<PAGE>

                SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C.   20549


                            FORM 10-Q


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

          For the quarterly period ended March 31, 1999

                                OR

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


                  Commission File Number 0-5464


              (LOGO)  MASSACHUSETTS ELECTRIC COMPANY


        (Exact name of registrant as specified in charter)


       MASSACHUSETTS               04-1988940
       (State or other             (I.R.S. Employer
       jurisdiction of             Identification No.)
       incorporation or
       organization)


      25 Research Drive, Westborough, Massachusetts   01582
             (Address of principal executive offices)

        Registrant's telephone number, including area code
                          (508-389-2000)

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 ( )

Common stock, par value $25 per share, authorized and
outstanding:  2,398,111 shares at March 31, 1999.
<PAGE>
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
----------------------------
<TABLE>
                          MASSACHUSETTS ELECTRIC COMPANY
                               Statements of Income
                              Periods Ended March 31
                                   (Unaudited)
<CAPTION>
                                                Three Months                           Twelve Months
                                                ------------                           -------------
                                            1999      1998      1999       1998
                                            ----      ----      ----       ----
                                                          (In Thousands)
<S>                                          <C>       <C>       <C>        <C>
Operating revenue                         $344,764  $396,714$1,438,467 $1,615,281
                                          --------  ------------------ ----------

Operating expenses:
  Purchased electric energy:
   Contract termination charges from
     New England Power Company, an affiliate55,748    36,822   319,556     36,822
   Other New England Power Company               -   246,677   218,343  1,096,107
   Other                                   147,800        83   322,807        500
  Other operation                           75,531    50,782   317,258    219,386
  Maintenance                                7,226     8,752    31,996     38,234
  Depreciation                              16,613    14,253    64,060     51,309
  Taxes, other than income taxes             9,600     8,949    38,634     31,219
  Income taxes                               8,654     7,553    37,420     41,411
                                          --------  ------------------ ----------
       Total operating expenses            321,172   373,871 1,350,074  1,514,988
                                          --------  ------------------ ----------
Operating income                            23,592    22,843    88,393    100,293

Other income (expense), net                 (2,190)   (2,878)   (2,822)    (2,518)
                                          --------  ------------------ ----------
       Operating and other income           21,402    19,965    85,571     97,775
                                          --------  ------------------ ----------

Interest:
  Interest on long-term debt                 6,853     6,871    27,055     27,400
  Other interest                             1,911     1,419     7,860      6,891
  Allowance for borrowed funds used during
   construction - credit                      (195)     (136)     (752)      (449)
                                          --------  ------------------ ----------
       Total interest                        8,569     8,154    34,163     33,842
                                          --------  ------------------ ----------

Net income                                $ 12,833  $ 11,811$   51,408 $   63,933
                                          ========  ================== ==========


                         Statements of Retained Earnings
                                 (In Thousands)

Retained earnings at beginning of period  $208,537  $201,156$  197,139 $  166,803
Net income                                  12,833    11,811    51,408     63,933
Dividends declared on cumulative
  preferred stock                             (154)     (240)     (787)    (2,283)
Dividends declared on common stock               -   (15,588)  (26,379)   (27,578)
Premium on redemption of preferred stock         -         -      (165)    (3,736)
                                          --------  ------------------ ----------
Retained earnings at end of period        $221,216  $197,139$  221,216 $  197,139
                                          ========  ================== ==========

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

   Per share data is not relevant because the Company's common stock is wholly
                      owned by New England Electric System.
</TABLE>
<PAGE>
<TABLE>
                      MASSACHUSETTS ELECTRIC COMPANY
                              Balance Sheets
                                (Unaudited)
<CAPTION>
                                                      March 31,                  December 31,
                                  ASSETS               1999           1998
                                  ------               ----           ----
                                                           (In Thousands)
<S>                                                     <C>           <C>
Utility plant, at original cost                        $1,639,000   $1,626,569
 Less accumulated provisions for depreciation             512,296      499,975
                                                       ----------   ----------
                                                        1,126,704    1,126,594
Construction work in progress                              19,749       16,575
                                                       ----------   ----------
   Net utility plant                                    1,146,453    1,143,169
                                                       ----------   ----------
Current assets:
 Cash                                                       8,209        6,994
 Accounts receivable:
   From electric energy services                          187,769      188,956
   Other (including $3,594,000 and $6,629,000
    from affiliates)                                        4,114        7,358
     Less reserves for doubtful accounts                   13,480       12,450
                                                       ----------   ----------
                                                          178,403      183,864
 Unbilled revenues                                         42,801       56,133
 Materials and supplies, at average cost                   10,395        9,281
 Prepaid and other current assets                           2,018       13,886
                                                       ----------   ----------
     Total current assets                                 241,826      270,158
                                                       ----------   ----------
Deferred charges and other assets                          39,022       41,235
                                                       ----------   ----------
                                                       $1,427,301   $1,454,562
                                                       ==========   ==========
                      CAPITALIZATION AND LIABILITIES
                      ------------------------------
Capitalization:
 Common stock, par value $25 per share, authorized
   and outstanding 2,398,111 shares                    $   59,953   $   59,953
 Premium on capital stock                                  45,942       45,942
 Other paid-in capital                                    193,498      193,498
 Retained earnings                                        221,216      208,537
 Unrealized gain on securities, net                           280          273
                                                       ----------   ----------
     Total common equity                                  520,889      508,203
 Cumulative preferred stock                                10,674       10,674
 Long-term debt                                           347,372      353,329
                                                       ----------   ----------
     Total capitalization                                 878,935      872,206
                                                       ----------   ----------
Current liabilities:
 Long-term debt due in one year                            21,000       15,000
 Short-term debt to affiliates                             37,325       80,725
 Accounts payable (including $51,543,000 and $34,506,000
  to affiliates)                                          146,634      127,621
 Accrued liabilities:
   Taxes                                                    6,899            -
   Interest                                                 8,010        8,509
   Other accrued expenses                                  48,423       40,626
 Customer deposits                                          4,258        4,456
 Dividends payable                                            155        4,951
                                                       ----------   ----------
     Total current liabilities                            272,704      281,888
                                                       ----------   ----------
Deferred federal and state income taxes                   190,271      200,965
Unamortized investment tax credits                         14,110       14,377
Other reserves and deferred credits                        71,281       85,126
                                                       ----------   ----------
                                                       $1,427,301   $1,454,562
                                                       ==========   ==========

The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
                      MASSACHUSETTS ELECTRIC COMPANY
                         Statements of Cash Flows
                          Quarters Ended March 31
                                (Unaudited)
<CAPTION>
                                                         1999          1998
                                                         ----          ----
                                                             (In Thousands)
<S>                                                                        <C>       <C>
Operating activities:
   Net income                                            $ 12,833     $ 11,811
   Adjustments to reconcile net income to net cash
     provided by operating activities:
   Depreciation                                            16,613       14,253
   Deferred income taxes and investment tax credits, net  (10,439)       5,834
   Allowance for borrowed funds used during construction     (195)        (136)
   Decrease (increase) in accounts receivable,
     net and unbilled revenues                             18,793      (18,127)
   Decrease (increase) in materials and supplies           (1,114)        (426)
   Decrease (increase) in prepaid and other current assets 11,868        1,404
   Increase (decrease) in accounts payable                 19,013       20,343
   Increase (decrease) in other current liabilities        13,999       (1,044)
   Other, net                                             (12,047)       2,455
                                                         --------     --------
      Net cash provided by (used in) operating activities$ 69,324     $ 36,367
                                                         --------     --------

Investing activities:
   Plant expenditures, excluding allowance for
     funds used during construction                      $(19,701)    $(18,488)
 
   Other investing activities                                 (58)         (87)
                                                         --------     --------
      Net cash provided by (used in) investing activities$(19,759)    $(18,575)
                                                         --------     --------
Financing activities:
   Dividends paid on common stock                        $ (4,796)    $ (4,796)
   Dividends paid on preferred stock                         (154)        (240)
   Long-term debt - issues                                      -       25,000
   Long-term debt - retirements                                 -      (30,000)
   Changes in short-term debt                             (43,400)      (4,400)
                                                         --------     --------
      Net cash provided by (used in)
       financing activities                              $(48,350)    $(14,436)
                                                         --------     --------

Net increase (decrease) in cash and cash equivalents     $  1,215     $  3,356

Cash and cash equivalents at beginning of period            6,994        6,743
                                                         --------     --------
Cash and cash equivalents at end of period               $  8,209     $ 10,099
                                                         ========     ========

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

</TABLE>
<PAGE>


<PAGE>
                  MASSACHUSETTS ELECTRIC COMPANY
            Notes to Unaudited Financial Statements

Note A - Hazardous Waste
------------------------

  The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly known as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous substances. 
A number of states, including Massachusetts, have enacted similar
laws.

  The electric utility industry typically utilizes and/or generates
in its operations a range of potentially hazardous products and by-
products.  Massachusetts Electric Company (the Company) currently
has in place an internal environmental audit program and an
external waste disposal vendor audit and qualification program
intended to enhance compliance with existing federal, state, and
local requirements regarding the handling of potentially hazardous
products and by-products.

  The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for 16
sites at which hazardous waste is alleged to have been disposed. 
Private parties have also contacted or initiated legal proceedings
against the Company regarding hazardous waste cleanup.  The most
prevalent types of hazardous waste sites with which the Company has
been associated are manufactured gas locations.  (Until the early
1970s, New England Electric System (NEES) was a combined electric
and gas holding company system.)  The Company is aware of
approximately 35 such manufactured gas locations in Massachusetts. 
The Company has been identified as a PRP at eight of these
manufactured gas locations, which are included in the 16 PRP sites
discussed above.  The Company has reported the existence of all
manufactured gas locations of which it is aware to state
environmental regulatory agencies.  The Company is engaged in
various phases of investigation and remediation work at 17 of the
manufactured gas locations.  The Company is currently aware of
other possible hazardous waste sites, and may in the future become
aware of additional sites, that it may be held responsible for
remediating.

  In 1993, the Massachusetts Department of Public Utilities 
approved a settlement agreement that provides for rate recovery of
remediation costs of former manufactured gas sites and certain
other hazardous waste sites located in Massachusetts.  Under that
agreement, qualified costs related to these sites are paid out of
a special fund established on the Company's books.  Rate-
recoverable contributions of $3 million, adjusted since 1993 for
inflation, are added annually to the fund along with interest,

<PAGE>
lease payments, and any recoveries from insurance carriers and
other third parties.  At March 31, 1999, the fund had a balance
of $47 million.

  Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult.  There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by the Company.  The NEES
Companies have recovered amounts from certain insurers, and,
where appropriate, the Company intends to seek recovery from
other insurers and from other PRPs, but it is uncertain whether,
and to what extent, such efforts will be successful.  At March
31, 1999, the Company had total reserves for environmental
response costs of $42 million which includes reserves established
in connection with the Company's hazardous waste fund referred to
above.  The Company believes that hazardous waste liabilities for
all sites of which it is aware, and which are not covered by a
rate agreement, are not material to its financial position.

Note B - New Accounting Standards
---------------------------------

  In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, Accounting
for Derivative Instruments and Hedging Activities (FAS 133),
which establishes accounting and reporting standards for such
instruments.  FAS 133 is effective for fiscal years beginning
after June 15, 1999.  

  Under the provisions of industry restructuring settlement
agreements approved by state and federal regulators implemented
on March 1, 1998, the Company is required to offer a default
service option to those customers who, for a variety of reasons,
are not purchasing power from a competitive supplier.  The
Company is required to procure this power supply through
competitive bidding.  In March 1999, the Company entered into a
power supply contract with a third party to provide the physical
supply of this power at a variable market rate.  In May 1999, the
Company entered into a eight month financial contract with
another third party to convert this variable rate into a fixed
rate for substantially, if not for all, of the physical supply. 
The Company will bill its retail customers at the fixed rate
under the financial contract.  Purchases under these contracts
are expected to be less than $5 million per month using April
1999 service requirements. 

<PAGE>
Note C
------

  In the opinion of the Company, these financial statements
reflect all adjustments (which include normal recurring
adjustments) necessary for a fair statement of the results of its
operations for the periods presented and should be considered in
conjunction with the notes to the financial statements in the
Company's 1998 Annual Report.
<PAGE>
                 MASSACHUSETTS ELECTRIC COMPANY
   Item 2. Management's Discussion and Analysis of Financial
              Condition and Results of Operations
----------------------------------------------------------------- 


  This section contains management's assessment of Massachusetts
Electric Company's (the Company) financial condition and the
principal factors having an impact on the results of operations. 
This discussion should be read in conjunction with the Company's
financial statements and footnotes and the 1998 Annual Report on
Form 10-K.


Merger Agreements
-----------------

  For a full discussion of New England Electric Systems' (NEES)
merger agreements with The National Grid Group plc (National Grid)
and Eastern Utilities Associates (EUA), see the Merger Agreements
sections of the Company's Form 10-K for 1998 and the Company's 1998
Annual Report.

Update of Merger Agreements with National Grid and EUA

  On April 9, 1999, NEES and National Grid received clearance under
the Hart-Scott-Rodino (HSR) Antitrust Improvements Act of 1976, as
amended.   In addition, shareholders of National Grid  approved the
proposed merger on April 22, 1999 with 99 percent of those voting
approving the merger.  On May 3, 1999, NEES received the approval
of more than the required majority of outstanding shares for the
merger with 75 percent of outstanding shares voting in favor of the
merger.  Of those shares voted, in excess of 94 percent voted in
favor of the merger.  NEES and National Grid have also filed for
merger approval with the Securities and Exchange Commission (SEC),
Federal Energy Regulatory Commission (FERC), and Nuclear Regulatory
Commission (NRC).  NEES and National Grid have also made filings in
the states in which NEES subsidiaries operate where support or
approval for the merger is required.  On April 21, 1999, the New
Hampshire Public Utilities Commission (NHPUC) issued an order
finding that the NEES/National Grid merger filing did not satisfy
the requirements for exemption from the NHPUC's formal review
process.  Hearings on the merger are scheduled for June 1999.  On
April 29, 1999, the Committee on Foreign Investment in the United
States under the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988 concluded there were no issues of
national security to warrant any investigation.  The NEES/National
Grid merger is expected to be completed by early 2000.

  On April 29, 1999, NEES and EUA also received clearance under HSR
for the NEES acquisition of EUA.  NEES and EUA have filed for
merger approval with the FERC and the Commonwealth of

<PAGE>
Massachusetts.  The acquisition of EUA also requires approval by
the SEC and NRC, and  approval by certain states in which EUA
subsidiaries operate.  On May 17, 1999, EUA shareholders approved
the acquisition of EUA by NEES.  The acquisition of EUA is expected
to be completed by early 2000.

Impact of Mergers on Distribution Rates
---------------------------------------

  On April 29, 1999, the Company and Eastern Edison Associates
(Eastern Edison), a wholly owned subsidiary of EUA, filed a rate
consolidation plan with the Massachusetts Department of
Telecommunications and Energy, reflecting the acquisition of EUA by
NEES and the merger of Eastern Edison into the Company.   In the
filing, the companies proposed that effective January 1, 2001,  
Eastern Edison's customers  would pay the same delivery rates as
the Company.  The filing calls for an extension of the Company's
distribution rate freeze through December 31, 2002.  The freeze
would be extended an additional two years upon completion of the
NEES/National Grid merger.

Industry Restructuring
----------------------

  For a full discussion of industry restructuring activities in
Massachusetts, the NEES companies' divestiture of its nonnuclear
generating business, stranded cost recovery, and the impact of
restructuring on the distribution business, see the "Industry
Restructuring" and "Impact of Restructuring on Distribution
Business" sections of the Company's Form 10-K for 1998 and the
Company's 1998 Annual Report.

Regulatory Asset Recovery
-------------------------

  Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets, and thereby defer
the income statement impact of these charges because they are
expected to be included in future customer charges. At March 31,
1999, the Company had approximately $14 million in net regulatory
assets.

  Under existing ratemaking practices and provisions of industry
restructuring settlement agreements approved by state and federal
regulators (Massachusetts Settlement), the Company has the ability
to recover through rates its specific costs of providing ongoing
distribution services and stranded costs billed to it by NEP.  The
Company has believed these factors have allowed it to continue to
apply FAS 71.
<PAGE>
  Currently, there is much regulatory and other movement toward
establishing performance-based rates. It is possible that the
adoption of performance-based rates, future regulatory rules, or
other circumstances could cause the application of FAS 71 to be
discontinued. Absent the circumstances described in the next
paragraph, this discontinuation would result in a noncash write-off
of previously established regulatory assets.  In addition, reserves
for depreciation may also have to be increased to comply with
unregulated accounting practices.

  In April 1999, the Company filed a rate plan which, if approved, 
may cause the application of FAS 71 to be discontinued upon
consummation of the NEES/National Grid merger.  Because the
discontinuation of FAS 71 would be coincident with the completion
of the NEES/National Grid merger, the regulatory assets would not
be written off but instead would be reclassified to either an
intangible asset account or a goodwill account. 

Year 2000 Readiness Disclosure
------------------------------

  Over the course of this year, most companies will face a
potentially serious information systems (computer) problem because
many software applications and operational programs written in the
past may not properly recognize calendar dates associated with the
year 2000 (Y2K). This could cause computers to either shut down or
lead to incorrect calculations.

  During 1996, the NEES companies began the process of identifying
the changes required to their computer software and hardware to
mitigate Y2K issues. The NEES companies established a Y2K Project
team to manage these issues, which has consisted of as many as 70
full-time equivalent staff at some points in time, primarily
external consultants being overseen by an internal Y2K management
team.  To facilitate the Y2K Project, NEES entered into contracts
with Keane, Inc. and IBM to provide personnel support to the Y2K
Project.  Through March 31, 1999, the NEES companies have spent
approximately $17 million with these vendors, which is included in
the cost figures disclosed below.  The Y2K Project team reports
project progress to a Y2K Executive Oversight Committee each month.
The team also makes regular reports to NEES' Board of Directors and
its Audit Committee. The NEES companies have separated their Y2K
Project into four parts as shown below, along with the estimated
completion dates for each part.
<PAGE>
<TABLE>
<CAPTION>
                                    Substantial Contingency Testing
                                    Completion  Documentation,
                                    of Critical and Clean
Category         Specific Example   Systems     Management
--------         ----------------   ----------- -------------------
<S>              <C>                <C>         <C>
Mainframe/Midrange                  Accounting/Customer   Completed Throughout 1999
systems          service integrated
                 systems

Desktop systems  Personal computers/            June 30, 1999       Throughout 1999
                 Department software/
                 Networks

Operational/     Dispatching systems/           June 30, 1999       Throughout 1999
Embedded         Transmission and
systems          Distribution systems/
                 Telephone systems

External issues  Electronic Data    June 30, 1999         Throughout 1999
                 Interchange/Vendor
                 communications
</TABLE>

  The NEES companies are using a three-phase approach in
coordinating their Y2K Project for system-related issues: (I)
Assessment and Inventory, (II) Pilot Testing, and (III) Renovation,
Conversion, or Replacement of Application and Operating Software
Packages and Testing. Phase I, which was an initial assessment of
all systems and devices for potential Y2K defects, was completed in
mid-1997. These assessments included, but were not limited to, the
review of program code for mainframe and midrange systems, analysis
of personal computer hardware and network equipment for desktop
systems, reaching consensus with key "data exchange" partners
regarding the approach and execution of plans to address Y2K-
related issues, and coordination with other New England Power Pool
(NEPOOL) member utilities related to operational systems, such as
transmission systems.  Phase II, which consisted of renovation
pilots for a cross-section of systems in order to facilitate the
establishment of templates for Phase III work, was completed in
late 1997. Phase III, which is currently ongoing, requires the
renovation, conversion, or replacement of the remaining
applications and operating software packages.

  Critical systems include major operational and informational
systems such as the NEES companies' financial-related and customer
information systems.  These mission critical systems were first
addressed at an individual component level, and then, upon
satisfactory completion of that testing, reviewed at an integrated
level, during which the Y2K Project team tested for Y2K problems
<PAGE>
which could be caused by various system interfaces.  Additionally,
contingency plans are being formulated for mission critical
systems, as described below.

  The overall Y2K Project has also been designed such that Y2K-
related work performed by external consultants is reviewed by NEES
employees, and vice-versa.  The Y2K Project team management
periodically benchmarks its progress against the recommended
progress schedule documented by the North American Electric
Reliability Council (NERC), and is currently ahead of the
recommended schedule.

  The NEES companies have also implemented a formalized
communication process with third parties to give and receive
information related to their progress in remediating their own Y2K
issues, and to communicate the NEES companies' progress in
addressing the Y2K issue. These third parties include major
customers, suppliers, and significant businesses with which the
NEES companies have data links (such as banks). The NEES companies
have identified standard offer generation service providers,
telecommunications companies, and the Independent System Operator-
New England (ISO New England) as critical to business operations. 
The NEES companies have been in contact with all of these parties
regarding the progress of their Y2K remediation efforts, and will
continue to monitor their ongoing remediation efforts through
continued communications. The NEES companies cannot predict the
outcome of other companies' remediation efforts.  Therefore,
contingency plans are being developed, as described below.

  The NEES companies believe total costs associated with making the
necessary modifications to all centralized and noncentralized
systems will be approximately $28 million. These costs include the
replacement of approximately one thousand desktop computers. In
addition, the NEES companies are spending $7 million related to the
replacement of the human resources and payroll system, in part due
to the Y2K issue. As of March 31, 1999, total Y2K-related costs of
approximately $30 million have been incurred, of which
approximately $4 million has been capitalized.  The NEES companies
continually review their cost estimates based upon the overall Y2K
Project status, and update these estimates as warranted.

  The NEES companies are in the process of developing Y2K
contingency plans to allow for critical information and operating
systems to function from January 1, 2000 forward. If required,
these plans are intended to address both internal risks as well as
potential external risks related to suppliers and customers. Part
of the contingency planning for accounting and desktop systems will
include taking extensive data back-ups prior to year-end closing.
For operational systems, the NEES companies have in place an
overall disaster recovery program, which already includes periodic
disaster simulation training (for outages due to severe weather,
for instance). As part of Y2K contingency planning, the NEES

<PAGE>
companies will review their disaster recovery plans, modifying them
for Y2K-specific issues, such as a potential loss of
telecommunication services. The NEES companies expect that these
contingency plans will be in place by the third quarter of 1999.

  Interregional and regional contingency plans are being formulated
that address emergency scenarios due to the interconnection of
utility systems throughout the United States. At a regional level,
the NEES companies are participating and cooperating with NEPOOL
and ISO New England. Overall regional activities, including those
of NEPOOL and ISO New England, will be coordinated by the Northeast
Power Coordinating Council, whose activities will be incorporated
into the interregional coordinating effort by NERC. The target for
the completion of this planning process is mid-1999. The NEES
companies have noted that the Y2K coordination efforts by ISO New
England began in May 1998, resulting in a demanding and difficult
schedule to attain regional and interregional target dates.

  The NEES companies believe that the contingency plans being
developed both internally and on a regional level should
substantially mitigate the risks of Y2K-related failures at NEES
company facilities or those caused by the inability of entities,
such as ISO New England, to maintain the short-term reliability of
various generator and/or transmission lines on a regional or
interregional basis.  Such risks include temporary disruptions of
electric service, which the NEES companies believe is the worst
case Y2K scenario with a reasonable chance of occurring.  In the
event that a short-term disruption in service occurs, NEES does not
expect that it would have a material impact on its financial
position or results of operation.

  While the NEES companies believe that their overall Y2K program
will satisfactorily address all critical operational and
system-related issues, significant risks remain. These risks
include, but are not limited to, the Y2K readiness of third
parties, including other utilities, power suppliers, and ISO New
England, cost and timeline estimates of remaining Y2K mitigation
efforts, and the overall accuracy of assumptions made related to
future events in the development of the Y2K mitigation effort.

Earnings
--------

  Net income for the first quarter of 1999 increased $1 million 
compared with the corresponding period in 1998.  The increase is
due primarily to a distribution rate increase implemented in March
1998 and increased kilowatthour (kWh) deliveries of 3.2 percent. 
These increases were partially offset by increased operation and
maintenance expenses, depreciation expense, and property tax
expense.


<PAGE>
Operating Revenue
-----------------

  Operating revenue decreased $52 million in the first quarter of
1999 compared with the corresponding period in 1998 reflecting
lower purchased power rates pursuant to the Massachusetts
Settlement implemented in March 1998.  Commencing in March 1998,
the revenues that the Company was billing related to contract
termination charges (CTC) from New England Power Company (NEP),
purchased power costs, and transmission wheeling costs became
subject to fully reconciling true-up mechanisms based on actual NEP
billings.  Prior to March 1998, only the fuel component of
purchased power expense was subject to a similar fully reconciling
true-up mechanism.  The decrease in 1999 operating revenue was 
offset by a $41 million distribution rate increase in accordance
with the Massachusetts Settlement, as well as a 3.2 percent
increase in kWh deliveries as a result of a continued strong
economy and the effect of weather.  

Operating Expenses
------------------

  Operating expenses for the first quarter of 1999 decreased $53
million compared with the corresponding period in 1998, primarily
due to reduced purchased electric energy expenses.  The decrease in
purchased electric energy due to the lower rates from power
suppliers is partially offset by the implementation of CTC billing
from NEP which commenced in March 1998.  The decrease is also
partially offset by increased operation and maintenance costs,
increased depreciation expense, and increased property tax expense. 

  The decrease in purchased electric energy is principally due to
reduced rates billed to the Company by suppliers. Historically, the
Company purchased all of its electrical requirements from NEP under
the provisions of an all-requirements contract at NEP's standard
resale rate.  Effective March 1, 1998, the contract was amended,
terminating the all-requirements provision of the contract and
resulting in CTCs, the fixed portion of which the Company will pay
monthly to NEP through the end of 2000.  The Company's customers
also gained the right to choose their power supplier.  NEP
continued to supply power to the Company, at lower rates, for
customers that continued to take power from the Company, until
September 1, 1998, when USGen New England, Inc., an indirect wholly
owned subsidiary of PG&E Corporation, and TransCanada Power
Marketing, Ltd. became the Company's principal wholesale power
suppliers.

  The increase in other operation and maintenance expenses is
primarily due to increased transmission billings from NEP of
approximately $22 million which, prior to March 1, 1998, were a
component of purchased power expense.  These transmission expenses
are included as part of the transmission true-up mechanism as
<PAGE>
discussed in the "Operating Revenue" section. The increase in
operation and maintenance expenses is also due to costs associated
with year 2000 computer readiness allocated to the Company and
increased healthcare costs.  

  The increase in depreciation expense in the first quarter of 1999
primarily reflects a portion of the $11 million increase in annual
depreciation expense provided for in the Massachusetts Settlement,
which went into effect on March 1, 1998, and depreciation expense
on new utility plant expenditures. 

Other Income
------------

  The increase in other income reflects the impact of a $1.3
million write-off of loss on reacquired debt in the first quarter
of 1998.

Utility Plant Expenditures and Financing
----------------------------------------

  Cash expenditures for utility plant totaled $20 million for the
first three months of 1999.  The funds necessary for utility plant
expenditures during the period were primarily provided by net cash
from operating activities, after the payment of dividends.

  At March 31, 1999, the Company had $37 million of short-term debt
outstanding representing borrowings from affiliates.  The Company's
ability to issue short-term debt is limited by the need to obtain
regulatory approval from the SEC under the Public Utility Holding
Company Act of 1935.  Approval has been granted for up to $150
million. At March 31, 1999, the Company had lines of credit with
banks totaling $55 million which are available to provide liquidity
support for commercial paper borrowings and other corporate
purposes.  There were no borrowings under these lines of credit at
March 31, 1999.

  For the twelve-month period ending March 31, 1999, the ratio of
earnings to fixed charges was 3.52.
<PAGE>
                   PART II. OTHER INFORMATION

Item 1.  Legal Proceedings
--------------------------

     Information concerning a rate filing by the Company with the
Massachusetts Department of Telecommunications and Energy on
April 30, 1999, discussed in Part I of this report in
Management's Discussion and Analysis of Financial Condition and
Results of Operations, is incorporated herein by reference and
made a part hereof.

Item 4.  Submission of Matters to a Vote of Security-Holders
------------------------------------------------------------

     On March 17, 1999, the Annual Meeting of Stockholders was
held.  The following actions were taken by the unanimous vote of
the 2,398,111 shares having general voting rights represented at
the meeting:

     The number of directors was fixed at seven.

     The following were elected as directors of the Company:

     Cheryl A. LaFleur
     Robert L. McCabe
     Lydia M. Pastuszek
     Lawrence J. Reilly
     Christopher E. Root
     Nancy H. Sala
     Richard P. Sergel
     
     John G. Cochrane was elected Treasurer and Geraldine M.
Zipser was elected Clerk.

     PricewaterhouseCoopers was selected as auditor for 1999.

Item 6.  Exhibits and Reports on Form 8-K
-----------------------------------------

     The Company is filing the following revised exhibit for
incorporation by reference into its registration statement on
Form S-3, Commission File No. 33-59145.

     12   Statement re computation of ratios

     The Company is filing Financial Data Schedules.
     
     The Company filed reports on Form 8-K dated February 1,
1999, and March 31, 1999, containing Items 5 and 7 and Item 7,
respectively.

<PAGE>
                            SIGNATURE

   Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report on Form 10-Q
for the quarter ended March 31, 1999 to be signed on its behalf
by the undersigned thereunto duly authorized.

                              MASSACHUSETTS ELECTRIC COMPANY


                              s/John G. Cochrane
                                                            
                              John G. Cochrane, Treasurer,
                              Authorized Officer, and 
                              Principal Financial Officer

Date: May 17, 1999