<PAGE>












Annual Report 1998
Massachusetts Electric Company

A Subsidiary of
New England Electric System


























                              [LOGO] Massachusetts Electric
                              A NEES Company
<PAGE>
Massachusetts Electric Company
55 Bearfoot Road, 
Northborough, Massachusetts 01532

Directors
(As of January 1, 1999)

Cheryl A. LaFleur
Senior Vice President, General Counsel, and Secretary of New
England Electric System

Robert L. McCabe
Chairman of the Company and of certain affiliates

Lydia M. Pastuszek
Senior Vice President of the Company
and of certain affiliates

Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates

Christopher E. Root
Senior Vice President of the Company
and of certain affiliates

Richard P. Sergel
President and Chief Executive Officer of New England Electric
System

Nancy H. Sala
Senior Vice President of the Company and of an affiliate

Officers
(As of January 1, 1999)

Robert L. McCabe
Chairman of the Company and of certain affiliates

Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates

Lydia M. Pastuszek
Senior Vice President of the
Company and of certain affiliates

Christopher E. Root
Senior Vice President of the Company and of certain affiliates

Nancy H. Sala
Senior Vice President of the Company
and of an affiliate

William J. Flaherty
Vice President of the Company
<PAGE>
Andrea Foley-Stapleford
Vice President of the Company

Richard W. Frost
Vice President of the Company and of certain affiliates

Rita A. Moran
Vice President of the Company

Joseph D. Newman
Vice President of the Company

Kwong O. Nuey
Vice President of the Company

Timothy R. Roughan
Vice President of the Company

William T. Sherry
Vice President of the Company

John G. Upham II
Vice President of the Company

John G. Cochrane
Treasurer of the Company and of certain affiliates, Assistant
Treasurer of an affiliate, Vice President of an affiliate and
Treasurer of New England Electric System

Thomas G. Robinson
Assistant Clerk and General Counsel of the Company

Robert King Wulff
Clerk of the Company and of certain affiliates, Secretary or
Assistant Clerk of certain affiliates and Assistant Secretary of
an affiliate

Howard W. McDowell
Assistant Treasurer and Controller of the Company and of certain
affiliates, Senior Vice President of an affiliate, Treasurer or
Controller of certain affiliates and Assistant Secretary of an
affiliate


Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, State Street Bank and Trust Company, Boston, Massachusetts

This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.
<PAGE>
Massachusetts Electric Company

  Massachusetts Electric Company (the Company) is a wholly owned
subsidiary of New England Electric System (NEES) operating in
Massachusetts.  The Company's business is the distribution of
electricity at retail.  Electric service is provided to
approximately 980,000 customers in 146 cities and towns having a
population of approximately 2,160,000 (1990 Census).  The
Company's service area covers approximately 43 percent of
Massachusetts.  The cities and towns served by the Company
include the highly diversified commercial and industrial cities
of Worcester, Lowell, and Quincy, the Interstate 495 high
technology belt, and many suburban communities and rural towns. 
The principal industries served include computer manufacturing
and related businesses, electrical and industrial machinery,
plastic goods, fabricated metals and paper, and chemical
products.  In addition, a broad range of professional, banking,
medical, and educational institutions is served.  As described in
the "Industry Restructuring" section of Financial Review, all
customers gained the right to choose their power supplier
effective March 1, 1998.

  The properties of the Company consist principally of
substations and distribution lines interconnected with
transmission and other facilities of New England Power Company,
the Company's transmission affiliate.  In September 1998, NEES
completed the divestiture of substantially all of its nonnuclear
generating business.  For further information on industry
restructuring and the divestiture of NEES' nonnuclear generating
business, refer to the "Industry Restructuring" section of
Financial Review.

  In December 1998, NEES agreed to a merger with The National
Grid Group plc, whose principal subsidiary operates the
transmission system in England and Wales.

  In February 1999, NEES entered into an agreement to acquire
Eastern Utilities Associates, a utility holding company serving
approximately 300,000 customers in Massachusetts and Rhode
Island. For further information on these proposed mergers, refer
to the "Merger Agreements" sections of Financial Review.
<PAGE>
Report of Independent Accountants

Massachusetts Electric Company, Westborough, Massachusetts:

  In our opinion, the accompanying balance sheets and the
related statements of income, of retained earnings, and of cash
flows present fairly, in all material respects, the financial
position of Massachusetts Electric Company (the Company), a
wholly owned subsidiary of New England Electric System, at
December 31, 1998 and 1997, and the results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted
accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is
to express an opinion on these financial statements based on our
audits. We conducted our audits of these statements in accordance
with generally accepted auditing standards which require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed
above.




Boston, Massachusetts           PricewaterhouseCoopers LLP
February 23, 1999


<PAGE>
Massachusetts Electric Company
Financial Review

  Merger Agreement with The National Grid Group plc

  On December 11, 1998, New England Electric System (NEES), The
National Grid Group plc (National Grid), and NGG Holdings LLC
(Holdings), a directly and indirectly wholly owned subsidiary of
National Grid, entered into an Agreement and Plan of Merger
(Merger Agreement). Pursuant to the Merger Agreement, Holdings
will merge with and into NEES (the Merger), with NEES becoming a
wholly owned subsidiary of National Grid. Massachusetts Electric
Company (the Company) will remain a wholly owned subsidiary of
NEES.

  The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the
Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), Federal Energy
Regulatory Commission (FERC), and Nuclear Regulatory Commission
(NRC), support or approval from the states in which NEES
subsidiaries operate, and clearance under both the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.

  Merger Agreement with Eastern Utilities Associates

  On February 1, 1999, NEES, Eastern Utilities Associates (EUA),
and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES.

  The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000.  Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.

  Industry Restructuring

  Pursuant to legislation enacted in Massachusetts and
settlement agreements approved by state and federal regulators
(Massachusetts Settlement), all customers were provided the right
to purchase electricity from the power supplier of their choice 
<PAGE>
effective March 1, 1998. Customers who do not choose a power
supplier are able, for a period of time, to continue to purchase
their electricity from the Company at a transition rate
("standard offer generation service") which, when combined with
delivery charges, results in a total rate reduction of 19 percent
compared with the rates that had been in effect in August 1997.  

  In addition to addressing customer choice, the Massachusetts
Settlement also required the NEES companies to divest their
nonnuclear generating business.  On September 1, 1998, NEES
subsidiaries New England Power Company (NEP) and The Narragansett
Electric Company completed the sale of substantially all of their
nonnuclear generating business, all of which had a book value of
approximately $1.1 billion, to USGen New England, Inc. (USGen),
an indirect wholly owned subsidiary of PG&E Corporation. The NEES
companies received $1.59 billion for the sale.  Effective
September 1, 1998, USGen and TransCanada Power Marketing, Ltd.
(TCPM) became the Company's principal suppliers for meeting
standard offer generation service obligations.

  The Massachusetts Settlement also provides that the costs of
NEP's generating investments and related contractual commitments
that were not recovered from the divestiture of those investments
("stranded costs") (the Company's share is 73 percent) are to be
recovered from distribution customers through contract
termination charges (CTC), which will be collected by the
Company. Under the Massachusetts Settlement, the recovery of
NEP's stranded costs is divided into several categories.
Unrecovered costs associated with generating plants (nuclear and
nonnuclear) and most regulatory assets will be fully recovered
through the CTC by the end of 2000 and would earn a return on
equity of 9.4 percent. NEP's obligation relating to the
above-market cost of purchased power contracts and nuclear
decommissioning costs are recovered through the CTC over a longer
period of time, as such costs are actually incurred. NEP's CTC
rate was originally set at 2.8 cents per kilowatthour (kWh), and
subsequently reduced to approximately 1.5 cents or less per kWh
upon completion of the sale of NEP's nonnuclear generating
business as described above. 

  Accounting Implications

  Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. 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 December 31, 1998, the Company had
approximately $38 million in net regulatory assets.

  Under existing ratemaking practices and provisions of the
Massachusetts Settlement, the Company will have the ability to 
<PAGE>
recover through rates its specific costs of providing ongoing
distribution services and stranded costs billed to it by NEP. 
The Company believes these factors will allow it to continue to
apply FAS 71.
  
  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. 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.

  Impact of Restructuring on Distribution Business

  The Massachusetts Settlement also establishes distribution
rates for the Company. On March 1, 1998, the Company's
distribution rates were set at a level approximately $45 million
above the level embedded in its previously bundled rates, with
such rates then frozen through the year 2000. This increase
reflects changes to the distribution cost of service, including
an $11 million increase in annual depreciation expense, a $3
million annual contribution to a storm fund, and increased annual
amortization of unfunded deferred income taxes of approximately
$1 million over six years. Through the year 2000, the Company's
return on equity is subject to a floor of 6 percent and a ceiling
of 11 percent. Earnings over the ceiling will be shared equally
between customers and shareholders up to a maximum of 12.5
percent. This sharing results in an effective cap on the
Company's return on equity of 11.75 percent, excluding certain
limited incentive opportunities. To the extent that earnings fall
below the floor, the Company will be authorized to surcharge
customers for the shortfall.

  Overview of Financial Results

  Net income for 1998 decreased $15 million compared with 1997. 
The decrease was primarily due to the decreases in revenues
related to the recovery of purchased power and transmission costs
being greater than the decreases in the related expenses.  This
amounted to approximately $35 million, before tax, and was in
part due to the reversal in 1997 of prior period refund accruals
related to the Company's purchased power cost adjustment
mechanism (PPCA).  It was also in part due to 1998 being a
transition year to new fully reconciling rate mechanisms for
purchased power and transmission costs as well as CTC costs
billed by NEP.  Increases in depreciation and property tax
expenses of $12 million and $7 million, respectively, also
contributed to the decrease.  These decreases in income were
partially offset by the effects of a distribution rate increase
that went into effect in March 1998.

  Net income for 1997 increased $28 million compared with 1996. 
The increase was primarily due to the reversal of prior period
refund accruals and a 2.0 percent increase in kWh deliveries.  
<PAGE>
Partially offsetting the higher earnings were increased operation
and maintenance costs, increased depreciation, and increased
income taxes.

  Operating Revenue

  Operating revenue decreased $134 million in 1998 compared with
1997 reflecting lower purchased power related rates pursuant to
the Massachusetts Settlement and a change in true-up mechanisms.
Rates were reduced by 10 percent in March 1998, and an additional
9 percent in September 1998 in conjunction with the sale of NEES'
nonnuclear generating assets, compared with rates that had been
in effect in August 1997. Commencing in March 1998, the revenues
that the Company is billing related to purchased power costs,
transmission wheeling costs and CTC charges from NEP, are all
subject to fully reconciling true-up mechanisms based on actual
billings.  Prior to March, only the fuel component of purchased
power expense was subject to a similar fully reconciling true-up
mechanism.  The decrease in 1998 operating revenue was partially
offset by a 1.0 percent increase in kWh deliveries.  The increase
in kWh deliveries reflects a strong economy.  For the year as a
whole, weather had a negative impact on 1998 deliveries when
compared with 1997.   

  Operating revenue increased $86 million in 1997 compared with
1996, and reflected the reversal of the prior period refund
accruals related to rate mechanisms referred to above, and
increased kWh deliveries due to an improved economy.  The
Massachusetts Settlement provided for the end of the Company's
PPCA mechanism effective July 31, 1996.  Prior to FERC approval,
the Company had accrued additional potential refund provisions of
$9 million for the last five months of 1996 and $7 million for
the first nine months of 1997.  Upon approval of the settlement,
these refund provisions were all reversed in the fourth quarter
of 1997, thereby increasing revenues.  The Company had accrued
refund provisions of $17 million during the first seven months of
1996, which were part of a net $18 million PPCA balance at July
31, 1996.

  The Company received approval from the Massachusetts
Department of Telecommunications and Energy (MDTE) to recover
demand-side management (DSM) program expenditures in rates on a
current basis through 1998.  These expenditures were $46 million,
$51 million, and $48 million in 1998, 1997, and 1996,
respectively.  The Massachusetts Settlement and statute provide
for recovery of DSM-related costs.  The MDTE approved the
Company's DSM program expenditure recovery plans through 2002. 
Since 1990, the Company has been allowed to earn incentives based
on the results of its DSM programs and has recorded before-tax
incentives of $6.6 million, $7.0 million, and $5.7 million in
1998, 1997, and 1996, respectively.

  Operating Expenses

  Operating expenses for 1998 decreased $120 million compared
with 1997 primarily due to reduced purchased electric energy 
<PAGE>
expenses, partially offset by CTC billings, 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.  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 and TCPM became the Company's
principal wholesale power suppliers.  The increase in other
operation and maintenance expenses is primarily due to increased
transmission costs of approximately $76 million which, as of
March 1, 1998 are billed separately and recorded as operation and
maintenance expense instead of as a component of purchased power
expense.  The increase in operation and maintenance expenses is
also due to costs associated with year 2000 (Y2K) computer
readiness.  These increases were offset by decreased DSM spending
and the effects of workforce reductions.  The increase in
depreciation expense in 1998 primarily reflects a portion of the
$11 million increase in annual depreciation expense provided for
in the Massachusetts Settlement, and depreciation expense on new
utility plant expenditures. The increase in taxes, other than
income taxes reflects one-time property tax adjustments paid in
the third quarter of 1998 to certain municipalities.

  Operating expenses for 1997 increased $56 million compared
with 1996 primarily due to increased purchased power expenses,
increased other operation and maintenance expenses and increased
income taxes.  The increase in purchased electric energy expenses
was due to increased replacement power fuel purchases by NEP due
to the reduced generation from partially owned nuclear units. 
These costs were passed on to the Company through NEP's fuel
clause.  The increase in other operation and maintenance expenses
was primarily due to increased distribution-system related costs,
including increased tree-trimming expenses, as well as increased
transmission wheeling charges from NEP related to the use of
NEP's transmission network for the Company's 1997 retail wheeling
pilot programs.

  Hazardous Waste

  The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The most prevalent types of hazardous
waste sites with which the Company has been associated are
manufactured gas locations. (Until the early 1970s, NEES was a
combined electric and gas holding company system.) The Company is
aware of approximately 35 such manufactured gas locations,
including eight for which the Company has been identified by
either federal or state regulatory agencies as a potentially
responsible party, located in Massachusetts. The Company has
reported the existence of all manufactured gas locations of which 
<PAGE>
it is aware to state environmental regulatory agencies. The
Company is engaged in various phases of investigation and
remediation work at approximately 20 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. A more
detailed discussion of this settlement agreement and of potential
hazardous waste liabilities is contained in Note D-2 of the Notes
to the Financial Statements. Predicting the potential costs to
investigate and remediate hazardous waste sites continues to be
difficult. At December 31, 1998, the Company had total reserves
for environmental response costs of $44 million. 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.

  Year 2000 Readiness Disclosure

  Over the next 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 
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 International Business
Machines Corporation to provide personnel support to the Y2K
Project.  Through December 31, 1998, the NEES companies have
spent approximately $14 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 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
<PAGE>
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 $4 million related
to the replacement of the human resources and payroll system, in
part due to the Y2K issue. To date, total Y2K-related costs of
$25 million have been incurred, of which $3 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 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 
<PAGE>
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 the worst case scenario with a
reasonable chance of occurring is temporary disruptions of
electric service. This scenario could result from a failure to
adequately remediate Y2K problems at NEES company facilities or
could be caused by the inability of entities, such as ISO New
England, to maintain the short-term reliability of various
generators and/or transmission lines on a regional or
interregional basis. The NEES companies believe that the
contingency plans being developed both internally and on a
regional level, as described above, should substantially mitigate
the risks of this potential scenario. 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
and results of operations.

  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 and power suppliers, 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.

  New Accounting Standards

  In 1997, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards No. 130,
Reporting of Comprehensive Income (FAS 130), which was adopted by
the Company in the first quarter of 1998.  FAS 130 establishes
standards for reporting comprehensive income and its components. 
Comprehensive income for the period is equal to net income plus
"other comprehensive income," which for the Company, consists of
the change in unrealized holding gains on available-for-sale
securities during the period.  Other comprehensive income was
immaterial for the Company for the year ended December 31, 1998.

  Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.

<PAGE>
  In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ended December 31, 1998.

  The adoption of FAS 130, FAS 131, and FAS 132 had no impact on
the Company's operating results, financial position, or cash
flows.

  In June 1998, the FASB 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. 
Currently, the Company has no such derivative holdings.

  Risk Management

  The Company's major financial market risk exposure is changing
interest rates. Changing interest rates will affect the fair
value of fixed rate debt. The table below presents the average
rate on the Company's long-term debt at December 31, 1998, the
amounts maturing during each of the next five years, and the fair
value of the Company's debt at December 31, 1998.
<TABLE>
<CAPTION>
                                                Fixed
                                              Long-Term
                                              ---------
<S>                                   <C>
Weighted
Average Rate                                    7.20%

Maturities                    (millions of dollars)

1999                                           $ 15
2000                                             21
2001                                              -
2002                                             25
2003                                             35
Cumulative
 thereafter                                     274
                                               ----
Total                                          $370
                                               ----
Fair Value                                     $403
                                               ----
</TABLE>
  Utility Plant Expenditures and Financing

  Cash expenditures for utility plant totaled $78 million in
1998.  The funds necessary for utility plant expenditures during
1998 were primarily provided by net cash from operating
activities, after the payment of dividends, and increased short-
<PAGE>
term debt.  Cash expenditures for utility plant for 1999 are
estimated to be approximately $75 million.  Internally generated
funds are expected to fully meet capital expenditure requirements
in 1999.

  In 1998, the Company issued $50 million of long-term debt,
retired $40 million of mortgage bonds and increased its short-
term debt outstanding by $46 million.  

  In 1998, the Company repurchased or redeemed preferred stock
with an aggregate par value of $5.1 million.  Total premiums paid
of $0.2 million in connection with the preferred stock repurchase
and redemption were charged to retained earnings. 

  At December 31, 1998, the Company had $81 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 1935
Act.  Approval has been granted for up to $150 million. As of
December 31, 1998, the Company had lines of credit with banks
totaling $55 million which are available to provide liquidity
support for commercial paper borrowings and other commercial
purposes.  There were no borrowings under these lines of credit
at December 31, 1998.
<PAGE>
<TABLE>
<CAPTION>

Massachusetts Electric Company
Statements of Income

Year ended December 31, (In thousands)   1998        1997        1996
-----------------------------------------------------------------------------------
<S>                                         <C>              <C>                 <C>
Operating revenue                       $1,490,417  $1,624,085 $1,538,537
                                        ----------  ---------- ----------
Operating expenses:
 Purchased electric energy (Note A):
  Contract termination charges from New
   England Power Company, an affiliate     300,630           -          -
  Other                                    640,110   1,145,047  1,120,709
 Other operation                           292,509     217,150    211,663
 Maintenance                                33,522      36,906     31,102
 Depreciation                               61,700      49,694     47,357
 Taxes, other than income taxes             37,983      31,143     30,559
 Income taxes                               36,319      42,454     25,186
                                        ----------  ---------- ----------
   Total operating expenses              1,402,773   1,522,394  1,466,576
                                        ----------  ---------- ----------

Operating income                            87,644     101,691     71,961

Other income (expense), net                 (3,510)     (1,536)    (1,213)
                                        ----------  ---------- ----------
   Operating and other income               84,134     100,155     70,748
                                        ----------  ---------- ----------
Interest:
 Interest on long-term debt                 27,073      27,612     27,089
 Other interest                              7,368       7,214      6,473
 Allowance for borrowed funds used during 
  construction - credit                       (693)       (429)      (740)
                                        ----------  ---------- ----------
   Total interest                           33,748      34,397     32,822
                                        ----------  ---------- ----------
Net income                              $   50,386  $   65,758 $   37,926
                                        ==========  ========== ==========

Statements of Retained Earnings

Year ended December 31, (In thousands)        1998        1997       1996
-----------------------------------------------------------------------------------
Retained earnings at beginning of year    $201,156    $165,936   $150,308
Net income                                  50,386      65,758     37,926
Dividends declared on cumulative
 preferred stock                              (873)     (2,821)    (3,114)
Dividends declared on common stock,
 $17.50, $10.00, and $8.00 per
 share, respectively                       (41,967)    (23,981)   (19,184)
Premium on redemption of preferred stock      (165)     (3,736)         -
                                          --------    --------   --------
Retained earnings at end of year          $208,537    $201,156   $165,936
                                          ========    ========   ========
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Massachusetts Electric Company
Balance Sheets

At December 31, (In thousands)                             1998       1997
------------------------------------------------------------------------------
<S>      <C>                                                <C>
Assets
Utility plant, at original cost                 $1,626,569 $1,579,309
Less accumulated provisions for depreciation       499,975    465,796
                                                ---------- ----------
                                                 1,126,594  1,113,513
Construction work in progress                       16,575     13,363
                                                ---------- ----------
   Net utility plant                             1,143,169  1,126,876
                                                ---------- ----------
Current assets:  
Cash                                                 6,994      6,743
Accounts receivable:
 From electric energy services                     188,956    158,627
 Other (including $6,629 and $1,321 from affiliates) 7,358      2,112
   Less reserves for doubtful accounts              12,450     12,808
                                                ---------- ----------
                                                   183,864    147,931
 Unbilled revenues (Note A-3)                       56,133     49,513
 Materials and supplies, at average cost             9,281      9,599
 Prepaid and other current assets                   13,886     22,255
                                                ---------- ----------
   Total current assets                            270,158    236,041
                                                ---------- ----------
Deferred charges and other assets (Note C)          41,235     45,450
                                                ---------- ----------
                                                $1,454,562 $1,408,367
                                                ========== ==========
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     45,945
 Other paid-in capital                             193,498    193,224
 Retained earnings                                 208,537    201,156
 Unrealized gain on securities, net                    273        129
                                                ---------- ----------
   Total common equity                             508,203    500,407
 Cumulative preferred stock (Note H)                10,674     15,739
 Long-term debt                                    353,329    338,387
                                                ---------- ----------
   Total capitalization                            872,206    854,533
                                                ---------- ----------
Current liabilities:
 Long-term debt due in one year                     15,000     20,000
 Short-term debt (including $80,725 and $4,800
  to affiliates)                                    80,725     34,700
 Accounts payable (including $34,506 and $179,211
  to affiliates)                                   127,621    195,023
 Accrued liabilities:
  Taxes                                                  -      8,275
  Interest                                           8,509      9,183
  Other accrued expenses (Note G)                   40,626     22,081
 Customer deposits                                   4,456      4,487
 Dividends payable                                   4,951      5,036
                                                ---------- ----------
   Total current liabilities                       281,888    298,785
                                                ---------- ----------
Deferred federal and state income taxes            200,965    179,474
Unamortized investment tax credits                  14,377     15,463
Other reserves and deferred credits                 85,126     60,112
Commitments and contingencies (Note D)
                                                ---------- ----------
                                                $1,454,562 $1,408,367
                                                ========== ==========
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
Massachusetts Electric Company
Statements of Cash Flows
<TABLE>
<CAPTION>
Year ended December 31, (In thousands)          1998       1997           1996
-----------------------------------------------------------------------------
<S>                                                         <C>            <C>                           <C>
Operating activities:                               
Net income                                  $ 50,386   $ 65,758            $ 37,926
Adjustments to reconcile net income to net
  cash provided by operating activities:
  Depreciation                                61,700     49,694              47,357
  Deferred income taxes and investment
   tax credits, net                           22,280        478              (7,850)
  Allowance for borrowed funds
   used during construction                     (693)                (429)          (740)
  Amortization of unbilled revenues                                                
  Decrease (increase) in accounts
   receivable, net and unbilled revenues     (42,553)               1,266          2,868
  Decrease (increase) in materials
   and supplies                                  318       (779)              1,782
  Decrease (increase) in prepaid
   and other current assets                    8,369      3,668              (3,409)
  Increase (decrease) in accounts payable               (67,402)             16,760              (3,680)
  Increase (decrease) in other
   current liabilities                         9,565    (25,711)             31,095
  Other, net                                  31,281     36,902              (2,430)
                                            --------   --------            --------
   Net cash provided by
    operating activities                    $ 73,251   $147,607            $102,919
                                            --------   --------             -------
Investing activities:
Plant expenditures, excluding allowance
 for funds used during construction         $(77,588)            $(87,998)      $(93,828)
Other investing activities                    (3,557)              (1,408)          (598)
                                            --------   --------            --------
   Net cash used in investing activities    $(81,145)            $(89,406)      $(94,426)
                                            --------   --------            --------
Financing activities:
Capital contributions from parent           $    274   $ 37,914            $      -
Dividends paid on common stock               (41,967)             (26,380)       (13,188)
Dividends paid on preferred stock               (958)              (3,359)        (3,114)
Long-term debt - issues                       50,000     15,000              20,000
Long-term debt - retirements                 (40,000)             (30,000)             -
Preferred stock - retirements                 (5,064)             (34,178)             -
Premium on redemption of preferred stock        (165)              (3,736)             -
Changes in short-term debt                    46,025     (9,075)            (11,675)
                                            --------   --------            --------
   Net cash provided by(used in)
    financing activities                    $  8,145   $(53,814)           $ (7,977)
                                            --------   --------            --------
Net increase in cash and cash equivalents              $    251            $  4,387            $    516
Cash and cash equivalents at
 beginning of year                             6,743      2,356               1,840
                                            --------   --------            --------
Cash and cash equivalents at end of year    $  6,994   $  6,743            $  2,356
                                            ========   ========            ========
Supplementary information:
Interest paid less amounts capitalized      $ 30,364   $ 31,251            $ 30,569
                                            --------   --------            --------
Federal and state income taxes paid         $ 34,111   $ 31,711            $ 39,174
                                            --------   --------            --------
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
Massachusetts Electric Company
Notes to Financial Statements

Note A - Significant Accounting Policies

1. Nature of Operations:

   Massachusetts Electric Company (the Company) is a wholly
owned subsidiary of New England Electric System (NEES) operating
in Massachusetts.  The Company's business is the distribution of
electricity at retail.  Electric service is provided to
approximately 980,000 customers in 146 cities and towns having a
population of approximately 2,160,000 (1990 Census).  The
Company's service area covers approximately 43 percent of
Massachusetts.  The properties of the Company consist principally
of substations and distribution lines interconnected with
transmission and other facilities of New England Power Company
(NEP), the Company's transmission affiliate.  Under an all-
requirements contract with NEP, the Company had previously
purchased all of its electric energy requirements from NEP under
a contract which obligated NEP to furnish such requirements at
its standard resale rate.  This contract has been amended to
terminate the all-requirements provision of the contract and 
allow NEP to recover its above-market generation commitments
through a contract termination charge (CTC), which the Company
collects from its customers.  See Note C for a discussion of
industry restructuring and NEES' divestiture of its nonnuclear
generating business.

2. System of Accounts:

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

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

3. Electric Utility Revenue:

   The Company accrues revenues for electricity delivered but
not yet billed (unbilled revenues).  Accrued revenues are also
recorded in accordance with rate adjustment mechanisms, which, in
1997, included the Company's purchased power cost adjustment
(PPCA) mechanism.  Upon approval of the Massachusetts Settlement
in November 1997, the PPCA mechanism was eliminated as of July
31, 1996.  Pending final approval of the settlement, the Company
had accrued refund reserves of $9 million for the last five
months of 1996 and an additional $7 million in the first nine
months of 1997.  Upon final approval of the settlement, these
refund reserves were reversed in the fourth quarter of 1997.
<PAGE>
4. Allowance for Funds Used During Construction (AFDC):

   The Company capitalizes AFDC as part of construction costs. 
AFDC represents an allowance for the cost of funds used to
finance construction.  AFDC is capitalized in "Utility plant"
with offsetting noncash credits to "Interest." This method is in
accordance with an established rate-making practice under which a
utility is permitted a return on, and the recovery of, prudently
incurred capital costs through their ultimate inclusion in rate
base and in the provision for depreciation.

5. Depreciation:

   Depreciation is provided annually on a straight-line basis. 
The provision for depreciation as a percentage of weighted
average depreciable property was 3.9 percent in 1998 and 3.3
percent in 1997 and 1996.

6. Cash:

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

7. New Accounting Standards:

   In 1997, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards No. 130,
Reporting of Comprehensive Income (FAS 130), which was adopted by
the Company in the first quarter of 1998.  FAS 130 establishes
standards for reporting comprehensive income and its components. 
Comprehensive income for the period is equal to net income plus
"other comprehensive income," which for the Company, consists of
the change in unrealized holding gains on available-for-sale
securities during the period.  Other comprehensive income was
immaterial for the Company for the year ended December 31, 1998.

   Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.

   In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ended December 31, 1998.

   The adoption of FAS 130, FAS 131, and FAS 132 had no impact
on the Company's operating results, financial position, or cash
flows. 

<PAGE>
   In June 1998, the FASB 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. 
Currently, the Company has no such derivative holdings.

Note B - Merger Agreements

   Merger Agreement with The National Grid Group plc

   On December 11, 1998, NEES, The National Grid Group plc
(National Grid), and NGG Holdings LLC (Holdings), a directly and
indirectly wholly owned subsidiary of National Grid, entered into
an Agreement and Plan of Merger (Merger Agreement). Pursuant to
the Merger Agreement, Holdings will merge with and into NEES (the
Merger), with NEES becoming a wholly owned subsidiary of National
Grid. The Company will remain a wholly owned subsidiary of NEES. 

   The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the
Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), Federal Energy
Regulatory Commission (FERC), and Nuclear Regulatory Commission
(NRC), support or approval from the states in which NEES
subsidiaries operate, and clearance under both the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.

   Merger Agreement with Eastern Utilities Associates

   On February 1, 1999, NEES, Eastern Utilities Associates
(EUA), and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES. 

   The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000.  Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.

<PAGE>
Note C - Industry Restructuring

   Pursuant to legislation enacted in Massachusetts and
settlement agreements approved by state and federal regulators
(Massachusetts Settlement), all customers were provided the right
to purchase electricity from the power supplier of their choice
effective March 1, 1998. Customers who do not choose a power
supplier are able, for a period of time, to continue to purchase
their electricity from the Company at a transition rate
("standard offer generation service") which, when combined with
delivery charges, results in a total rate reduction of 19 percent
compared with the rates that had been in effect in August 1997.

   In addition to addressing customer choice, the Massachusetts
Settlement also required the NEES companies to divest their
nonnuclear generating business.  On September 1, 1998, NEES
subsidiaries NEP and The Narragansett Electric Company completed
the sale of substantially all of their nonnuclear generating
business, all of which had a book value of approximately $1.1
billion, to USGen New England, Inc. (USGen), an indirect wholly
owned subsidiary of PG&E Corporation. The NEES companies received
$1.59 billion for the sale. Effective September 1, 1998, USGen
and TransCanada Power Marketing, Ltd. became the Company's
principal suppliers for meeting standard offer generation service
obligations.

   The Massachusetts Settlement also provides that the costs of
NEP's generating investments and related contractual commitments
that were not recovered from the divestiture of those investments
("stranded costs") (the Company's share is 73 percent) are to be
recovered from distribution customers through CTCs, which will be
collected by the Company. Under the Massachusetts Settlement, the
recovery of NEP's stranded costs is divided into several
categories. Unrecovered costs associated with generating plants
(nuclear and nonnuclear) and most regulatory assets will be fully
recovered through the CTC by the end of 2000 and would earn a
return on equity of 9.4 percent. NEP's obligation relating to the
above-market cost of purchased power contracts and nuclear
decommissioning costs are recovered through the CTC over a longer
period of time, as such costs are actually incurred. NEP's CTC
rate was originally set at 2.8 cents per kilowatthour (kWh), and
subsequently reduced to approximately 1.5 cents or less per kWh
upon completion of the sale of NEP's nonnuclear generating
business as described above. 

   Accounting Implications

   Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. 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 
<PAGE>
charges because they are expected to be included in future
customer charges. 

   Under existing ratemaking practices and provisions of the
Massachusetts Settlement, the Company will have the ability to
recover through rates its specific costs of providing ongoing
distribution services and stranded costs billed to it by NEP. 
The Company believes these factors will allow it to continue to
apply FAS 71.
   
   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. 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.

The components of regulatory assets are as follows:
<TABLE>
<CAPTION>
At December 31, (In thousands)                                                      1998                          1997
------------------------------------------------------------------------------
<S>                                                         <C>            <C>
Regulatory assets (liabilities) included
 in current assets and liabilities:                                           
 Rate adjustment mechanisms                            $ 24,913       $  2,960
                                                       --------       --------
Regulatory assets (liabilities) included
 in deferred charges and other reserves
 and deferred credits:
 Unamortized losses on reacquired debt                    6,424          6,939
 Deferred FAS No. 106 costs                               6,332          9,950
 Deferred FAS No. 109 costs                               6,307          8,275
 Environmental response costs                           (12,874)       (18,294)
 Deferred storm costs                                     6,447          8,108
 Other                                                        -            412
                                                       --------       --------
                                                         12,636         15,390
                                                       --------       --------
                                                       $ 37,549       $ 18,350
                                                       ========       ========
</TABLE>

Note D - Commitments and Contingencies

1. Plant Expenditures:

   The Company's utility plant expenditures are estimated to be
approximately $75 million in 1999.  At December 31, 1998,
substantial commitments had been made relative to future planned
expenditures.

2. 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 
<PAGE>
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.  NEES subsidiaries currently have in
place an internal environmental audit program and an external
waste disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous
products and by-products.

   The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
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, 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,
lease payments, and any recoveries from insurance carriers and
other third parties.  At December 31, 1998, 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 December
31, 1998, the Company had total reserves for environmental 
<PAGE>
response costs of $44 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 E - Employee Benefits

1. Pension Plans: 

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

Net pension cost for 1998, 1997, and 1996 included the following
components:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars)                     1998    1997      1996
-----------------------------------------------------------------------------------------
<S>                                                       <C>      <C>     <C>
Service cost - benefits earned during the period               $ 4,760$  4,474  $  4,429
Plus (less):
 Interest cost on projected benefit       obligation            18,176  17,413    16,935
 Return on plan assets at expected long-term rate              (21,379)(19,961)  (18,562)
 Amortization of transition obligation                            (658)   (660)     (656)
 Amortization of prior service cost                       417      465     462
 Amortization of net (gain)/loss                                   246     100       510
 Curtailment (gain)/loss                                 (465)       -       -
-----------------------------------------------------------------------------------------
   Benefit cost                                       $ 1,097 $  1,831$  3,118
-----------------------------------------------------------------------------------------
Special termination benefits not included above                $21,670$      -       $      -
-----------------------------------------------------------------------------------------
</TABLE>
<PAGE>
  The funded status of the plans cannot be presented separately
for the Company as the Company participates in the plans with
other NEES subsidiaries.  The following table sets forth the
funded status of the NEES companies' plans at December 31:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
(millions of dollars)                                                   1998           1997
---------------------------------------------------------------------------
<S>                                                                      <C>            <C>
Benefit obligation                                                      $843           $819
Unrecognized prior service costs                                          (6)            (8)
Transition liability not yet recognized (amortized)                       (2)            (4)
Additional minimum liability                                               7              4
---------------------------------------------------------------------------
                                                                         842            811
---------------------------------------------------------------------------
Plan assets at fair value                                                837            834
Transition asset not yet recognized (amortized)                           (6)            (8)
Net (gain)/loss not yet recognized (amortized)                           (92)           (52)
---------------------------------------------------------------------------
                                                                         739            774
---------------------------------------------------------------------------
Accrued pension/(prepaid) payments
 recorded on books                                                      $103           $ 37
---------------------------------------------------------------------------
</TABLE>
  The following provides a reconciliation of benefit obligations
and plan assets:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
(millions of dollars)                                                   1998           1997
-----------------------------------------------------------------------------
<S>                                                                      <C>            <C>
Changes in benefit obligation:
Benefit obligation at January 1                                         $819           $807
Service cost                                                              14             15
Interest cost                                                             55             53
Actuarial (gain)/loss                                                     (5)            59
Benefits paid from plan assets                                           (94)           (47)
Special termination benefits                                              64              -
Curtailment                                                              (11)             -
Plan Amendments                                                            1              -
Dispositions (Yankee Atomic)                                               -            (68)
-----------------------------------------------------------------------------
Benefit obligation at December 31                                       $843           $819
-----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1                                                 $834           $812
Actual return on plan assets during year                                                 93            130
Company contributions                                                      4              8
Benefits paid from plan assets                                           (94)           (47)
Dispositions (Yankee Atomic)                                               -            (69)
-----------------------------------------------------------------------------
Fair value of plan assets at December 31                                               $837           $834
-----------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Year ended December 31           1999       1998       1997       1996
----------------------------------------------------------------------
<S>                              <C>        <C>        <C>        <C>
Assumptions used to determine pension cost:
    Discount rate                6.75%      6.75%      7.25%      7.25%
    Average rate of increase in
      future compensation level  4.13%      4.13%      4.13%      4.13%
    Expected long-term rate of
      return on assets           8.50%      8.50%      8.50%      8.50%
</TABLE>

    The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates from 1999 and 1998,
respectively, and the 1983 Group Annuity Mortality table.

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

2. Postretirement Benefit Plans Other than Pensions (PBOPs):

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

  The Company's total cost of PBOPs for 1998, 1997, and 1996
included the following components:
                               <TABLE>
                               <CAPTION>
-----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars)                     1998    1997      1996
-----------------------------------------------------------------------------------------
<S>                                                       <C>      <C>     <C>
Service cost - benefits earned during the period              $  2,202$  2,164  $  2,232
Plus (less):
 Interest cost on projected benefit       obligation             9,258   9,486     9,661
 Return on plan assets at expected long-term rate               (7,963) (6,871)   (5,455)
 Amortization of transition obligation                           7,186   7,300     7,300
 Amortization of prior service cost                        30       30      30
 Amortization of net (gain)/loss                                (3,103) (2,865)   (2,063)
 Curtailment (gain)/loss                                4,909        -       -
-----------------------------------------------------------------------------------------
   Benefit cost                                      $ 12,519 $  9,244$ 11,705
-----------------------------------------------------------------------------------------
Special termination benefits not included above               $  1,982$      -       $      -
-----------------------------------------------------------------------------------------
</TABLE>

<PAGE>
    The following table sets forth the Company's benefits earned
and the plans' funded status:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
At December 31 (millions of dollars)                                              1998           1997
-----------------------------------------------------------------------------
<S>                                                                                <C>            <C>
Benefit obligation                                                                $149          $ 136
Unrecognized prior service costs                                                     -              -
Transition liability not yet recognized (amortized)                                (98)          (109)
-----------------------------------------------------------------------------
                                                                                    51             27
-----------------------------------------------------------------------------
Plan assets at fair value                                                          106             98
Net (gain)/loss not yet recognized (amortized)                                     (58)           (60)
-----------------------------------------------------------------------------
                                                                                    48             38
-----------------------------------------------------------------------------
Accrued pension/(prepaid) payments recorded on books               $  3          $ (11)
-----------------------------------------------------------------------------
</TABLE>
  The following provides a reconciliation of benefit obligations
and plan assets:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
(millions of dollars)                                                   1998           1997
-----------------------------------------------------------------------------
<S>                                                                      <C>            <C>
Changes in benefit obligation:
Benefit obligation at January 1                                         $136           $144
Service cost                                                               2              2
Interest cost                                                              9              9
Actuarial (gain)/loss                                                      2            (14)
Benefits paid from plan assets                                            (6)            (5)
Special termination benefits                                               2              -
Curtailment                                                                4              -
-----------------------------------------------------------------------------
Benefit obligation at December 31                                       $149           $136
-----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1                                                 $ 98           $ 82
Actual return on plan assets during year                                                 14             16
Company contributions                                                      -              5
Benefits paid from plan assets                                            (6)            (5)
-----------------------------------------------------------------------------
Fair value of plan assets at December 31                                               $106           $ 98
-----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year ended December 31           1999       1998       1997       1996
----------------------------------------------------------------------
<S>                              <C>        <C>        <C>        <C>
Assumptions used to determine postretirement benefit cost:
    Discount rate                6.75%      6.75%      7.25%      7.25%
    Expected long-term rate of
      return on assets           8.25%      8.25%      8.25%      8.25%
    Health care cost rate - 
      1996 to 1999               5.25%      5.25%      8.00%      8.00%
    Health care cost rate - 
      2000 to 2004               5.25%      5.25%      6.25%      6.25%
    Health care cost rate - 
      2005 and beyond            5.25%      5.25%      5.25%      5.25%         
 </TABLE>
<PAGE>
    The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates in effect for 1999 and 1998,
respectively.

    The assumptions used in the health care cost trends have a
significant effect on the amounts reported. A one percentage
point change in the assumed rates would increase the accumulated
postretirement benefit obligation (APBO) as of December 31, 1998
by approximately $18 million or decrease the APBO by
approximately $16 million, and change the net periodic cost for
1998 by approximately $2 million.

    The Company generally funds the annual tax-deductible
contributions. Plan assets are invested in equity and debt
securities and cash equivalents.

3. Early Retirement and Special Severance Programs:

  In 1998, the Company offered a voluntary early retirement
program to all employees who were at least 55 years old with 10
years of service. This program was part of an organizational
review with the goal of streamlining operations and reducing the
work force to reflect the sale of the nonnuclear generating
business. The early retirement offer was accepted by 292
employees. A special severance program was also utilized in 1998
for employees affected by the organizational restructuring, but
who were not eligible for, or did not accept, the early
retirement offer. The cost of these programs is being reimbursed
by NEP.

Note F - Income Taxes 

  The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns.  The Company's
income tax provision is calculated on a separate return basis. 
Federal income tax returns have been examined and reported on by
the Internal Revenue Service through 1993.

  Total income taxes in the statements of income are as follows:

<TABLE>
<CAPTION>
Year ended December 31, (In thousands)          1998       1997           1996
-----------------------------------------------------------------------------
<S>                                                         <C>            <C>            <C>
Income taxes charged to operations           $36,319    $42,454             $25,186
Income taxes charged (credited)
 to "Other income"                              (870)                (887)             (2,010)
                                             -------    -------             -------
  Total income taxes                         $35,449    $41,567             $23,176
                                             =======    =======             =======
</TABLE>
<PAGE>
  Total income taxes, as shown above, consist of the following
components:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands)          1998       1997                1996
-----------------------------------------------------------------------------
<S>                                                         <C>                 <C>            <C>
Current income taxes                         $13,169    $41,089             $31,026
Deferred income taxes                         23,366      1,581              (6,732)
Investment tax credits, net                   (1,086)              (1,103)             (1,118)
                                             -------    -------             -------
  Total income taxes                         $35,449    $41,567             $23,176
                                             =======    =======             =======
</TABLE>
  Investment tax credits have been deferred and are being
amortized over the estimated lives of the property giving rise to
the credits.

 Total income taxes, as shown above, consist of federal and
state components as follows:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands)          1998       1997                1996
-----------------------------------------------------------------------------
<S>                                                         <C>                 <C>            <C>
Federal income taxes                         $28,450    $34,053             $18,697
State income taxes                             6,999      7,514               4,479
                                             -------    -------             -------
  Total income taxes                         $35,449    $41,567             $23,176
                                             =======    =======             =======
</TABLE>

 Consistent with rate-making policies of the Massachusetts
Department of Telecommunications and Energy, the Company has
adopted comprehensive interperiod tax allocation (normalization)
for temporary book/tax differences.

 Total income taxes differ from the amounts computed by applying
the federal statutory tax rates to income before taxes.  The
reasons for the differences are as follows:
<TABLE>
<CAPTION>
Year ended December 31, (In thousands)          1998       1997                1996
-----------------------------------------------------------------------------
<S>                                                         <C>                 <C>            <C>
Computed tax at statutory rate               $30,042    $37,564             $21,386
Increases (reductions) in tax resulting from:
 Amortization of investment tax credits       (1,086)              (1,103)             (1,118)
 State income taxes, net of federal
  income tax benefit                           4,549      4,884               2,911
 All other differences                         1,944        222                  (3)
                                             -------    -------             -------
   Total income taxes                        $35,449    $41,567             $23,176
                                             =======    =======             =======
</TABLE>
 The following table identifies the major components of total
deferred income taxes:
<PAGE>
<TABLE>
<CAPTION>
At December 31, (In millions)                   1998       1997
-----------------------------------------------------------------
<S>                                                         <C>                 <C>
Deferred tax asset:
 Plant related                                 $   9      $   9
 Investment tax credits                            6          6
 All other                                        35         57
                                               -----      -----
                                                  50         72
                                               -----      -----
Deferred tax liability:
 Plant related                                  (231)           (223)
 All other                                       (20)            (28)
                                               -----      -----
                                                (251)           (251)
                                               -----      -----
  Net deferred tax liability                   $(201)          $(179)
                                               =====      =====
</TABLE>

Note G - Short-term Borrowings and Other Accrued Expenses

   At December 31, 1998, the Company had $81 million of
short-term debt outstanding representing borrowings from
affiliates.  NEES and certain subsidiaries, including the
Company, with regulatory approval, operate a money pool to more
effectively utilize cash resources and to reduce outside
short-term borrowings.  Short-term borrowing needs are met first
by available funds of the money pool participants.  Borrowing
companies pay interest at a rate designed to approximate the cost
of outside short-term borrowings.  Companies which invest in the
pool share the interest earned on a basis proportionate to their
average monthly investment in the money pool.  Funds may be
withdrawn from or repaid to the pool at any time without prior
notice.

   At December 31, 1998, 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 December 31, 1998.  Fees are paid in lieu of
compensating balances on most lines of credit.

   The components of other accrued expenses are as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
At December 31, (In thousands)                            1998           1997
---------------------------------------------------------------------------
<S>                                                                  <C>            <C>
Rate adjustment mechanisms                             $28,333        $ 4,227
Accrued wages and benefits                               9,972         15,244
Other                                                    2,321          2,610
                                                       -------        -------
                                                       $40,626        $22,081
                                                       =======        =======
</TABLE>

<PAGE>
Note H - Cumulative Preferred Stock

   A summary of cumulative preferred stock at December 31, 1998
and 1997 is as follows (in thousands except for share data):

<TABLE>
<CAPTION>
                           Shares                                             Dividends            Call
                      Outstanding                       Amount   Declared     Price
-----------------------------------------------------------------------------------
                     1998    1997    1998   1997    1998    1997           
-----------------------------------------------------------------------------------
<S>                         <C>      <C>     <C>    <C>     <C>      <C>       <C>
$25 par value -
 6.84% Series           - 192,161 $    - $ 4,804    $246  $  931     
$100 par value -
 4.44% Series      27,615  27,815   2,761  2,782     124     305     $104.068
 4.76% Series      25,130  27,530   2,513  2,753     125     326     $103.730
 6.99% Series      54,000  54,000   5,400  5,400     378   1,259          (a)
-----------------------------------------------------------------------------------
   Total          106,745 301,506 $10,674$15,739    $873  $2,821
===================================================================================
<FN>
(a) Callable on or after August 1, 2003 at $103.50.
</FN>
</TABLE>
   The annual dividend requirement for total cumulative
preferred stock was $620,000 and $961,000 at the end of the 1998
and 1997, respectively.

   There are no mandatory redemption provisions on the Company's
cumulative preferred stock.

  In 1998, the Company repurchased or redeemed preferred stock
with an aggregate par value of $5.1 million.  Total premiums paid
of $0.2 million in connection with the preferred stock repurchase
and redemption were charged to retained earnings.

<PAGE>
Note I - Long-term Debt 

 A summary of long-term debt is as follows:
<TABLE>
<CAPTION>
At December 31, (In thousands)
---------------------------------------------------------------------------
Series               Rate %                   Maturity                         1998                          1997
===========================================================================
<S>                     <C>                   <C>                               <C>                           <C>
First Mortgage Bonds:
U(95-3)               7.800                        February 13, 1998        $     -            $  5,000
U(95-4)               7.790                        February 16, 1998              -               5,000
R(92-1)               7.240                        December 30, 1998              -              10,000
S(92-3)               6.630                        August 12, 1999            7,500               7,500
S(92-4)               6.600                        August 12, 1999            7,500               7,500
U(95-5)               7.930                        February 14, 2000          6,000               6,000
S(92-2)               6.980                        July 17, 2000              5,000               5,000
S(92-9)               6.310                        September 15, 2000        10,000              10,000
R(92-6)               7.710                        July 1, 2002              10,000              10,000
S(92-11)              7.250                        October 28, 2002           5,000               5,000
S(92-12)              7.340                        November 25, 2002         10,000              10,000
T(93-2)               7.090                        January 27, 2003          20,000              20,000
T(93-5)               6.400                        June 24, 2003             10,000              10,000
U(93-1)               6.240                        November 17, 2003          5,000               5,000
U(94-6)               8.520                        November 30, 2004         10,000              10,000
U(95-1)               8.450                        January 10, 2005          10,000              10,000
U(95-2)               8.220                        January 24, 2005          10,000              10,000
U(95-7)               7.920                        March 3, 2005              9,000               9,000
V(95-1)               6.720                        June 23, 2005             10,000              10,000
V(96-1)               6.780                        November 20, 2006         20,000              20,000
T(93-7)               6.660                        June 23, 2008              5,000               5,000
T(93-8)               6.660                        June 30, 2008              5,000               5,000
T(93-10)              6.110                        September 8, 2008         10,000              10,000
T(93-11)              6.375                        November 17, 2008         10,000              10,000
V(98-3)               5.720                        November 24, 2008         25,000                   -
R(92-3)               8.550                        February 7, 2022           5,000               5,000
S(92-5)               8.180                        August 1, 2022            10,000              10,000
S(92-10)              8.400                        October 26, 2022           5,000               5,000
T(93-1)               8.150                        January 20, 2023               -              10,000
T(93-3)               7.980                        January 27, 2023               -              10,000
T(93-4)               7.690                        February 24, 2023         10,000              10,000
T(93-6)               7.500                        June 23, 2023              3,000               3,000
T(93-9)               7.500                        June 29, 2023              7,000               7,000
U(93-2)               7.200                        November 15, 2023         10,000              10,000
U(93-3)               7.150                        November 24, 2023          1,000               1,000
U(94-1)               7.050                        February 2, 2024          10,000              10,000
U(94-2)               8.080                        May 2, 2024                5,000               5,000
U(94-3)               8.030                        June 14, 2024              5,000               5,000
U(94-4)               8.160                        August 9, 2024             5,000               5,000
U(94-5)               8.850                        November 7, 2024           1,000               1,000
U(95-6)               8.460                        February 28, 2025          3,000               3,000
V(95-2)               7.630                        June 27, 2025             10,000              10,000
V(95-3)               7.600                        September 12, 2025        10,000              10,000
V(95-4)               7.630                        September 12, 2025        10,000              10,000
V(97-1)               7.390                        October 1, 2027           15,000              15,000
V(98-1)               6.910                        January 12, 2028          20,000                   -
V(98-2)               6.940                        January 12, 2028           5,000                   -
Unamortized discounts                                  (1,671)               (1,613)
                                                               --------    --------
Total long-term debt                                           $368,329    $358,387
                                                               ========    ========
Long-term debt due in one year                         15,000                20,000
                                                               --------    --------
                                                               $353,329    $338,387
                                                               ========    ========
</TABLE>

   Substantially all of the properties and franchises of the
Company are subject to the lien of mortgage indentures under
which the first mortgage bonds have been issued.
<PAGE>
   The Company will make cash payments of $15,000,000 in 1999,
$21,000,000 in 2000, $25,000,000 in 2002, $35,000,000 in 2003 and
$274,000,000 thereafter, to retire maturing mortgage bonds. 

   At December 31, 1998, the Company's long-term debt had a
carrying value of approximately $370,000,000 and had a fair value
of approximately $403,000,000.  The fair market value of the
Company's long-term debt was estimated based on the quoted prices
for similar issues or on the current rates offered to the Company
for debt of the same remaining maturity.

Note J - Restrictions on Retained Earnings Available for
         Dividends on Common Stock

   As long as any preferred stock is outstanding, certain
restrictions on payment of dividends on common stock would come
into effect if the "junior stock equity" was, or by reason of
payment of such dividends became, less than 25 percent of "Total
capitalization."  However, the junior stock equity at December
31, 1998 was 57 percent of total capitalization, and accordingly,
none of the Company's retained earnings at December 31, 1998 were
restricted as to dividends on common stock under the foregoing
provisions.

   Under restrictions contained in the indentures relating to
first mortgage bonds, $20,113,000 of the Company's retained
earnings at December 31, 1998 were restricted as to dividends on
common stock.

Note K - Supplementary Income Statement Information

   Advertising expenses, expenditures for research and
development, and rents were not material and there were no
royalties paid in 1998, 1997, or 1996.  Taxes, other than income
taxes, charged to operating expenses are set forth by classes as
follows:

<TABLE>
<CAPTION>
Year ended December 31, (In thousands)                    1998                                1997                          1996
----------------------------------------------------------------------------
<S>                                                              <C>                           <C>                           <C>
Municipal property taxes                               $30,561                             $23,796                       $23,304
Federal and state payroll
 and other taxes                                               7,422                         7,347                         7,255
                                                             -------                       -------                       -------
                                                             $37,983                       $31,143                       $30,559
                                                             =======                       =======                       =======
</TABLE>
<PAGE>
   New England Power Service Company, an affiliated service
company operating pursuant to the provisions of Section 13 of the
1935 Act, furnished services to the Company at the cost of such
services.  These costs amounted to $88,630,000, $73,145,000, and
$67,756,000, including capitalized construction costs of
$8,909,000, $7,907,000, and $9,330,000 for each of the years
1998, 1997, and 1996, respectively.

<TABLE>
<CAPTION>
Selected Financial Information
Year ended December 31, (In millions)       1998           1997           1996           1995           1994
-----------------------------------------------------------------------------------
<S>                                          <C>            <C>            <C>            <C>            <C>
Operating revenue                         $1,490         $1,624         $1,539              $1,506              $1,482
Net income                                $   50         $   66         $   38              $   29              $   35
Total assets                              $1,455         $1,408         $1,390              $1,343              $1,296
Capitalization:
 Common equity                            $  508         $  500         $  427              $  412              $  384
 Cumulative preferred stock                   11             16             50                  50                  50
 Long-term debt                              353            339            343                 353                 266
                                          ------         ------         ------              ------              ------
Total capitalization                      $  872         $  855         $  820              $  815              $  700
Preferred dividends declared              $    1         $    3         $    3              $    3              $    3
Common dividends declared                 $   42         $   24         $   19              $   13              $   30
</TABLE>

<TABLE>
<CAPTION>
Selected Quarterly Financial Information (Unaudited)
---------------------------------------------------------------------------
                                First              Second      Third             Fourth
(In thousands)                Quarter             Quarter    Quarter            Quarter
===========================================================================
<S>                               <C>                 <C>        <C>                <C>
1998
Operating revenue            $396,714            $361,889   $380,409           $351,405
Operating income             $ 22,843            $ 18,488   $ 20,350           $ 25,963
Net income                   $ 11,811            $  9,612   $ 11,920           $ 17,043               

1997
Operating revenue            $405,518            $369,542   $404,990           $444,035
Operating income             $ 24,241            $ 19,697   $ 17,621           $ 40,132
Net income                   $ 13,636            $ 10,353   $  8,041              $ 33,728              *
<FN>
*  See "Overview of Financial Results" and "Operating Revenue" sections of
Financial Review for a discussion of factors contributing to the fourth
quarter increase in net income.
</FN>
</TABLE>

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

<PAGE>
   A copy of Massachusetts Electric Company's Annual Report on
Form 10-K to the Securities and Exchange Commission for the year
ended December 31, 1998 will be available on or about April 1,
1999, upon request at no charge by contacting: Merrill IR Edge,
33 Boston Post Road, Suite 270, Marlborough, MA 01752,
Telephone: 508-786-1907, Fax: 508-786-1915, E-mail:
iredge@merrillcorp.com.