UNITED STATES
  SECURITIES AND EXCHANGE COMMISSION
   Washington, D.C.  20549

          FORM 10-Q

 (Mark one)

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

    For the quarterly period ended                    March 31, 1997
                                 OR

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

    For the transition period _________________ to ___________________

    Commission File Number                                1-5366



EASTERN UTILITIES ASSOCIATES
       (Exact name of registrant as specified in its charter)


          Massachusetts                                 04-1271872
      (State or other jurisdiction of                 (I.R.S. Employer
      incorporation or organization)                  Identification No.)


      One Liberty Square, Boston, Massachusetts
      (Address of principal executive offices)
            02109
         (Zip Code)

        (617)357-9590
 (Registrant's telephone number including area code)


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

    Yes...X.......No..........


    Indicate  the number of shares  outstanding of each of the  issuer's
    classes of  common stock, as of the latest practical date.
              Class                          Outstanding at April 30, 1997
        Common Shares, $5 par value          20,435,997 shares

<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>

                                                           March 31,       December 31,
                                                               1997            1996
        <S>                                                 <C>          <C>
          ASSETS
         Utility Plant and Other Investments:
            Utility Plant in Service                     $ 1,068,009     $ 1,067,056
            Less:  Accumulated Provision for Depreciation
                       and Amortization                      359,912         350,816
            Net Utility Plant in Service                     708,097         716,240
            Construction Work in Progress                      8,533           3,839
                 Net Utility Plant                           716,630         720,079
            Investments in Jointly Owned Companies            71,747          71,626
            Non-Utility Plant - Net                           71,179          72,653
                 Total Plant and Other Investments           859,556         864,358
         Current Assets:
            Cash and Temporary Cash Investments                6,022          12,455
            Accounts Receivable, Net                          85,980          90,153
            Notes Receivable                                  28,158          24,691
            Fuel, Materials and Supplies                      12,600          14,131
            Other Current Assets                               7,799           7,668
                 Total Current Assets                        140,559         149,098
         Deferred Debits and Other Non-Current Assets        245,749         243,573
                 Total Assets                            $ 1,245,864     $ 1,257,029
         LIABILITIES AND CAPITALIZATION
         Capitalization:
            Common Shares, $5 Par Value                  $   102,180     $   102,180
            Other Paid-In Capital                            221,246         221,160
            Common Share Expense                              (3,931)         (3,931)
            Retained Earnings                                 54,257          52,404
                 Total Common Equity                         373,752         371,813
            Non-Redeemable Preferred Stock - Net               6,900           6,900
            Redeemable Preferred Stock - Net                  27,179          27,035
            Long-Term Debt - Net                             403,336         406,337
                 Total Capitalization                        811,167         812,085
         Current Liabilities:
            Long-Term Debt Due Within One Year                27,514          27,512
            Notes Payable                                     47,172          51,848
            Accounts Payable                                  30,572          33,811
            Taxes Accrued                                      4,112           3,004
            Interest Accrued                                   8,019           9,612
            Other Current Liabilities                         29,231          26,772
                 Total Current Liabilities                   146,620         152,559
         Deferred Credits and Other Non-Current Liabilities  122,635         123,209
         Accumulated Deferred Taxes                          165,442         169,176
                 Total Liabilities and Capitalization    $ 1,245,864     $ 1,257,029

            See accompanying notes to consolidated condensed financial statements.

</TABLE>

<TABLE>
  EASTERN UTILITIES ASSOCIATES
    CONSOLIDATED CONDENSED STATEMENTS OF INCOME
  (In Thousands Except Number of Shares and Per Share Amounts)
<CAPTION>




                                                                       Three Months Ended
                                                                     March 31,
                                                                       1997          1996
         <S>                                                          <C>          <C>
        Operating Revenues                                         $  141,753    $  134,800
        Operating Expenses:
            Fuel                                                       29,471        23,195
            Purchased Power                                            32,509        30,003
            Other Operation and Maintenance                            41,342        40,730
            Depreciation and Amortization                              11,630        11,123
            Taxes Other Than Income                                     6,376         6,470
            Income Taxes - Current                                      8,915         6,272
                         - Deferred (Credit)                           (4,696)       (1,274)
                  Total                                               125,547       116,519
        Operating Income                                               16,206        18,281
        Other Income - Net                                              4,429         3,368
        Income Before Interest Charges                                 20,635        21,649
        Interest Charges:
            Interest on Long-Term Debt                                  8,226         8,649
            Other Interest Expense                                      1,594         1,620
            Allowance for Borrowed Funds Used
              During Construction (Credit)                               (240)         (546)
        Net Interest Charges                                            9,580         9,723
        Net Income                                                     11,055        11,926
        Preferred Dividends of Subsidiaries                               576           578
        Consolidated Net Earnings                                  $   10,479    $   11,348



        Weighted Average Number of
          Common Shares Outstanding                                20,435,997    20,436,755
        Consolidated Earnings Per
          Average Common Share                                     $     0.51    $     0.56

        Dividends Paid Per Share                                   $    0.415    $     0.40


        See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
  EASTERN UTILITIES ASSOCIATES
 CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
    (In Thousands)

<CAPTION>
                                                                 Three Months Ended
                                                               March 31,
                                                                 1997          1996
    <S>                                                         <C>          <C>
    CASH FLOW FROM OPERATING ACTIVITIES:
    Net Income                                               $   11,055     $ 11,926
    Adjustments to Reconcile Net Income
       to Net Cash Provided from Operating Activities:
          Depreciation and Amortization                          13,153       13,181
          Deferred Taxes                                         (4,600)        (877)
          Non-cash (Gains)/Expenses on Sales of Investments
            in Energy Savings Projects                            2,652          928
          Investment Tax Credit, Net                               (300)        (302)
          Allowance for Funds Used During Construction              (46)         (40)
          Coll. and sales of project notes and leases rec.        2,605        1,587
          Other - Net                                               337         (420)
    Change in Operating Assets and Liabilities                    3,024        6,777
    Net Cash Provided From Operating Activities                  27,880       32,760

    CASH FLOW FROM INVESTING ACTIVITIES:
       Construction Expenditures                                (20,373)      (14,733
       Collections on Notes and Lease Rec. of EUA Cogenex         2,922          552
       Equity Investment in Joint Ventures                         (107)         (75)
    Net Cash (Used in) Investment Activities                    (17,558)      (14,256

    CASH FLOW FROM FINANCING ACTIVITIES:
       Redemptions:
          Long-Term Debt                                         (3,022)      (3,019)
       Premium on Reacquisition and Financing Expenses                0           (5)
       EUA Common Share Dividends Paid                           (8,482)      (8,175)
       Subsidiary Preferred Dividends Paid                         (576)        (578)
       Net (Decrease) Increase in Short-Term Debt                (4,675)       2,980
    Net Cash (Used in) Financing Activities                     (16,755)      (8,797)
    Net (Decrease) Increase in Cash and Temp. Cash Investments   (6,433)       9,707

    Cash and Temporary Cash Investments at Beginning of Period   12,455        4,060

    Cash and Temporary Cash Investments at End of Period     $    6,022     $ 13,767

    Supplemental disclosures of cash flow information:
       Cash paid during the period for:
          Interest (Net of Capitalized Interest)             $   10,086     $  8,543
          Income Taxes                                       $    7,263     $    973
    Supplemental schedule of non-cash investing activities:
       Conversion of Investments in Energy Savings
         Projects to Notes and Leases Receivable             $    2,189     $    712


See accompanying notes to consolidated condensed financial statements.
</TABLE>


                    EASTERN UTILITIES ASSOCIATES
                NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS


     The accompanying Notes should be read in conjunction with the Notes to
Consolidated Financial Statements incorporated in the Eastern Utilities
Associates (EUA or the Company) 1996 Annual Report on Form 10-K.

Note A -  In the opinion of the Company, the accompanying unaudited
          consolidated condensed financial statements contain all adjustments
          (consisting of only normal recurring accruals) necessary to present
          fairly its financial position as of March 31, 1997 and the results of
          operations and cash flows for the three months ended March 31, 1997
          and 1996.  Certain reclassifications have been made to prior period
          financial statements to conform to current period classifications.
          The year-end consolidated condensed balance sheet data was derived
          from audited financial statements but does not include all
          disclosures required under generally accepted accounting principles.

          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.

Note B -  Results shown above for the respective interim periods are not
          necessarily indicative of results to be expected for the fiscal years
          due to seasonal factors which are inherent in electric utilities in
          New England.  A greater proportionate amount of revenues is earned in
          the first and fourth quarters (winter season) of most years because
          more electricity is sold due to weather conditions, fewer day-light
          hours, etc.

Note C -  Commitments and Contingencies:

          Recent Nuclear Regulatory Commission (NRC) Actions

          Millstone III:

          Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw
          nuclear unit that is jointly owned by a number of New England
          utilities, including subsidiaries of Northeast Utilities (Northeast).
          Northeast is the lead participant in Millstone III, and on March 30,
          1996, Northeast determined 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 NRC has raised numerous issues with respect to Millstone III and
          certain of the other nuclear units in which Northeast and its
          subsidiaries, either individually or collectively, have the largest
          ownership shares, including Connecticut Yankee (see "Connecticut
          Yankee" below).

          In July 1996, Northeast reported that it was responding to a series
          of requests from the NRC seeking assurance that the Millstone III
          unit would be operated in accordance with the terms of its operating
          license and other NRC requirements and regulations and dealing with a
          series of issues that Northeast has identified in the course of these
          reviews.  Providing these assurances and addressing these issues were
          components of an Operational Readiness Plan which was submitted to
          the NRC on July 2, 1996 and is presently being implemented.

          On October 18 1996, the NRC informed Northeast that it was
          establishing a Special Projects Office to oversee inspection and
          licensing activities at Millstone.  The Special Projects Office is
          responsible for (1) licensing and inspection activities at
          Northeast's Connecticut plants, (2) oversight of an Independent
          Corrective Action The ICAVP for Millstone III is scheduled to begin
          in May of 1997.  The ICAVP is an external review process that is
          necessary prior to the restart of the unit.

          On October 24, 1996 the NRC issued another order directing that prior
          to restart of Millstone III, Northeast submit a plan for disposition
          of safety issues raised by employees and retain an independent third-
          party to oversee implementation of this plan.  This third-party
          oversight will continue until the situation is corrected.

          Northeast expects that one of the three Millstone units will be ready
          for restart in the third quarter of 1997, one in the fourth quarter
          of 1997 and one in the first quarter of 1998.  Subject to final NRC
          reviews and inspections, Northeast expects that at least one of the
          units will be back on line by the end of 1997.

          In March of 1997, Northeast announced that Millstone III has been
          designated as the lead unit in the recovery process of the three
          Millstone nuclear units that are currently out of service.  Millstone
          III 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 May 8, 1997, Northeast presented a revised 1997 budget for
          Millstone III which included significant increases in operation and
          maintenance (O&M) expenses.  Montaup's share of the revised O&M
          budget is approximately $10.4 million, approximately $4.4 million
          more than originally expected and $3.2 million more than O&M
          expenditures in 1996.

          While Millstone III is out of service, Montaup will incur incremental
          replacement power costs estimated at $0.5 million to $0.7 million per
          month.  Montaup bills its replacement power costs through its fuel
          adjustment clause, a wholesale tariff jurisdictional to the Federal
          Energy Regulatory Commission (FERC).  However, there is no comparable
          clause in Montaup's FERC-approved rates which at this time would
          permit Montaup to recover its share of the incremental operation and
          maintenance costs incurred by Northeast.

          EUA cannot predict the ultimate outcome of the NRC inquiries or the
          impact which they may have on Montaup and the EUA system.  Montaup is
          also evaluating its rights and obligations under the various
          agreements relating to the ownership and operation of Millstone III.

          Connecticut Yankee:

          Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July
          1996 because of issues related to certain containment air
          recirculation and service water systems.  Montaup has a 4.5% equity
          ownership in Connecticut Yankee with a book value of $5.0 million at
          March 31, 1997.

          In October 1996, Montaup, as one of the joint owners, participated in
          an economic evaluation of Connecticut Yankee which recommended
          permanently closing the unit and replacing its output with less
          expensive energy sources.  As a result of the analysis, work at the
          plant had slowed pending a final board decision.  In December
          1996, the Board of Directors voted to retire the generating station.
          Connecticut Yankee certified to the NRC that it had permanently
          closed power generation operations and removed fuel from the reactor.
          Connecticut Yankee has two years to submit its decommissioning plan
          to the NRC.  The preliminary estimate of the sum of future payments
          for the permanent shutdown, decommissioning, and recovery of the
          remaining investment in Connecticut Yankee, is approximately $758
          million.  Montaup's share of the total estimated costs is $34.1
          million.

          Maine Yankee:

          On June 7, 1996, the NRC commissioned an independent Safety
          Assessment Team to assess the conformance of the Maine Yankee Atomic
          Power Station to its design and licensing basis.  Montaup holds a
          4.0% ownership interest in the Maine Yankee Unit.  On October 7,
          1996, the NRC released an Independent Safety Assessment (ISA)
          report.  In evaluating the Plant's conformance to its licensing
          basis, the report concluded that Maine Yankee was in general
          conformance with its licensing basis although significant items of
          nonconformance were identified stemming from two closely related root
          causes: (1) economic pressure to be a low-cost energy provider
          had limited available resources to address corrective actions and
          some improvements, and (2) a questioning culture was lacking, which
          had resulted in a failure to identify or promptly correct significant
          problems in areas perceived by Maine Yankee to be of low safety
          significance.

          A letter to Maine Yankee from the Chair of the NRC accompanying the
          ISA report directed Maine Yankee to provide to the NRC its plans for
          addressing the root causes of the deficiencies identified by the ISA.

          In December, 1996 the unit was shut down for inspections and repairs
          to resolve cable-separation and associated issues.  While the Plant
          has been out of service, Maine Yankee, having previously detected
          indications of minor leakage in a small number of the Plant's 38,000
          fuel rods, used the opportunity to inspect the Plant's 217 fuel
          assemblies.  As a result of the inspection, Maine Yankee determined
          that several fuel assemblies that contained leaking rods should be
          replaced and has commenced that process.   On January 29, 1997 the
          NRC announced that it had placed the unit on its "watch list."  The
          operator expects the Plant to remain out of service until the fuel-
          assembly replacement and a thorough inspection of the Plant's
          electrical cabling are completed and associated issues resolved, and
          restarting the Plant is approved by the NRC.

          In February 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy)
          signed a contract for Entergy to provide management services
          including plant operations at the Maine Yankee plant through
          September 1997.  Maine Yankee and Entergy have been discussing the
          possibilities of a longer term contract.

          On March 7, 1997, Maine Yankee submitted its Restart Readiness Plan
          (RRP) to the NRC.  The RRP is subject to public participation and
          comment prior to NRC approval.  Maine Yankee expects the unit to be
          out of service until at least August 1997, but cannot predict when or
          whether all regulatory and/or operational issues will be
          satisfactorily resolved.

          The owners of Maine Yankee continue to evaluate the impact of
          substantially increased maintenance costs on the economic viability
          of the unit.

          General:

          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 have on any of the other
          nuclear power plants in which Montaup has an ownership interest or
          power contract.

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

     The following is Management's discussion and analysis of certain
significant factors affecting the Company's earnings and financial condition
for the interim periods presented in this Form 10-Q.

Overview

     Consolidated net earnings for the first quarter of 1997 were $10.5 million
compared to first quarter 1996 net earnings of $11.3 million.   Net Earnings
contributions by Business Unit for the first three months of 1997 and 1996 were
as follows (in thousands):

                                  Three Months Ended March 31,

                                              1997        1996
    Core Electric Business                 $10,901     $11,613
    Energy Related Business                  (510)         (92)
    Corporate                                   88        (173)
       Consolidated                        $10,479     $11,348


     The decrease in the net earnings contribution of the Core Electric
Business in the first quarter of 1997 was primarily due to decreased
kilowatthour (kWh) sales.  Total primary kWh sales decreased by 2.9% in this
year's first quarter, mainly weather related.  Peak demands for electricity
decreased 4.2% in this year's first quarter.

     Net Earnings of our Energy Related Business Unit decreased by
approximately $400,000 in the first quarter of 1997 as compared to the same
period of a year ago.  This decrease is primarily due to increased expenses of
the BIOTEN partnership, largely marketing related.  As anticipated, EUA Cogenex
operated at a loss of approximately $600,000 in the first quarter of 1997,
approximately one-half of the operating loss experienced in the fourth quarter
of 1996.  The improvement in new contract sales experienced in this year's
first quarter is expected to contribute to  earnings in the second half of
1997.  The first quarter operating loss was offset somewhat by a net gain of
approximately $500,000 resulting from a change in  EUA Cogenex pension and
post-retirement welfare benefit plans.  These benefit plan changes will result
in significant on-going expense savings.

     The change in the earnings contribution of the Corporate Business Unit is
due primarily to lower interest expense and increased intercompany interest
income.

Operating Revenues

    Operating Revenues for the first three months of 1997 increased by
approximately $7.0 million to approximately $141.8 million when compared to the
same period of 1996.  Operating Revenues by Business Unit for the first quarter
of 1997 and 1996 were as follows (in thousands):

                                  Three Months Ended March 31,

                                              1997        1996
    Core Electric Business                $128,224    $122,204
    Energy Related Business                 13,529      12,596
    Corporate                                    0           0
       Consolidated                       $141,753    $134,800


     Core Electric Business revenues increased $6.0 million due primarily to
recoveries of increased fuel, purchased power and conservation and load
management (C&LM) expenses aggregating approximately $8.0 million, and base
rate increases for Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) pursuant to the Rhode Island Utility
Restructuring Act of 1996 (URA)   These increases were offset by the impacts of
decreased kWh sales and peak demand billings.

     EUA Cogenex revenues, which account for nearly all of the Energy Related
Business Unit revenues, increased by approximately $900,000 due primarily to an
increase of $1.6 million in partnership project sales offset somewhat by a
decrease in EUA Day Division revenues in the first quarter.

Operating Expenses

     Fuel expense of the Core Electric Business for the first quarter of 1997
increased from that of the same period in 1996 by approximately $6.3 million or
27.1%.  Outages of nuclear units in this year's first quarter contributed to a
greater dependance on higher cost fossil fuels for energy requirements,
resulting in a 27.7% increase in average fuel costs.  This increase was offset
somewhat by decreased energy requirements for the period.

     Purchased Power expense for the first quarter of 1997 increased $2.5
million or 8.4% as compared to last year's first quarter.  Higher costs billed
to Montaup by Maine Yankee, Connecticut Yankee, and Ocean State Power in 1997's
first quarter were primarily responsible for this change.

     Other Operation and Maintenance (O&M) expenses for the quarter ended March
31, 1997 increased approximately $600,000 or 1.5% from the same period in 1996
due to the following: Direct expenses of the Core and Corporate Business units
decreased by approximately $800,000 in this year's first quarter due primarily
to decreased customer accounts expense of approximately $400,000 and decreased
distribution expenses aggregating approximately $300,000.

     Indirect expenses, items in which we have limited short-term control or
items which are fully recovered in rates, increased by approximately $800,000
in the first quarter of 1997 as compared to the same period of 1996.  This
change was due primarily to increased jointly owned unit expenses of
approximately $1.6 million, $1.0 million of which is related to the Millstone
III outage, partially offset by decreases in C&LM expenses of approximately
$400,000 and decreased employee benefits expenses of approximately $300,000.

     Expenses of the Energy Related Business unit increased by $600,000 for the
period.  This increase is primarily due to increased marketing-related expenses
of the BIOTEN partnership.

Depreciation and Amortization Expense

     Depreciation and Amortization expense increased $500,000 or 4.6% in the
first quarter of 1997 when compared to last year's first quarter due largely to
increased Core Electric plant in service.

Other Income and (Deductions) - Net

     Other Income and (Deductions) - Net increased by approximately $1.1
million in this year's first quarter.  This increase is due primarily to
interest income related to the favorable resolution of a Massachusetts
corporate income tax dispute and the impact of changes to EUA Cogenex pension
and post-retirement welfare benefit plans.

Interest Charges

     Net interest charges decreased by approximately $100,000 in the first
quarter of 1997 due primarily to a decrease of $400,000 in long-term debt
interest resulting from the operation of normal sinking fund provisions offset
by a decrease in capitalized interest of EUA Cogenex of approximately $300,000.

Liquidity and Sources of Capital

     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.

     Traditionally, cash construction requirements not met with internally
generated funds are financed through short-term borrowings which are ultimately
funded with permanent capital.  At March 31, 1997, EUA System companies
maintained short-term lines of credit with various banks aggregating
approximately $140 million.  Outstanding short-term debt at March 31, 1997 and
December 31, 1996 by Business Unit was as follows (in Thousands):

                                March 31, 1997  December 31, 1996
    Core Electric Business             $ 9,103         $ 3,670
    Energy Related Business             28,412          24,341
    Corporate                            9,657          23,837
       Consolidated                    $47,172         $51,848

    For the three months ended March 31, 1997, internally generated funds
amounted to approximately $15.3 million while the EUA System's cash
construction requirements amounted to approximately $20.4 million for the same
period.  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.

Electric Utility Industry Restructuring

     On August 7, 1996 the Governor of Rhode Island signed into law the URA.
The URA provides for customer choice of electricity supplier to be phased-in
commencing July 1, 1997 for large manufacturing customers, certain new
commercial and industrial customers, and State of Rhode Island accounts.  By
July 1, 1998, or sooner, all customers will have retail access.  Under the
URA the local distribution company will retain the responsibility of providing
distribution services to the ultimate electricity consumer within its
franchised service territory.  For customers who choose not to choose, the
local distribution company would arrange for supply at a non-discriminatory,
"standard offer" price.  Distribution companies will also be providers of last
resort, required to arrange for supply at prevailing market prices for
customers who are unable to obtain their own supply.

     The URA provides for full recovery of prudently incurred embedded
generation costs that might not be recovered in a competitive electric
generation market, commonly referred to as "stranded costs," through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000.  The transition charge recovers, among other things, costs
of depreciated generation, net of its market value, regulatory assets, nuclear
decommissioning costs and above market payments to power suppliers.  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 July 1,
1997, 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 July 1, 1997,
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 rate-making standards for electric distribution
companies.  These performance based standards provide for a 6% minimum and an
approximate 12% maximum allowed return on equity for Blackstone and 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 and other performance
factors.  Under this provision of the law, base rates were increased 1.88% for
customers of Blackstone, and 2.18% for our Newport customers effective January
1, 1997.

     The implementation of the URA requires approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).

      In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers and
the state's Attorney General and filed a Memorandum of Understanding (MOU) with
the RIPUC in March 1997 outlining the terms of the settlement.  In addition to
complying with the URA, the settlement provides for an immediate 10% rate
reduction and the filing of a plan to divest all of Montaup's generating
assets, and is similar in many respects to the settlement negotiated in
Massachusetts, described below.

     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 and filed a MOU with the Massachusetts
Department of Public Utilities (MDPU) 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 and provide Eastern Edison and Montaup full
recovery of "stranded costs."

     The agreement envisions that all of Eastern Edison's customers will have
the ability to choose an alternative supplier of electricity beginning 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% savings from today's electricity rates.  Eastern Edison would be required
to arrange for "standard offer" service and would purchase power for  "standard
offer" service from suppliers through a competitive bidding process.   The
agreement is also designed to achieve full divestiture of Montaup's generating
assets via implementation of a plan, to be submitted to the MDPU by July 1,
1997, that would require (1) separation by Montaup of its generating and
transmission businesses and (2) full market valuation and sale of all
generating assets through an auction or equivalent process, to be conducted by
an independent third party.

     Upon the commencement of retail choice in Massachusetts, Montaup's FERC
approved, all-requirements wholesale contract with Eastern Edison would be
terminated.  In its place, Montaup will bill Eastern Edison a Contract
Termination Charge (CTC) designed to recover the cost of Montaup's above
market, embedded  generation commitments to serve Eastern Edison's customers,
with a return.  Eastern Edison will recover the CTC through a non-bypassable
transition access charge to all of its distribution customers.  The transition
access charge would 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.

     Embedded costs associated with generating plants and regulatory assets
would be recovered, with a return, over a period of 12 years.  Purchased power
contracts and nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond 12 years.
The initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.

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

     In addition to MDPU approval of the agreement, implementation is also
subject to the approval of FERC.  Any disposition of generation assets
resulting from the agreements or the URA would also require the approval of the
SEC under the Public Utility Holding Company Act of 1935.

     On May 1, 1997, Montaup and the R.I. Distribution Companies jointly filed
amendments to the FERC-approved all-requirements power contracts between
Montaup and the R.I.  Distribution Companies, respectively, with FERC.  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.  These provisions are intended to
ulimately replace the current services offered by the all-requirements
contracts upon full retail access pursuant to the URA.  EUA intends to amend
this filing once settlement negotiations have concluded in Rhode Island and
Massachusetts.  The filing also includes "hold harmless" provisions for
Montaup's other wholesale customers and for retail customers of the R.I.
Distribution Companies, which allow for recovery of any of Montaup's lost
revenues during the initial phases of retail access in Rhode Island.  This
filing allows the R.I. Distribution Companies to implement on July 1, 1997 the
phase-in provisions of the URA and to avoid any cross subsidies by their retail
customers who are excluded from the groups of customers given retail choice
prior to the final phase and by Montaup's other customers.

     Negotiations in both Massachusetts and Rhode Island on final settlement
terms regarding electric utility industry restructuring, including the CTC, are
continuing, subsequent to which formal filings will be made to the MDPU and
RIPUC for approval.  It is EUA's intent to file both Massachusetts and Rhode
Island settlements with FERC for approval of amendments to the all-
requirements wholesale contracts contained in the respective settlements.

     Historically, electric rates have been designed to recover a utility's
full costs 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.  EUA believes that its Core Electric operations will continue to
meet the criteria established in these accounting standards.

     However, the potential exists that the final outcome of state and federal
agency determinations could result in EUA no longer meeting the criteria of
these accounting standards which could trigger the discontinuance of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (FAS71).  Should it be required to discontinue the
application of FAS71, EUA would be required to take an immediate write-down of
the affected assets in accordance with FAS101, "Accounting for the
Discontinuation of Application of FAS71."

     In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover the 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".

Other

     EUA occasionally makes projections of expected future performance or
statements of its plans, objectives and new business opportunities which are
forward-looking statements under federal securities law.  Actual results could
differ materially from those discussed and there can be no assurance that such
estimates of future results will be achieved.

Item 5.   Other Information

     On April 24, 1996, FERC issued orders on its March 24, 1995 Notice of
Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to
encourage competition in the bulk power market.  FERC's April 24th actions
include:

     - order No. 888, a final rule requiring open access transmission and
       requiring all public utilities that own, operate or control interstate
       transmission to file tariffs that offer others the same transmission
       services they provide themselves, under comparable terms and
       conditions. Utilities must take transmission service for their own
       wholesale transactions under the terms and conditions of the tariff;

     - establishing the right and a mechanism for recovery of prudently
       incurred stranded costs by public utilities and transmitting utilities;
       which arise as a result of wholesale open access;

     - order No. 889, a final rule requiring public utilities to implement
       standards of conduct and an Open Access Same-time Information System
       (OASIS).  Utilities must obtain information about their transmission the
       same way as their competitors through the OASIS;

     - a NOPR requesting comment on replacing the single tariff contained in
       the final open access rule with a capacity reservation tariff that would
       reveal how much transmission is available at any given time.

     Open-access transmission tariffs for point-to-point and network service
were filed with FERC by Montaup in February 1996 and became effective April 21,
1996, subject to refund, for a period of at least one year. The rates in the
tariffs were the subject of a settlement agreement which was filed on June 14,
1996. Montaup amended its filing on July 9, 1996 to modify its terms and
conditions in conformance with FERC's order. These tariffs are in compliance
with FERC's April 24th rulings.

     On November 13, 1996, FERC issued a final order on the non-rate terms and
conditions of Montaup's open access transmission tariff. Montaup was required
to provide a more detailed description of the method used to compute available
transmission capability.  FERC has not taken any action on the rates portion of
the tariff.

     On December 31, 1996, Montaup filed revisions to its Open Access
Transmission tariff necessary to comply with FERC's order on September 11,
1996, which dealt with use rights of High Voltage Direct Current (HVDC)
interconnection transmission facilities with the Hydro Quebec system. On
January 21,1997, Montaup filed revisions to its Open Access Transmission tariff
to coincide with the New England Power Pool (NEPOOL) Open Access Transmission
tariff filed on December 31, 1996 (see below) which became effective March 1,
1997, subject to refund and the issuance of further orders. On April 2, 1997,
Montaup filed additional revised tariff sheets to update the filing's formula
rate for local network service.

     On January 3, 1997, as required by FERC in Order No. 889, Montaup filed
its Standards of Conduct Implementation Procedures detailing Montaup's
compliance with the requirements of FERC's standards. Coincident with this
filing, Montaup complied with OASIS's requirements as part of a regionwide
OASIS in NEPOOL.

     On March 4, 1997 FERC issued Orders 888A and 889A which reaffirms the
legal and policy bases in which Orders 888 and 889 are grounded and addresses
interventions that were filed in response to Orders 888 and 889. As a result,
compliance tariffs must be filed by July 14, 1997.

     In addition to the above transmission tariffs filings, the EUA System
companies have been actively involved in the restructuring of NEPOOL.  NEPOOL
is a voluntary organization open to any person engaged in the electric business
such as investor-owned utilities, municipals, cooperative utilities, power
marketers, brokers and load aggregators. On December 31, 1996, NEPOOL, on
behalf of its participants, filed a restructuring proposal with the FERC. The
NEPOOL restructuring proposal is the product of over two years of intense
discussions, deliberations and negotiations among the over 130 NEPOOL member
participants and many non-participants, including New England state regulators.
The key elements of the restructuring proposal are the implementation of a
regional NEPOOL Open Access Transmission Tariff (NEPOOL Tariff), the
creation of an Independent System Operator (ISO), and the restatement of the
NEPOOL Agreement to establish a broader governance structure for NEPOOL and to
develop a more open competitive market structure.

     The NEPOOL Tariff, which became effective on March 1, 1997, ensures non-
discriminatory open access to the regional transmission network by providing a
single rate for all transactions that utilize the NEPOOL's bulk power
transmission facilities. The NEPOOL Tariff promotes competition in the New
England power market through its non-pancaked rate structure. All regional
service within NEPOOL, except for wheeling through or out, is to be provided as
a network service.

     NEPOOL is in the process of transferring operational control of the New
England bulk power system to the ISO, a newly created non-profit Delaware
corporation. The ISO's primary responsibility is to ensure system reliability,
administer the NEPOOL Tariff, and oversee the efficient and competitive
functioning of the regional power market. The selection of the ISO's
Board of Directors was announced in April 1997.

     To give market participants more choice and to foster competition, the
restructured NEPOOL proposes the unbundling of electric service in the NEPOOL
control area. The restructured NEPOOL calls for the development of competitive
wholesale markets for installed capability, operable capability, energy, and
reserves. These wholesale products will be market priced based on
bid clearing pricing rather than the current cost-based pricing. Market
participants will be able to transfer their responsibility for these products
by buying or selling these various services through bilateral transactions or
through the regional power exchange that will be administered through the
ISO. Implementation of the installed capability market is planned for November
1997, the operable capability and energy markets are planned for April 1998,
and the reserve markets will follow later in 1998.

     In general, the EUA System companies support the changes to NEPOOL because
much of the cross subsidies for sharing costs will be eliminated. These changes
will have an impact on the EUA System operating revenues and costs as NEPOOL
transitions from a cost based to a bid based system.


Item 6.   Exhibits and Reports on Form 8-K

     (a)  Exhibits - None

     (b)  Reports on Form 8-K - On January 6, 1997, the Registrant filed a
          current report of Form 8-K with respect to Item 5 (Other Events).




                                SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.


                                        Eastern Utilities Associates
                                                (Registrant)



Date:  May 14, 1997                     /s/ Richard M. Burns
                                        Richard M. Burns
                                        (on behalf of the Registrant and
                                        as Chief Accounting Officer)