates for 1998 dividends on EUA
Common Shares:

Record          Payment
January 30      February 17
May 1           May 15
July 31         August 15
November 2      November 16

Direct Deposit Plan
EUA Shareholders have the option of having their EUA dividends deposited
directly into their bank accounts.  If you wish to participate, contact EUA
investor relations at 1-800-736-3001 (Toll-Free).

Replacement of Dividend Checks
If you do not receive your dividend check within ten business days after the
dividend payment date, or if your check is lost, destroyed or stolen, you
should notify the disbursing agent in writing for a replacement.

Dividend Reinvestment and Common
Share Purchase Plan

A Dividend Reinvestment and Common Share Purchase Plan is available to all
registered shareholders and EUA System company employees.  It is a simple and
convenient method of purchasing additional shares of EUA common stock.
Participants also may make cash payments to purchase additional shares.  You
may obtain complete details by writing to Clifford J. Hebert Jr., Vice
President - Finance & Treasurer at the address shown below under "Financial
Community Inquiries."

Duplicate Mailings
Duplicate mailings are costly.  Shareholders may be receiving duplicate copies
of annual and quarterly reports due to multiple stock accounts in the same
household.  To eliminate additional mailings of these reports, please write to
us and enclose label(s) or label information from the duplicate reports.
Dividend checks and proxy material will continue to be sent for each account on
record.

EUA is required by law to create a separate account for each name when stock is
held in similar but different names (e.g., John A. Smith, J. A. Smith, John A.
and Mary K. Smith, etc.).  Please contact the Company for instructions if you
wish to consolidate multiple accounts.

Financial Community Inquiries
Institutional investors and securities analysts should direct
inquiries to:
Clifford J. Hebert, Jr., Vice President - Finance & Treasurer
EUA Service Corporation
Post Office Box 2333
Boston, MA 02107
(617) 357-9590

The name Eastern Utilities Associates is the designation of the Trustees for
the time being under a Declaration of Trust dated April 2, 1928, as amended.
All persons dealing with Eastern Utilities Associates must look solely to the
trust property for the enforcement of any claims against Eastern Utilities
Associates, as neither the Trustees, Officers nor Shareholders assume any
personal liability for obligations entered into on behalf of Eastern Utilities
Associates.

Internet Address
Visit EUA's Home Page on the World Wide Web at:
http://www.eua.com

"Picture of a Customer with a note " "Every customer, every employee,
every shareholder at Eastern Utilities makes a difference...""

EUA System Officers

Trustees


Russell A. Boss (A, P)
President and Chief Executive Officer
A. T. Cross Company
Lincoln, Rhode Island

Paul J. Choquette, Jr. (C, F)
Chairman and Chief Executive Officer
Gilbane Building Company
Providence, Rhode Island

Peter S. Damon (A, P)
President and Chief Executive Officer
Bank of Newport
Newport, Rhode Island

Peter B. Freeman (F, P)
Corporate Director and Trustee
Providence, Rhode Island

Larry A. Liebenow (A, C)
President and Chief Executive Officer
Quaker Fabric Corporation
Fall River, Massachusetts

Jacek Makowski (F, P)
Chairman, Poseidon Resources Corporation
Stamford, Connecticut

Wesley W. Marple, Jr. (A, C)
Professor of Business Administration
Northeastern University
Boston, Massachusetts

Donald G. Pardus
Chairman of the Board of Trustees and
Chief Executive Officer of the Association

Margaret M. Stapleton (A, F)
Vice President
John Hancock Mutual Life Insurance Company
Boston, Massachusetts

John R. Stevens
President and Chief Operating Officer of the Association

W. Nicholas Thorndike (C, F)
Corporate Director and Trustee
Brookline, Massachusetts


A  Indicates member of Audit Committee
C  Indicates member of Compensation and Nominating Committee
F  Indicates member of Finance Committee
P  Indicates member of Pension Trust Committee

Donald G. Pardus
Chairman of the Board of Trustees and
Chief Executive Officer

John R. Stevens
President and Chief Operating Officer

John D. Carney
Executive Vice President

Robert G. Powderly
Executive Vice President

Clifford J. Hebert, Jr.
Treasurer and Secretary

Donald T. Sena
Assistant Treasurer