<PAGE>
 
               UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549
                                        
                                  FORM 10-K/A
                                        

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

     For the fiscal year ended December 31, 1998
                                       OR
[_]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

     For the transition period from _________ to _________

                         Commission file number 1-14768
                                   BEC ENERGY
             (Exact name of registrant as specified in its charter)

                Massachusetts                       04-6830187
--------------------------------------------------------------------------------
         (State or other jurisdiction of          (I.R.S. Employer
         incorporation or organization)          Identification No.)

     800 Boylston Street, Boston, Massachusetts          02199
--------------------------------------------------------------------------------
     (Address of principal executive offices)          (Zip Code)

Registrant's telephone number, including area code:  1-888-423-2364
                                                     --------------

Securities registered pursuant to Section 12(b) of the Act:

                                                   Name of each exchange
     Title of each class                           on which registered
     -------------------                           ------------------------
     Common stock, par value $1 per share          New York Stock Exchange
                                                   Boston Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities

Exchange Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days.  YES  X   NO 
                                                       ---     ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 26, 1999 computed as the average of the high and low
market price of the common stock as reported in the listing of composite
transactions for New York Stock Exchange listed securities in the Wall Street
Journal: $1,818,184,643.

Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.

                 Class                   Outstanding at March 26, 1999
        --------------------------       -----------------------------
        Common Stock, $1 par value               46,471,173 shares
<PAGE>
 
BEC Energy
--------------------------------------------------------------------------------

Form 10-K/A Annual Report
--------------------------------------------------------------------------------

December 31, 1998
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
 
Part I                                                           Page
--------------------------------------------------------------------------------
<S>                                                              <C>
 
Item  1.  Business                                                  2
 
Item  2.  Properties and Power Supply                               6
 
Item  3.  Legal Proceedings                                         8
 
Item  4.  Submission of Matters to a Vote of Security Holders       9
 

Part II
--------------------------------------------------------------------------------

Item  5.  Market for the Registrant's Common Stock and Related
          Stockholder Matters                                      12

Item  6.  Selected Financial Data                                  13

Item  7.  Management's Discussion and Analysis                     14

Item  8.  Financial Statements and Supplementary Financial
          Information                                              30

Item  9.  Changes in and Disagreements with Accountants on
          Accounting and Financial Disclosure                      58


Part III
--------------------------------------------------------------------------------

Item 10.  Trustees and Executive Officers of the Registrant        59

Item 11.  Executive Compensation                                   62

Item 12.  Security Ownership of Certain Beneficial Owners and
          Management                                               70

Item 13.  Certain Relationships and Related Transactions           71


Part IV
--------------------------------------------------------------------------------

Item 14.  Exhibits, Financial Statement Schedules and Reports on
          Form 8-K                                                 72
</TABLE> 

                                       1
<PAGE>
 
                                    Part I
                                    ------

Item 1.  Business
-----------------

(a) General Development of Business
-----------------------------------

Boston Edison Company (Boston Edison), an investor-owned regulated public
utility incorporated in 1886 under Massachusetts law, received final approval of
its reorganization plan to form a holding company structure from the Securities
and Exchange Commission (SEC) in May 1998.  Effective May 20, 1998 the holding
company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned
subsidiary of BEC.  Effective June 25, 1998, Boston Energy Technology Group
(BETG) ceased being a subsidiary of Boston Edison and became a wholly owned
subsidiary of BEC.  Unregulated activities continue to be conducted through
BETG.

Within its newly restructured industry, BEC has announced its intention to focus
its utility operations on the transmission and distribution of energy.  The sale
of Boston Edison's fossil generating assets to Sithe Energies, Inc. (Sithe) was
completed in May 1998.  In November 1998, Boston Edison signed an agreement with
Entergy Nuclear Generating Company (Entergy) to sell its wholly owned nuclear
generating unit, Pilgrim Nuclear Power Station (Pilgrim).  BEC signed a merger
agreement with Commonwealth Energy System (CES) in December 1998 that will
create an energy delivery company serving approximately 1.3 million customers
located entirely within Massachusetts, including more than one million electric
customers in 81 communities and 240,000 gas customers in 51 communities.

(b) Financial Information about Industry Segments
-------------------------------------------------

BEC's principal segment is the electric utility, Boston Edison.  As noted above,
unregulated activities are conducted through BETG.  Such unregulated activities
include telecommunications, construction management and district cooling.  Refer
to Note J to the Consolidated Financial Statements in Item 8 for specific
financial information related to BEC's electric utility and unregulated
segments.

(c) Narrative Description of Business
-------------------------------------

Principal Products and Services

Boston Edison currently supplies electricity at retail to an area of 590 square
miles, including the city of Boston and 39 surrounding cities and towns.  The
population of the area served with electricity at retail is approximately 1.5
million.  In 1998 Boston Edison served an average of approximately 660,000
customers.  It also supplies electricity at wholesale for resale to other
utilities and municipalities.  Electric operating revenues by class for the last
three years consisted of the following:
<TABLE>
<CAPTION>
 
                                   1998   1997   1996
------------------------------------------------------
<S>                                <C>    <C>    <C>
Retail electric revenues:
  Commercial                         51%    51%    50%
  Residential                        27%    27%    27%
  Industrial                          9%     9%     9%
  Other                               1%     1%     2%
Wholesale and contract revenues      12%    12%    12%
=====================================================
</TABLE>

                                       2
<PAGE>
 
Sources and Availability of Fuel

On May 15, 1998, Boston Edison completed the sale of its non-nuclear generating
assets to Sithe Energies.  In April 1998, Boston Edison began soliciting
expressions of interest for the sale of its nuclear generating unit, Pilgrim as
part of the previously announced strategy to exit the generation business.  On
November 19, 1998, Boston Edison announced that Entergy, a subsidiary of New
Orleans-based Entergy Corporation, had been selected as the winning bidder for
Pilgrim.  A purchase and sale agreement has been signed and all required
approvals are anticipated in the second quarter of 1999.  Company generation by
type of fuel for each of the last five years were as follows:
<TABLE> 
<CAPTION> 
              Percentage of Company
             Generation by Source (%)
         --------------------------------
         1998   1997   1996   1995   1994
-----------------------------------------
<S>      <C>    <C>    <C>    <C>    <C> 
Oil       8.1   32.0   16.1   17.5   27.8
Gas      20.8   31.1   33.3   39.9   31.6
Nuclear  71.1   36.9   50.6   42.6   40.6
=========================================
</TABLE> 

The decrease in company oil and gas generation resulting from the fossil
divestiture was partially offset by higher purchased power in 1998 that included
a six-month transitional power purchase contract with Sithe that began in May.

In order to obtain fuel for use at Pilgrim Station, Boston Edison must obtain
supplies of uranium concentrates and secure contracts for these concentrates to
go through the processes of conversion, enrichment and fabrication of nuclear
fuel assemblies.  Boston Edison currently has contracts for supplies of uranium
concentrates and the processes of conversion, enrichment and fabrication through
2002, 2000, 2004 and 2012, respectively.  Following the planned sale of Pilgrim,
it is expected that each of these contracts for future commitments will either
be terminated or permitted to expire in accordance with their terms.  Boston
Edison may be subject to a penalty of approximately $10 million to terminate one
of these contracts.  Management anticipates any payment will be collected from
customers under the terms of the Boston Edison settlement agreement.  None of
these supply contracts have been assigned to Entergy.

Franchises

Through its charter, which is unlimited in time, Boston Edison has the right to
engage in the business of producing and selling electricity, steam and other
forms of energy, has powers incidental thereto and is entitled to all the rights
and privileges of and subject to the duties imposed upon electric companies
under Massachusetts laws.  The locations in public ways for electric
transmission and distribution lines are obtained from municipal and other state
authorities which, in granting these locations, act as agents for the state.  In
some cases the action of these authorities is subject to appeal to the
Massachusetts Department of Telecommunications and Energy (DTE).  The rights to
these locations are not limited in time, but are not vested and are subject to
the action of these authorities and the legislature.  Pursuant to the
Massachusetts electric utility industry restructuring legislation enacted in
November 1997, the DTE has defined the service territory of Boston Edison based
on the territory actually served on July 1, 1997, and following, to the extent
possible, municipal boundaries.  The legislation further provided that, until
terminated by effect of law or otherwise, Boston Edison shall have the exclusive
obligation to provide distribution service to all retail customers 

                                       3
<PAGE>
 
within such service territory. No other entity shall provide distribution
service within this territory without the written consent of Boston Edison which
consent must be filed with the DTE and the municipality so affected.

Seasonal Nature of Business

Kilowatt-hour (kWh) sales and revenues are typically higher in the winter and
summer than in the spring and fall as sales tend to vary with weather
conditions.  Refer to the Selected Consolidated Quarterly Financial Data
(Unaudited) in Item 8 for specific financial information by quarter for 1998 and
1997.

Competitive Conditions

The utility industry has continued to change in response to the marketplace
demands for improved customer service and lower prices for energy.  These
pressures have resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business combinations.  On
December 5, 1998, BEC and CES, headquartered in Cambridge, Massachusetts,
entered into an Agreement and Plan of Merger (the Merger Agreement).
Management's Discussion and Analysis ("Merger with COM/Energy") in Item 7
provides further details regarding the Merger Agreement.

BEC's electric utility subsidiary, Boston Edison has been anticipating and
responding to changes in the electric energy business as a result of industry
restructuring proceedings at both the federal and state levels.  Management's
Discussion and Analysis ("Retail Access") in Item 7 provides further details
regarding Boston Edison's response to the industry climate, including details of
its industry restructuring settlement agreement.

Environmental Matters

BEC and its subsidiaries are subject to numerous federal, state and local
standards with respect to the management of wastes, air and water quality and
other environmental considerations.  These standards could require modification
of existing facilities or curtailment or termination of operations at these
facilities.  They could also potentially delay or discontinue construction of
new facilities and increase capital and operating costs by substantial amounts.
Noncompliance with certain standards can, in some cases, also result in the
imposition of monetary civil penalties.

Environmental-related capital expenditures for the years 1998 and 1997 were $0.6
million and $1.4 million, respectively.  Management believes that its remaining
operating facilities are in substantial compliance with currently applicable
statutory and regulatory environmental requirements.  Additional expenditures
could be required as changes in environmental requirements occur.

Number of Employees

As of March 26, 1999, BEC had 2,893 full-time and 48 part-time utility employees
including 1,966 represented by two locals of the Utility Workers Union of
America, AFL-CIO.  The locals' labor contracts are effective through May of the
year 2000.  Management believes it has satisfactory employee relations.

Approximately 600 employees are expected to terminate employment with BEC as a
result of the divestiture of Pilgrim Station in 1999.  Refer to the Generating
Assets Divestiture section of Item 7 for information regarding employees
affected by the nuclear divestiture.

                                       4
<PAGE>
 
(d) Financial Information about Foreign and Domestic Operations and Export Sales
--------------------------------------------------------------------------------

BEC's principal subsidiary, Boston Edison delivers electricity to retail and
wholesale customers in the Boston area.  Neither Boston Edison, nor BEC's other
subsidiaries have any foreign operations or export sales.

(e) Additional Information
--------------------------

Regulation

BEC's electric utility subsidiary, Boston Edison and its wholly owned
subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the
authority of the DTE, whose jurisdiction includes supervision over retail rates
for electricity and financing and investing activities.  In addition, the
Federal Energy Regulatory Commission (FERC) has jurisdiction over various phases
of Boston Edison's business including rates for power sold at wholesale for
resale, facilities used for the transmission or sale of that power, certain
issuances of short-term debt and regulation of the system of accounts.  BEC's
subsidiary BETG and its subsidiaries are not subject to such regulation.

The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting,
construction and operation of nuclear reactors with respect to public health and
safety, environmental matters and antitrust considerations.  A license granted
by the NRC may be revoked, suspended or modified for failure to construct or
operate a facility in accordance with its terms.  Boston Edison currently holds
an operating license for Pilgrim Station which expires in 2012.  Continuing NRC
review of existing regulations and certain operating occurrences at other
nuclear plants have periodically resulted in the imposition of additional
requirements for all nuclear plants in the United States, including Pilgrim
Station.  NRC inspections and investigations can result in the issuance of
notices of violation.  These notices can also be accompanied by orders directing
that certain actions be taken or by the imposition of monetary civil penalties.

In addition, management could undertake certain actions regarding Pilgrim
Station at the request or suggestion of its insurers or the Institute of Nuclear
Power Operations, a voluntary association of nuclear utilities dedicated to the
promotion of safety and reliability in the operation of nuclear power plants.
Nuclear power continues to be a subject of political controversy and public
debate manifested from time to time in the form of requests for various kinds of
federal, state and local legislative or regulatory action, direct voter
initiatives or referenda or litigation.  Management cannot predict the extent,
cost or timing of any modifications to Pilgrim which could be necessary as a
result of additional regulatory or other requirements.  As discussed in Sources
and Availability of Fuel of this item, Boston Edison entered into a purchase and
sale agreement with Entergy for the sale of Pilgrim Station.  The DTE approved
the sale of Pilgrim in March 1999.  Other required approvals are anticipated in
the second quarter of 1999.  Such approvals are required for the completion of
the Pilgrim sale.  Provided that all required approvals are received and the
sale of Pilgrim proceeds as planned, Boston Edison will transfer its regulatory
and legal liability and responsibility for Pilgrim to Entergy, except for any
outstanding liabilities related to pre-closing occurrences.  If the required
approvals are not received as anticipated, the agreement with Entergy could be
terminated.  If Boston Edison is ultimately unable to sell Pilgrim, management
expects it would recover all stranded Pilgrim costs, including decommissioning
under the Boston Edison settlement agreement.

                                       5
<PAGE>
 
Capital Expenditures and Financings

The most recent estimates of capital expenditures (excluding nuclear fuel),
allowance for funds used during construction (AFUDC), long-term debt maturities
and preferred stock payment requirements for the years 1999 through 2003 are as
follows:
<TABLE> 
<CAPTION> 
(in thousands)        1999         2000         2001         2002         2003
------------------------------------------------------------------------------
<S>              <C>           <C>          <C>          <C>          <C> 
Capital
expenditures (1)  $233,000     $200,000     $189,000     $180,000     $158,000
AFUDC             $  1,200     $  1,200     $  1,200     $  1,200     $  1,200
Long-term debt    $  1,600     $166,600     $  1,600     $  1,600     $151,650
Preferred stock   $      -     $      -     $ 50,000     $      -     $      -
==============================================================================
</TABLE> 
(1)  Includes both utility and nonutility ventures.

Management continuously reviews its capital expenditure and financing programs.
These programs and, therefore, the estimates included in this Form 10-K/A are
subject to revision due to changes in regulatory requirements, environmental
standards, availability and cost of capital, interest rates and other
assumptions.

Plant expenditures in 1998 were $120 million and consisted primarily of
additions to Boston Edison's distribution and transmission systems and
construction expenditures related to BEC's district cooling subsidiary,
Northwind Boston, LLC.  The majority of these expenditures were for system
reliability and control improvements, customer service enhancements and capacity
expansion to allow for long range growth in the Boston Edison service territory.

Refer to the Liquidity section of Item 7 for more information regarding capital
resources to fund BEC's construction programs.

Item 2.  Properties and Power Supply
------------------------------------

Total electric generation capacity from facilities owned by Boston Edison
consisted of the following:
<TABLE>
<CAPTION>
 
                                                                     Year
Unit (a)                    Location        Capacity (b)   Type    Installed
-------------------------------------------------------------------------------
<S>                    <C>                  <C>           <C>      <C>
Pilgrim Nuclear        Plymouth, Mass.              670   Nuclear       1972
 Power Station
 
New Boston Station     South Boston, Mass.          760   Fossil   1965-1967
 Units 1 and 2
 
Mystic Station         Everett, Mass.
 Units 4-5-6                                        388   Fossil   1957-1961
 Unit 7                                             592   Fossil        1975
 Combustion turbine                                  14   Fossil        1969
 generator
 
Combustion turbine     Various                      276   Fossil   1966-1971
 generators (nine)
==============================================================================
</TABLE>

(a)  As discussed in Sources and Availability of Fuel of this item, Boston
     Edison completed the sale of its fossil generating assets to Sithe

                                       6
<PAGE>

     Energies in May 1998. IN addition, Pilgrim Station is expected to be sold
     to Entergy in 1999.

(b)  In megawatts (MW) based on winter capability audit results in 1997.

Boston Edison's high-tension transmission lines are generally located on land
either owned or subject to easements in its favor.  Its low-tension distribution
lines are located principally on public property under permission granted by
municipal and other state authorities.

As of December 31, 1998, Boston Edison's transmission system consisted of 376
miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 171
miles of underground circuits operating at 115 and 345 kV.  The substations
supported by these lines are 45 transmission or combined transmission and
distribution substations with transformer capacity of 11,053 megavolt amperes
(MVA), 57 4 kV distribution substations with transformer capacity of 932 MVA and
16 primary network units with 79 MVA capacity.  In addition, high tension
service was delivered to 248 customers' substations.  The overhead and
underground distribution systems cover approximately 3,700 and 3,200 circuit
miles, respectively.  HEEC, Boston Edison's regulated subsidiary, has a
distribution system that consists principally of a 4.1 mile 115 kV submarine
distribution line and a substation which is located on Deer Island in Boston,
Massachusetts.  HEEC provides the ongoing support required to distribute
electric energy to its one customer, the Massachusetts Water Resources
Authority, at this location.

Purchased Power Contracts

Boston Edison entered into a 13-month agreement effective December 1, 1998 to
transfer all of the unit output entitlements from its long-term power purchase
contracts to Select Energy (Select), a subsidiary of Northeast Utilities, Inc.
In return, Select will provide full energy service requirements to Boston
Edison, including New England Power Pool (NEPOOL) capability responsibilities,
at FERC approved tariff rates through December 31, 1999.  For more information
regarding these long-term contracts refer to Note L to the Consolidated
Financial Statements in Item 8.

Sales Contracts

Boston Edison currently sells a percentage of Pilgrim Station's output to
Commonwealth Electric Company (Commonwealth), Montaup Electric Company (Montaup)
and various municipalities under long-term contracts.  Under these contracts,
the utilities and municipalities pay their proportionate share of the costs of
operating the station and associated transmission facilities.  The long-term
power sales contracts with Commonwealth and Montaup will be terminated upon the
closing of the sale of Pilgrim Station to Entergy.  The contracts with the
municipalities remain in place whereby Boston Edison will purchase power for
resale to the municipalities under a purchase power agreement entered into with
Entergy.  Refer to Notes K and L to the Consolidated Financial Statements in
Item 8 for more information regarding these contracts.

New England Power Pool

Boston Edison is a member of NEPOOL, a voluntary association of electric
utilities and other electricity suppliers in New England responsible for the
coordination, monitoring and directing of the operations of the major generating
and transmission facilities in the region.  To obtain maximum benefits of power
pooling, the electric facilities of all member companies are 

                                       7
<PAGE>
 
directed by an Independent System Operator (ISO New England) as if they were a
single power system. This is accomplished through the use of a central
dispatching system that uses the lowest-priced generation and transmission
equipment available at any given time. NEPOOL's goal is to ensure a reliable
energy supply for the New England region at the lowest possible price.

During 1997, the power pool was restructured with changes taking effect to the
membership and governance provisions of the power pooling agreement along with
the transfer of operating responsibility of the integrated transmission and
generation system in New England to ISO New England.  Previously, NEPOOL
dispatched generating units for operation based on the lowest operating costs of
available generation and transmission.  Under the new structure, generators will
be required to provide ISO New England with market prices at which they will
sell short-term energy supply.  These prices will form the basis for dispatch
anticipated to begin in the second quarter of 1999.  As noted in the Purchased
Power Contracts section above, Boston Edison will receive all of its power
supply requirements from Select in 1999.  Therefore, the change to NEPOOL's
operations and pricing structure is expected to have no material impact on
Boston Edison's costs for purchased electric energy.

Item 3.  Legal Proceedings
--------------------------

Industry and corporate restructuring legal proceedings

The DTE order approving the Boston Edison settlement agreement and the DTE order
approving the formation of BEC as a holding company were appealed by certain
parties to the Massachusetts Supreme Judicial Court (SJC).  In December 1998,
the SJC dismissed the appeal of the order approving the holding company
formation.  One settlement agreement appeal remains pending, however there has
to date been no briefing, hearing or other action taken with respect to this
proceeding.

In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.

Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.

A referendum seeking repeal of the Massachusetts electric industry restructuring
legislation that was enacted in November 1997 was overwhelmingly defeated by a
better than 70% to 30% margin in a state-wide general election held on November
3, 1998.  This outcome allows the comprehensive framework established for the
restructuring of the electric industry to continue as intended under the enacted
legislation.

Regulatory proceedings

In October 1997, the DTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings began in the fourth quarter of 1998 and are expected to be completed in
the first half of 1999.

                                       8
<PAGE>
 
Each of the Reading Municipal Light Department, the Littleton Electric Light
Department and the West Boylston Municipal Light Department have filed separate
claims for arbitration in Massachusetts alleging that the proposed transfer of
Pilgrim Station constitutes a breach of their respective power sale agreements
and seeking to terminate those agreements.  The remaining municipal light
departments have also indicated that they plan to file similar claims for
arbitration.  Boston Edison has requested the FERC to exercise its pre-emptive
authority to consider the claims of the municipal light departments.  In the
event that either the FERC determines, or as a result of the arbitrations, that
the contracts should be terminated, Boston Edison would continue to be obligated
to purchase power from Entergy that it intended to resell to the municipal light
departments.  Boston Edison may not be able to resell such power in the short-
term power exchange at a price equal to or greater than the price it is required
to pay to Entergy.  However, Boston Edison has filed at the DTE for recovery of
any such shortfall as part of its Pilgrim divestiture filing through the
transition charge.

Management is currently unable to determine the outcome of these proceedings
however, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.

Other litigation

In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison.  The town claimed that Boston Edison
wrongfully failed to execute an agreement with the town for payments in addition
to taxes due to the town under the Massachusetts electric industry restructuring
legislation.  Boston Edison and the town agreed on a 15-year, $141 million
property tax package in March 1999.  Payments in each of the first four years
are approximately $15 million after which payments gradually decline.  All
payments under this agreement will be recovered from customers through the
transition charge.

In the normal course of its business BEC and its subsidiaries are also involved
in certain other legal matters.  Management is unable to fully determine a range
of reasonably possible legal costs in excess of amounts accrued.  Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position.  However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.

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

There were no matters submitted to a vote of security holders during the fourth
quarter of 1998.

                                       9
<PAGE>
 
Executive Officers of the Registrant
------------------------------------

The names, ages, positions and business experience during the past five years of
all the executive officers of BEC Energy (Boston Edison, prior to May, 1998) as
of March 1, 1999 are listed below.  There are no family relationships between
any of the officers, nor any arrangement or understanding between any officer
and another person pursuant to which the position as officer is held.  Officers
hold office until the first meeting of the trustees following the next annual
meeting of the stockholders and until their respective successors are chosen and
qualified.

                                            Business Experience
Name, Age and Position                      During Past Five Years
----------------------                      ----------------------

Thomas J. May, 51                           Chairman of the Board, President
Chairman of the Board, President            and Chief Executive Officer (since
and Chief Executive Officer                 1995), Chairman of the Board and
                                            Chief Executive Officer (1994-
                                            1995), President and Chief
                                            Operating Officer (1993-1994);
                                            Director (since 1991)

                                            Chairman of the Board, President
                                            and Chief Executive Officer and
                                            Director, Boston Energy Technology
                                            Group, Inc.; Director, Harbor
                                            Electric Energy Company, Boston
                                            Edison Services, Inc., BecoCom,
                                            Inc., Northwind Boston, LLC and
                                            Coneco Corp.


Douglas S. Horan, 49                        Senior Vice President - Strategy
Senior Vice President - Strategy            and Law and General Counsel
and Law and General Counsel                 (since 1995), Vice President and
                                            General Counsel (1994-1995),
                                            Deputy General Counsel (1991-1994)
       
                                            Senior Vice President, General
                                            Counsel and Director, Harbor
                                            Electric Energy Company; Senior
                                            Vice President and Director,
                                            BecoCom, Inc.; Director, Boston
                                            Energy Technology Group, Inc.,
                                            Boston Edison Services, Inc. and
                                            Coneco Corp.

                                       10
<PAGE>
 
                                            Business Experience
Name, Age and Position                      During Past Five Years
----------------------                      ----------------------


James J. Judge, 43                          Senior Vice President - Corporate
Senior Vice President - Corporate           Services and Treasurer (since
Services and Treasurer                      1995), Assistant Treasurer (1989-
                                            1995), Director - Corporate
                                            Planning (1993-1995)
       
                                            Senior Vice President, Treasurer
                                            and Director, Harbor Electric
                                            Energy Company and Boston Energy
                                            Technology Group, Inc.; Senior
                                            Vice President and Director,
                                            Boston Edison Services, Inc. and
                                            BecoCom, Inc.; Director, Northwind
                                            Boston, LLC and Coneco Corp.


Robert J. Weafer, Jr., 52                   Vice President - Finance,
Vice President - Finance,                   Controller and Chief Accounting
Controller and Chief                        Officer (since 1991)
Accounting Officer
                                            President and Assistant Treasurer,
                                            Coneco Corp., Assistant Treasurer,
                                            Harbor Electric Energy Company,
                                            Boston Energy Technology Group,
                                            Inc. and Boston Edison Services,
                                            Inc.


Theodora S. Convisser, 51                   Clerk of the Corporation (since
Clerk of the Corporation                    1986) and Assistant General
                                            Counsel (since 1984)
              
                                            Clerk, Harbor Electric Energy
                                            Company, Boston Energy Technology
                                            Group, Inc., Boston Edison
                                            Services, Inc., BecoCom, Inc.,
                                            Northwind Boston, LLC and Coneco
                                            Corp.

                                       11
<PAGE>
 
                              Part II
                              -------

Item 5.  Market for the Registrant's Common Stock and Related Stockholder
-------------------------------------------------------------------------
Matters
-------

(a) Market Information
----------------------

BEC's common stock is listed on the New York and Boston Stock Exchanges.

The high and low market value per share of common stock as reported in the Wall
Street Journal for each of the quarters in 1998 and 1997 was as follows.  (Prior
to May 1998, the information listed refers to Boston Edison common stock.)
<TABLE>
<CAPTION>
 
                          1998               1997
                  -------------------  ----------------
                    High       Low      High      Low
                  ---------  --------  -------  -------
<S>               <C>        <C>       <C>      <C>
First quarter     $41 15/16  $35 1/16  $27 3/8  $26
Second quarter    $42   5/8  $ 38 7/8  $26 5/8  $24 5/8
Third quarter     $44  5/16  $ 37 3/4  $30 7/8  $26 1/2
Fourth quarter    $44 15/16  $ 39 5/8  $38 3/8  $30 1/4
                  =========  ========  =======  =======
</TABLE>

(b) Holders
-----------

As of March 26, 1999, there were 29,234 holders of BEC common stock.

(c) Dividends
-------------

Dividends declared per share of common stock for each of the quarters in 1998
and 1997 were as follows.  (Prior to May 1998, the information listed refers to
Boston Edison common stock.)
<TABLE>
<CAPTION>
 
                   1998    1997
                  ------  ------
<S>               <C>     <C>
First quarter     $0.470  $0.470
Second quarter    $0.470  $0.470
Third quarter     $0.470  $0.470
Fourth quarter    $0.485  $0.470
                  ======  ======
</TABLE>

                                       12
<PAGE>
 
Item 6.  Selected Financial Data
--------------------------------

The following table summarizes five years of selected consolidated financial
data (in thousands, except per share data).
<TABLE> 
<CAPTION> 
                  1998         1997        1996         1995          1994
--------------------------------------------------------------------------------
<S>           <C>          <C>          <C>          <C>           <C> 
Operating
 revenues     $1,622,515   $1,778,531   $1,668,856   $1,628,503    $1,544,735

Net income    $  141,046   $  144,642   $  141,546   $  112,310    $  125,022

Earnings per
 share of
 common
 stock:
   Basic      $     2.76   $     2.71   $     2.61   $     2.08(a) $     2.41
   Diluted    $     2.75   $     2.71   $     2.61   $     2.08(a) $     2.41

Total
 assets       $3,213,899   $3,622,347   $3,729,291   $3,637,170    $3,608,699

Long-term
 debt         $  955,563   $1,057,076   $1,058,644   $1,160,223    $1,136,617

Redeemable
 preferred
 stock        $   92,040   $  163,093   $  203,419   $  206,514    $  208,514

Cash
 dividends
 declared
 per common
 share        $    1.895   $    1.880   $    1.880    $    1.835   $    1.775
==============================================================================
</TABLE> 
(a)  Includes $0.44 per share restructuring charge.  Excluding the
    restructuring charge, 1995 earnings per share were $2.52.

                                       13
<PAGE>
 
Item 7.  Management's Discussion and Analysis
---------------------------------------------

Merger with COM/Energy

The utility industry has continued to change in response to the marketplace
demands for improved customer service and lower prices for energy.  These
pressures have resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business combinations.  On
December 5, 1998, BEC Energy (BEC) and Commonwealth Energy System (CES),
headquartered in Cambridge, Massachusetts, entered into an Agreement and Plan of
Merger (the Merger Agreement).  Pursuant to the Merger Agreement, BEC and CES
will be merged into a new holding company which has not yet been named (Newco).
Holders of BEC common shares will receive one share of Newco common stock for
each share held while CES common shareholders will receive 1.05 shares of Newco
common stock for each share held.  Alternatively, current BEC and CES common
shareholders have the right to receive $44.10 of cash for each share held, up to
an aggregate maximum of $300 million.  At the close of the merger, BEC
shareholders are expected to own approximately 68% of Newco common stock and CES
shareholders are expected to own approximately 32%.  The merger is expected to
occur shortly after the satisfaction of certain conditions, including the
receipt of certain regulatory approvals including that of the Massachusetts
Department of Telecommunications and Energy (DTE).  The regulatory approval
process is expected to be completed during the second half of 1999.

The merger will create an energy delivery company serving approximately 1.3
million customers located entirely within Massachusetts, including more than one
million electric customers in 81 communities and 240,000 gas customers in 51
communities.

The Merger Agreement may be terminated under certain circumstances, including by
any party if the merger is not consummated by December 5, 1999, subject to an
automatic extension of six months if the requisite regulatory approvals have not
yet been obtained by such date.  The merger will be accounted for using the
purchase method of accounting.

Upon effectiveness of the merger, Thomas J. May, BEC's current Chairman,
President and Chief Executive Officer (CEO), will become the Chairman and CEO of
Newco.  Russell D. Wright, CES' current President and CEO, will become the
President and Chief Operating Officer of Newco and will serve on Newco's board
of trustees.  Also, upon the effective date of the merger, Newco's board of
trustees will consist of BEC's and CES' current trustees.

Retail Access

BEC's electric utility subsidiary, Boston Edison Company (Boston Edison) has
been anticipating and responding to the changes in the electric energy business
as a result of industry restructuring proceedings at both federal and state
levels.  In January 1998, the DTE approved Boston Edison's restructuring
settlement agreement.  The DTE found that the settlement agreement substantially
complied or was consistent with key provisions of a Massachusetts law enacted in
November 1997 establishing a comprehensive framework for the restructuring of
the electric utility industry.  Prior to this settlement agreement, retail
electric customers within Boston Edison's service territory received all
services related to the provision of electricity from Boston Edison.  This
included the procurement of the electricity supply (either through purchase
contracts or generation) and the transmission and distribution to customers'
facilities.  Major provisions of 

                                       14
<PAGE>
 
the settlement agreement included the ability for retail electric customers to
choose their electricity supplier (referred to as retail access) effective 
March 1, 1998 (the retail access date). Boston Edison will continue to provide
all transmission and distribution of electricity services to all of its retail
customers. Under its settlement agreement, Boston Edison provides standard offer
service to all customers of record as of the retail access date. Customers
continuing to buy electricity under the standard offer are receiving service at
rates designed to give 10% savings from the rates in effect prior to the retail
access date. These standard offer customers will realize an additional 5%
average savings, after an adjustment for inflation, by September 1, 1999. Boston
Edison expects to be able to meet this additional rate reduction as a result of
the divestiture of the fossil generating assets which is discussed below. The
proceeds from the divestiture are being utilized to reduce customer rates. New
retail customers in the Boston Edison service territory and previously existing
customers that are no longer eligible for the standard offer due to choosing a
competitive supplier are on default service. The price of default service is
intended to reflect the average competitive market price for power. As of
December 31, 1998, 87% of customers are receiving standard offer service, while
13% are receiving default service. No customers received generation service from
competitive suppliers during 1998. Refer also to the Electric revenues section
for more information.

Generating Assets Divestiture

The Boston Edison restructuring settlement agreement included a provision for
the divestiture of its fossil generating assets no later than six months after
the retail access date.  On May 15, 1998, Boston Edison completed the sale of
its non-nuclear generating assets to Sithe Energies, Inc. (Sithe).  Boston
Edison received proceeds from the sale of $655 million, including $121 million
for a six-month transitional power purchase contract.  The amount received above
net book value on the sale of these assets is being returned to Boston Edison's
customers over the settlement period.  That amount is partially offset by the
costs to provide standard offer service incurred by Boston Edison's fossil
generating assets prior to the divestiture which are recoverable under Boston
Edison's settlement agreement.

In April 1998, Boston Edison began soliciting expressions of interest for the
sale of its nuclear generating unit, Pilgrim Nuclear Power Station (Pilgrim) as
part of the previously announced strategy to exit the generation business.  On
November 19, 1998, Boston Edison announced that Entergy Nuclear Generating
Company (Entergy), a subsidiary of New Orleans-based Entergy Corporation, had
been selected as the winning bidder for Pilgrim.  In the nation's first
competitive bid process for a nuclear power plant, Entergy is expected to
purchase Pilgrim in a deal valued at an estimated $121 million.  In addition,
under the agreement Boston Edison will fully fund and transfer its
decommissioning trust fund to Entergy and Entergy will then assume full
liability and responsibility for decommissioning the Pilgrim site.  A purchase
and sale agreement has been signed and all required approvals are anticipated in
the second quarter of 1999.  The purchase price includes reimbursement for costs
to be expended by Boston Edison in 1999 primarily related to the refueling and
maintenance outage scheduled for May 1999.  Therefore, the actual proceeds could
be impacted by the ultimate timing of the transaction.

As part of a benefits package offered to employees affected by the nuclear
divestiture, eligible non-represented nuclear and designated nuclear support
employees were offered unreduced retirement and transition benefits under a
voluntary early retirement program (VERP).  Sixteen employees elected to
participate in the VERP.  A retention benefit program was offered to all non-

                                       15
<PAGE>
 
represented nuclear and designated nuclear support employees that did not elect
or were ineligible to retire under the VERP who continue to work through the
sale closing date.  It is anticipated that approximately 300 non-represented
nuclear and designated nuclear support employees will receive one-time retention
payments under this program.  Costs associated with the VERP and retention
program are recoverable under Boston Edison's settlement agreement.  At December
31, 1998, approximately $24 million in one-time benefit charges were deferred as
a regulatory asset related to the nuclear divestiture.

For more information on the nuclear divestiture refer to the November 23, 1998
BEC or Boston Edison Report on Form 8-K announcing the purchase and sale
agreement with Entergy.

BEC Energy

Boston Edison received final approval of its reorganization plan to form a
holding company structure from the Securities and Exchange Commission (SEC) in
May 1998.  Effective May 20, 1998, BEC was formed with Boston Edison as a wholly
owned subsidiary of BEC.  Effective June 25, 1998, Boston Energy Technology
Group (BETG) ceased being a subsidiary of Boston Edison and became a wholly
owned subsidiary of BEC.  The holding company structure clearly separates the
unregulated and regulated operations of BEC and provides management with greater
organizational flexibility in order to take advantage of utility and nonutility
business opportunities in a more timely manner, including the merger with CES.

Joint Ventures

Unregulated activities continue to be conducted through BETG.  During 1997, BETG
entered into two joint venture agreements.  BETG's joint venture agreement with
RCN Telecom Services, Inc. (RCN) established a limited liability company (LLC)
that competes directly with local and long-distance telephone, video and
Internet access companies for telecommunications-related services.  BETG owns
49% of the LLC while RCN owns 51% and maintains day-to-day management
responsibility.  As part of the joint venture agreement, BETG has the option to
exchange certain portions of its joint venture interest for shares of RCN
Corporation common stock.  During 1998, BETG exercised its option to convert a
portion of its interest with a cost of $11 million.  BETG expects to receive
approximately 1.1 million RCN Corporation common shares during the first quarter
of 1999.  As a result of this conversion, BETG's ownership interest in the joint
venture is reduced from 49% to 46%.

BETG also established an energy marketing venture with Williams Energy Services
Company (WESCO), a subsidiary of The Williams Companies, Inc. in 1997.  In
August 1998, BEC and WESCO entered into an agreement to transfer BETG's 50%
interest in their joint venture to WESCO.  This transaction did not have a
material impact on BEC's consolidated financial position or results of
operations.

Results of Operations

1998 versus 1997

Basic and diluted earnings per common share were $2.76 and $2.75, respectively
in 1998 compared to $2.71 and $2.71 in 1997, a 1.8% increase in basic earnings
as described below.

                                       16
<PAGE>
 
Operating revenues

Operating revenues decreased 8.8% from 1997 as follows:
<TABLE> 
<S>                                          <C> 
(in thousands)
-------------------------------------------------------
Retail revenues                              $(148,272)
Wholesale revenues                              (3,721)
Short-term sales and other revenues             (4,023)
------------------------------------------------------- 
   Decrease in operating revenues            $(156,016)
======================================================= 
</TABLE> 

Retail revenues were $1,375 million in 1998 compared to $1,523 million in 1997,
a decrease of $148 million or 10%.  Retail revenues reflect the impact of the
mandated 10% retail rate reduction.  A 2.0% increase in retail kilowatt-hour
(kWh) sales in 1998 partially offset the impact of the rate reduction.  Retail
revenues also reflect a decrease due to the timing effect of fuel and purchased
power cost recovery.  Prior to its cessation as of March 1, 1998, the fuel
clause charge was lower than the prior year as the 1997 charge reflected the
recovery of substantial prior year undercollections.  Fuel clause revenues were
offset by fuel and purchased power expenses and, therefore, had no net effect on
earnings.

Short-term sales and other revenues were $105 million in 1998 compared to $109
million in 1997, a decrease of $4 million or 4%.  Boston Edison experienced a
$20 million decrease in short-term power sales revenues consistent with an 11%
reduction in short-term kWh sales, primarily as a result of the expiration of
certain short-term sales contracts.  The decrease has no net impact on earnings
as it is offset by a corresponding decrease in fuel and purchased power
expenses.  Additional decreases include a $2 million decrease from Boston
Edison's Harbor Electric Energy Company subsidiary and a $2 million decrease
from BETG.  These decreases were partially offset by the recognition of $20
million of revenue related to the support of standard offer service provided by
Boston Edison's fossil generating units prior to divestiture.

Operating expenses

Fuel and purchased power expense was $568 million in 1998 compared to $679
million in 1997, a decrease of $111 million or 16%.  Fuel expense related to
fossil generation units decreased approximately $161 million.  This decrease
reflects the divestiture of those units in May 1998.  Purchased power expense
increased approximately $94 million, an increase of 26%.  This increase reflects
Boston Edison's purchased power requirements in the absence of its fossil
generating units.  Prior to the retail access date, the fuel and purchased power
clause component of its electric rates allowed Boston Edison to adjust its rates
to fully collect fuel and purchased power costs.  Since the retail access date,
Boston Edison similarly adjusts its electric rates to fully collect the cost of
providing standard offer and default service.  Fuel and purchased power expense
reflects a reduction of approximately $7 million related to these mechanisms in
1998.  In 1997, fuel and purchased power expense reflects an increase of
approximately $37 million related to these mechanisms.  Due to the rate
adjustment mechanisms, this net reduction in operating expenses of $44 million
had no net impact on earnings.

Operations and maintenance expense was $386 million in 1998 compared to $423
million in 1997, a decrease of $37 million or 9%.  The most significant driver
of this decrease was a $28 million decrease in power production expenses
primarily due to the fossil divestiture in May 1998.  Employee benefit expenses
decreased by approximately $24 million due to lower pension and other
postretirement benefit costs.  These favorable impacts were partially offset by
a $4 million increase in general and administrative expenses primarily due 

                                       17
<PAGE>
 
to spending related to electric industry restructuring and the year 2000
computer issue and a $7 million increase in expenses related to parent company
costs and unregulated ventures.

Depreciation and amortization expense was $192 million in 1998 compared to $189
million in 1997, an increase of $3 million or 1%.  Depreciation on distribution
utility plant increased approximately $10 million, as Boston Edison was required
to increase this depreciation under the terms of its settlement agreement.  This
increase was partially offset by an $8.7 million nonrecurring charge recorded in
1997 to reflect the removal of specific nuclear-related intangible assets from
the balance sheet.  These intangible assets related to costs incurred for plant
design and safety studies.  These studies were superceded by updated studies.

Demand side management (DSM) and renewable energy programs expense was $52
million in 1998 compared to $30 million in 1997, an increase of $22 million or
74%.  This increase reflects an increase in the required spending for DSM
programs in 1998.  In addition, the renewable energy programs expense of $8
million in 1998 is the result of a new state mandate for the funding of
renewable energy that became effective March 1, 1998.  Renewable energy expenses
are collected through a separate rate mechanism and, therefore, have no net
effect on earnings.

Property and other taxes were $84 million in 1998 compared to $106 million in
1997, a decrease of $22 million or 21%.  The decrease is due to a decrease in
municipal property taxes resulting from the fossil divestiture.

Operating income taxes were $98 million in 1998 compared to $94 million in 1997,
an increase of $4 million or 4%.  The increase in operating income taxes is
primarily the result of a $4 million reduction in investment tax credit
amortization due to the divestiture of the fossil generating assets and non-
deductible expenses incurred at BETG.  Refer to Note C to the Consolidated
Financial Statements for more information on income taxes.

Other income (expense), net

Other expense, net of tax was $11.8 million in 1998 compared to $6.4 million in
1997, an increase of $5.4 million or 85%. Prior to the consideration of tax
benefits, other expenses were $35.9 million in 1998 compared to $17.7 million in
1997, an increase of $18.2 million. BETG's equity losses in the RCN and
EnergyVision joint ventures were $19.7 million in 1998 compared to $9.2 million
in 1997. The $10.5 million increase is primarily due to RCN which began
operations in the second quarter of 1997. 1998 also reflects $23.2 million of
costs related to the fossil divestiture that is offset by the recognition of
investment tax credits disclosed below, $3.5 million related to discontinued
operations of BETG's subsidiary, Coneco and $2.6 million of costs associated
with the referendum that sought to repeal the Massachusetts electric industry
restructuring law. These negative amounts are offset in 1998 by $7.6 million of
interest income due to levels of cash on hand as a result of the proceeds from
the fossil divestiture. In addition to the other items mentioned, 1997 results
reflect a charge of $12.9 million from the nuclear asset impairment which is
discussed further in Note B to the Consolidated Financial Statements. Offsetting
the negative impacts in 1997 was $5.0 million of interest income received
related to the favorable outcome of an IRS audit. Other miscellaneous income was
$5.5 million in 1998 and other miscellaneous expense was $0.6 million in 1997.
Income tax benefits related to other expenses were $24.1 million in 1998 and
$11.3 million in 1997. The 1998 income tax benefit includes $10.9 million
related to the

                                       18
<PAGE>

recognition of previously deferred investment tax credits associated with the
fossil generating stations.
 
Interest charges

Interest charges on long-term debt were $83 million in 1998 compared to $92
million in 1997, a decrease of $9 million or 10%.  The decrease reflects $6
million due to the maturing of $100 million of 5.95% debentures in March 1998
and the cessation of amortization of the associated redemption premiums and $2
million due to the redemption of a $100 million 6.662% bank loan in June 1998.

Short-term interest charges were $9 million in 1998 compared to $15 million in
1997, a decrease of $6 million or 40%.  Approximately $7 million of the decrease
is due to the redemption of Boston Edison's outstanding short-term debt with
proceeds from the fossil divestiture.  This was partially offset by $1 million
in interest charges from BEC's line of credit entered into in 1998.

Preferred stock dividends

Preferred stock dividends were $9 million in 1998 compared to $13 million in
1997, a decrease of $4 million or 33%.  Preferred stock dividends decreased $1
million as a result of Boston Edison's redemption of 40,000 shares of 7.27%
series cumulative preferred stock in May 1998 and 1997 and the remaining 320,000
shares in July 1998.  An additional $3 million decrease was due to the
redemption of 400,000 shares of 7.75% series cumulative preferred stock in July
1998 and 400,000 shares of 8.25% series in June 1997.  Refer to Note G to the
Consolidated Financial Statements.

1997 versus 1996

Basic and diluted earnings per common share were $2.71 in 1997 compared to $2.61
in 1996, a 3.8% increase as described below.

Operating revenues

Operating revenues increased 6.6% over 1996 as follows:
<TABLE> 
<S>                                           <C> 
(in thousands)
------------------------------------------------------
Retail revenues                               $ 88,484
Wholesale revenues                                (765)
Short-term sales and other revenues             21,956
------------------------------------------------------
   Increase in operating revenues             $109,675
======================================================
</TABLE> 
Retail revenues were $1,523 million in 1997 compared to $1,435 million in 1996,
an increase of $88 million or 6%.  Retail base revenues, consistent with the
0.8% increase in kWh sales in 1997, were $923 million compared to $920 million
in 1996.  Increases due to warmer than normal temperatures in June and July,
cooler temperatures in October and December and the stronger local economy were
offset by milder than normal winter conditions during the first quarter of 1997
and lower industrial sales.  Industrial sales continued to be adversely affected
by the decline in manufacturing activity in the Boston Edison service territory.
In addition, revenues in 1996 reflect one more day of sales due to the leap
year.  The increase in retail electric revenues is primarily due to the timing
effect of fuel and purchased power cost recovery.  An $88 million increase in
fuel and purchased power clause revenues reflects the recovery of substantial
prior year undercollections.  These higher revenues are offset by higher fuel
and purchased power expenses and, therefore, have no net effect on earnings.
Pilgrim performance revenues, which varied annually based on the operating
performance of Pilgrim Station 

                                       19
<PAGE>
 
prior to the retail access date, decreased $4 million primarily due to a lower
annual capacity factor effective November 1996 reflecting the scheduled
refueling and maintenance outage in the first quarter of 1997.

Short-term sales and other revenues were $109 million in 1997 compared to $87
million in 1996, an increase of $22 million or 25%.  Short-term sales revenues
increased approximately $16 million.  This was due to the continued reduction in
available nuclear energy supply in New England combined with a 42% increase in
fossil generation allowing for increased sales to the power exchange.  Revenues
from these short-term sales resulted in a corresponding reduction to future fuel
and purchased power billings to retail customers and, therefore, had no net
effect on earnings.

Operating expenses

Fuel and purchased power expense was $679 million in 1997 compared to $589
million in 1996, an increase of $90 million or 15%.  This increase reflects $57
million related to the timing effect of fuel and purchased power cost recovery.
In addition, company fuel expense increased $50 million primarily due to the
increase in fossil generation.  These increases were partially offset by a $22
million decrease in power exchange purchases.  These fuel and purchased power
expenses are substantially recoverable through fuel and purchased power
revenues.

Operations and maintenance expense was $423 million in both 1997 and 1996.  The
$6 million incremental impact associated with service restoration efforts
resulting from the severe snow storm in April 1997 that struck the greater
Boston area offset the impact of lower spending from cost control efforts and
significantly less overhaul activity at the fossil generating units.

Depreciation and amortization expense was $189 million in 1997 compared to $186
million in 1996, an increase of $3 million or 2%.  An $8.7 million nonrecurring
charge was recorded to depreciation expense in the third quarter of 1997 to
reflect the removal of specific nuclear-related intangible assets from the
balance sheet.  These intangible assets related to costs incurred for plant
design and safety studies.  These studies were superceded by updated studies.
In 1996 a $5.2 million adjustment was recorded to correct the accumulated
depreciation balance of certain large computer equipment.

Operating income taxes were $94 million in 1997 compared to $88 million in 1996,
an increase of $6 million or 6%.  Income taxes increased as a result of higher
net income offset by the impact of the favorable outcome of an Internal Revenue
Service (IRS) appeal received in the third quarter related to investment tax
credits (ITC).  This also resulted in an increase in unamortized ITC which is
being reflected as a reduction to income tax expense over the life of the
related assets.  Refer to Note C to the Consolidated Financial Statements for
more information on income taxes.

Other income (expense), net

Other expense, net was $6 million in 1997 compared to income of $4 million in
1996, a net increase in expense of $10 million.  1997 reflects the charge of
approximately $13 million ($8 million after tax) from the nuclear asset
impairment which is further discussed in Note B to the Consolidated Financial
Statements in addition to BETG equity losses of $9 million ($6 million after
tax).  These decreases were partially offset by approximately $5 million ($3
million after tax) in interest income from the IRS appeal.

                                       20
<PAGE>
 
Interest charges

Interest charges on long-term debt were $92 million in 1997 compared to $95
million in 1996, a decrease of $3 million or 2%.  The decrease reflects $6
million due to the maturing of $100 million of 5.70% debentures in March 1997
and the cessation of amortization of the associated redemption premiums.  This
was partially offset by a $5 million increase due to the March 1997 issuance of
a $100 million 6.662% bank loan due in 1999.  The decrease also reflects $2
million from the maturity of $100 million of 5 1/8% debentures in March 1996.

Allowance for borrowed funds used during construction (AFUDC), which represents
the financing costs of construction, was $1 million in 1997 compared to $2
million in 1996, a decrease of $1 million or 48%.  AFUDC decreased primarily due
to a lower average construction work in progress (CWIP) balance in 1997.  The
1996 average CWIP balance included nuclear fuel purchased in anticipation of
Pilgrim Station's scheduled refueling outage in the first quarter of 1997.

Preferred stock dividends

Preferred stock dividends were $13 million in 1997 compared to $15 million in
1996, a decrease of $2 million or 14%.  The decrease in preferred stock
dividends is the result of the redemption of 20,000 of mandatory and 20,000 of
optional shares of 7.27% series cumulative preferred stock in May 1997 and
400,000 shares of 8.25% series in June 1997.  Refer to Note G to the
Consolidated Financial Statements.

Electric Sales and Revenues

Electric sales

Total kWh sales increased 2.3%.  The 2.0% increase in 1998 retail kWh sales was
primarily due to the positive impact of a continued strong local economy on
commercial customers.  The commercial sector represents approximately 50% of
electric operating revenues.  The Boston area commercial office vacancy rate is
at a 17-year low.  In addition, the Massachusetts employment rate increased 2.8%
over 1997.  These positive impacts associated with the economic conditions along
with warmer than normal summer weather were partially offset by the mild winter
weather conditions in the first quarter of 1998.  Wholesale sales increased
primarily due to a 32% increase in sales to Pilgrim contract customers.  That
increase reflects a 97% capacity factor in 1998, the plant's highest annual
performance ever achieved.  The lower level of sales in 1997 reflected that
year's refueling outage.  Short-term sales decreased due to lower sales to other
contract customers.

Retail kWh sales increased 0.8% in 1997.  This was primarily attributable to the
commercial sector.  The commercial increase reflects the impact of a continued
strong economy in the Boston area and very warm temperatures in June and July
and cooler than normal temperatures in the fourth quarter.  Hotel occupancy
rates and non-manufacturing employment continued to increase in 1997.
Residential revenues were also positively impacted by the weather.  These
positive impacts were offset by milder winter weather in the first quarter of
1997 and declines in manufacturing employment affecting the industrial sector.
In addition, revenues in 1996 reflect one more day of sales due to the leap
year.  Total kWh sales increased 3.1% as a result of the continued reduction in
available nuclear energy supply in New England.  This reduction, combined with
an increase in fossil generation allowed for increased sales to the power
exchange.

                                       21
<PAGE>
 
Electric revenues

Boston Edison's electric delivery business provides standard offer customers
service at rates designed to give 10% savings from the rates in effect prior to
the retail access date.  As part of the Massachusetts restructuring legislation
enacted in November 1997, these customers will realize an additional 5% average
savings, after an adjustment for inflation, by September 1, 1999.  Boston Edison
expects to meet this additional rate reduction as a result of the proceeds
received from the divestiture of the fossil generating assets.  All Boston
Edison distribution customers must pay a transition charge as a component of
distribution electric rates.  The purpose of the transition charge is to allow
Boston Edison to collect certain costs from customers which would not be
collected in the competitive energy supply market.  Such costs include the above
market costs related to purchased power contracts and its own generating
stations, as well as the cost to decommission Pilgrim Station.  The plant and
regulatory asset balances which will be recovered through the transition charge
until 2009 were approved by the DTE.  The other costs will be reviewed by the
DTE on an annual basis.  Under the settlement agreement, the aggregate amount of
the transition charge is reduced by the net proceeds from fossil divestiture.
The cost of providing standard offer service, which includes fuel and purchased
power costs, is recovered from customers on a fully reconciling basis.  The
price of default service is intended to reflect the average competitive market
price for power.

As part of the settlement agreement, the annual performance adjustment charge
ceased and the cost recovery mechanism for Pilgrim Station changed effective
March 1, 1998.  Approximately 25% of the operations and capital costs, including
a return on investment, continues to be collected under wholesale contracts with
other utilities and municipalities.  Boston Edison's long-term power sales
contracts with the utilities, Commonwealth Electric Company and Montaup Electric
Company, will be terminated upon the closing of the sale of Pilgrim Station to
Entergy.  Boston Edison's contracts with the various municipalities remain in
place.  However, upon the Pilgrim sale closing date, Boston Edison will purchase
power for resale to the municipalities under a purchase power agreement entered
into with Entergy.  Through the sale closing date, Boston Edison will share 25%
of any profit or loss from the sale of Pilgrim's output with distribution
customers through the transition charge.  In addition, Boston Edison will obtain
transition payments up to a maximum of $23 million per year depending on the
level of costs incurred for such items as property taxes, insurance, regulatory
fees and security requirements.

Under its settlement agreement, Boston Edison's distribution rates will remain
unchanged through December 31, 2000, subject to a minimum and maximum return on
average common equity (ROE).  The ROE is subject to a floor of 6% and a ceiling
of 11.75%.  If the ROE is below 6%, Boston Edison is authorized to add a
surcharge to distribution rates in order to achieve the 6% floor.  If the ROE is
above 11%, it is required to adjust distribution rates by an amount necessary to
reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5%
by 100%.  No adjustment is made if the ROE is between 6% and 11%.  The cost of
providing transmission service to distribution customers is recovered on a fully
reconciling basis.

Boston Edison filed proposed adjustments to its standard offer and transition
charges with the DTE in November 1998.  The DTE approved these proposed
adjustments to be effective January 1, 1999.  The DTE is continuing to examine
Boston Edison's cost recovery mechanisms.  The rates provide an approximate 12%
reduction from inflation-adjusted pre-retail access date rates.

                                       22
<PAGE>
 
Liquidity

Cash requirements for utility plant expenditures have been met in recent years
with internally generated funds.  These funds are cash flows from operating
activities, adjusted to exclude changes in working capital and the payment of
dividends.  During 1998, 1997 and 1996 internal generation of cash provided 97%,
211% and 177%, respectively of plant expenditures.  The capital spending level,
excluding nuclear fuel, forecasted for 1999 is $233 million which includes
amounts for utility plant and the capital requirements of the nonutility
ventures.  This spending level also includes the 1999 portion of business system
replacements discussed below.  The capital spending level over the next five
years is forecasted to be approximately $960 million.  In addition to capital
expenditures, debt and preferred stock payment requirements are $1.6 million in
1999, $166.6 million in 2000, $51.6 million in 2001, $1.6 million in 2002 and
$151.65 million in 2003.

Boston Edison supplements internally generated funds as needed, primarily
through the issuance of short-term commercial paper and bank borrowings.  Boston
Edison has authority from the Federal Energy Regulatory Commission (FERC) to
issue up to $350 million of short-term debt.  Boston Edison has a $200 million
revolving credit agreement with a group of banks as well as other arrangements
with several banks to provide additional short-term credit on an uncommitted and
as available basis.  No amount was outstanding under the revolving credit
agreement as of December 31, 1998.

In December 1998, Boston Edison filed a securitization financing plan with the
DTE.  Under the plan, a special purpose entity (SPE) will be formed as a wholly
owned subsidiary of Boston Edison.  The SPE will pay Boston Edison an amount
equal to the generation-related regulatory assets to be securitized by issuing
debt securities.  A portion of the net proceeds will be used to fund the nuclear
decommissioning trust.  In addition, Boston Edison may also utilize a portion of
the proceeds to reduce capitalization and for general corporate purposes.
Boston Edison will remit amounts to the SPE as these amounts are collected from
customers through a separate component of the transition charge over the
settlement period.  A DTE order regarding the securitization plan is expected by
the second quarter of 1999.

BEC established a $225 million revolving credit agreement with a group of banks
effective through July 2001.  The purpose of the credit agreement is to provide
financing to the holding company for general corporate purposes, invest in its
subsidiaries and fund the common share repurchase program discussed below.
Approximately $78 million was outstanding under this agreement as of 
December 31, 1998.

Refer to Note H to the Consolidated Financial Statements for more information
regarding these debt agreements.

In April 1998, Boston Edison announced a common share repurchase program under
which it would repurchase up to four million of its common shares.  BEC has
assumed this program since the reorganization to a holding company structure.
Through December 31, 1998, approximately 1.3 million shares have been
repurchased at a total cost of approximately $53 million.  Under this program,
shares are repurchased through open market, block or privately-negotiated
transactions, or a combination.  The timing and actual number of shares
repurchased will be impacted by market conditions.

                                       23
<PAGE>
 
Year 2000 Computer Issue

The year 2000 issue is the result of computer programs that were written using
two digits rather than four to define an applicable year.  If computer programs
with date-sensitive functions are not year 2000 compliant, they may recognize a
date using "00" as the year 1900 rather than the year 2000.  This could result
in system failures or miscalculations causing disruptions of operations,
including, among other things, a temporary inability to process transactions and
engage in other normal business activities.  BEC has a year 2000 program in
place to address the risk of non-compliant internal business software, internal
non-business software and embedded chip technology and external noncompliance of
third parties.

BEC is addressing the year 2000 issue on a coordinated basis.  BEC has
inventoried and assessed all date-sensitive information and transaction
processing computer systems and has determined that approximately one-third of
business critical systems software need modification or replacement.  BEC
defines its business critical systems as those which are necessary for the
delivery of and billing and accounting for electricity to its customers.  Plans
have been developed and are being implemented to correct and test all affected
systems, with priorities assigned based on the importance of the supported
activity.  As systems are being remediated or replaced, they are tested for
operational and year 2000 compliance in their own environment.  After completion
of implementation, the systems are then tested for their integration and
compliance with other interactive systems.  Management estimates that
approximately 70% of the efforts necessary to implement and test its critical
computer systems to alleviate the year 2000 issue are complete and expects to
complete all efforts by the end of the second quarter of 1999.  In addition, all
other non-critical systems have been inventoried and assessed.  Approximately
one-third of these systems require modification or replacement.  Under the year
2000 plan, each non-critical system has a form of readiness acceptance
commensurate with its business importance.  The more important and complex
systems are being tested as a means of acceptance.  Less important and non-
complex systems may refer to industry test results, vendor test results and/or
vendor statements of readiness as a means of acceptance.  Management expects to
complete the remediation, replacement and testing of at least 95% of its non-
critical computer systems by the end of the second quarter of 1999.  All non-
critical systems are scheduled for completion by the third quarter of 1999.

BEC has also inventoried its non-information technology systems that may be
date-sensitive and that use embedded technology such as micro-controllers or
micro-processors.  Approximately 27% of these systems require modification or
replacement.  The three categories of these systems are (1) telecommunications,
(2) distribution system controls and (3) other distribution equipment.  BEC is
55%, 30% and 80% complete, respectively, with its efforts to resolve and
remediate the systems that have been identified as year 2000 non-compliant
within each category.  BEC expects completion of resolution and testing by the
end of the second quarter of 1999.

Costs incurred to remediate non-compliant systems are expensed as incurred.  In
addition, a decision has been made to use this opportunity to upgrade some of
BEC's inefficient centralized business systems.  Systems' replacement costs will
be capitalized and amortized over future periods.  BEC expects the modification
and testing of its information and transaction processing systems to cost $32
million.  BEC has expended $19 million on this project through December 31,
1998.  BEC has funded and plans on continuing to fund all costs related to year
2000 with internally generated cash flows.

                                       24
<PAGE>
 
In addition to its internal efforts, BEC has initiated formal communications
with its significant suppliers, service providers and other vendors to determine
the extent to which BEC may be vulnerable to their failure to correct their own
year 2000 issues.  BEC has received responses from over 500 third party vendors
including all business critical vendors.  Approximately 40% of the vendors
indicated their systems would not be adversely impacted by year 2000 issues.
All of the vendors contacted have indicated that they will be year 2000
compliant by the end of the fourth quarter of 1999.  In addition, BEC has
contacted all of its significant power suppliers.  Each has indicated that they
either are or will be year 2000 compliant by the end of the fourth quarter of
1999.  In addition to the risk faced from its dependence on third party
suppliers for year 2000 compliance, BEC has a risk that power will not be
available from the New England Power Pool (NEPOOL) for the purchase and
distribution to Boston Edison's customers.  Should NEPOOL fail to resolve its
year 2000 issues as planned, there would be an adverse impact on Boston Edison
and its customers.  To mitigate this risk, efforts are being coordinated with
NEPOOL to establish inter-utility testing guidelines to determine year 2000
readiness.  Boston Edison is also a participant in the NEPOOL/ISO New England
Year 2000 Joint Oversight Committee which has responsibility for the operational
reliability of NEPOOL.  Overall regional activities, including those of
NEPOOL/ISO New England, will be coordinated by the Northeast Power Coordinating
Council, whose activities will be incorporated into the interregional
coordinating effort by the North American Electric Reliability Council.  The
target for the completion of this effort is mid-1999.

In addition, parts of the global infrastructure, including national banking
systems, electrical power grids, gas pipelines, transportation facilities,
communications and government activities, may not be fully functional after 1999
due to the year 2000 issue.  Infrastructure failures could significantly reduce
BEC's ability to acquire energy and its ability to serve its customers as
effectively as they are now being served.

BEC believes that its efforts to address the year 2000 issue will allow it to
successfully avoid any material adverse effect on its operations or financial
condition.  However, it recognizes that failing to resolve year 2000 issues on a
timely basis would, in a most reasonable worst case scenario, significantly
limit its ability to acquire and distribute energy or process its daily business
transactions for a period of time, especially if such failure is coupled with
third party or infrastructure failures.  Similarly, BEC could be significantly
affected by the failure of one or more significant suppliers, customers or
components of the infrastructure to conduct their respective operations normally
after 1999.  Adverse effects on BEC could include, among other things, business
disruption, increased costs, loss of business and other similar risks.

BEC's year 2000 program includes contingency plans. If required, these plans are
intended to address both internal risks as well as potential external risks
related to vendors, customers and energy suppliers. Plans have been developed in
conjunction with available national and regional guidance and are based on
system emergency plans that were developed and successfully tested over the past
several years. Included within its contingency plans are procedures for the
procurement of short-term power supplies and emergency distribution system
restoration procedures. The contract with ISO New England requires that ISO New
England dispatch at all times sufficient resources to meet total New England
load requirements. ISO New England has the responsibility and authority to
dispatch all regional generation sources including maintaining sufficient
operating reserves to respond to unanticipated system conditions. ISO New
England, in conjunction with the New England Power Pool has an extensive year
2000 readiness program underway to ensure that it will have sufficient
generation and transmission resources to

                                       25
<PAGE>

reliably serve load. In addition, ISO New England plans to increase its
operating reserves during the early year 2000 period from approximately 15% to
40%.
 
The foregoing discussion regarding year 2000 project timing, effectiveness,
implementation and costs includes forward-looking statements that are based on
management's current evaluation using available information.  Factors that might
cause material changes include, but are not limited to, the availability of key
year 2000 personnel, the readiness of third parties and BEC's ability to respond
to unforeseen year 2000 complications.

Other Matters

Environmental

Boston Edison is an owner or operator of approximately 20 properties where oil
or hazardous materials were spilled or released.  Boston Edison also continues
to face possible liability as a potentially responsible party in the cleanup of
five multi-party hazardous waste sites in Massachusetts and other states where
it is alleged to have generated, transported or disposed of hazardous waste at
the sites.  Refer to Note K.4. to the Consolidated Financial Statements for more
information regarding hazardous waste issues.

Uncertainties continue to exist with respect to the disposal of both spent
nuclear fuel and low-level radioactive waste resulting from the operation of
nuclear generating facilities. The United States Department of Energy (DOE) is
responsible for the ultimate disposal of spent nuclear fuel.  However,
uncertainties regarding the DOE's schedule of acceptance of spent fuel for
disposal continue to exist.  Under the purchase and sale agreement with Entergy,
Entergy will assume full liability and responsibility for decommissioning and
waste disposal at Pilgrim Station.  Refer to Note D to the Consolidated
Financial Statements for further discussion regarding nuclear decommissioning
and waste disposal.

Public concern continues regarding electromagnetic fields (EMF) associated with
electric transmission and distribution facilities and appliances and wiring in
buildings and homes.  Such concerns have included the possibility of adverse
health effects caused by EMF as well as perceived effects on property values.
Some scientific reviews conducted to date have suggested associations between
EMF and potential health effects, while other studies have not substantiated
such associations.  The National Research Council previously reported that there
is no conclusive evidence that exposure to EMF from power lines and appliances
presents a health hazard.  The panel of scientists, working with the National
Academy of Sciences, report that more than 500 studies over the last several
years have produced no proof that EMF causes leukemia or other cancers or harms
human health in other ways.  Boston Edison continues to support research into
the subject and participates in the funding of industry-sponsored studies.  It
is aware that public concern regarding EMF in some cases has resulted in
litigation, in opposition to existing or proposed facilities in proceedings
before regulators or in requests for legislation or regulatory standards
concerning EMF levels.  It has addressed issues relative to EMF in various legal
and regulatory proceedings and in discussions with customers and other concerned
persons; however, to date it has not been significantly affected by these
developments.  Boston Edison continues to monitor all aspects of the EMF issue.

                                       26
<PAGE>
 
Industry and corporate restructuring legal proceedings

The DTE order approving the Boston Edison settlement agreement and the DTE order
approving the formation of BEC as a holding company were appealed by certain
parties to the Massachusetts Supreme Judicial Court (SJC).  In December 1998,
the SJC dismissed the appeal of the order approving the holding company
formation.  One settlement agreement appeal remains pending, however there has
to date been no briefing, hearing or other action taken with respect to this
proceeding.

In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.

Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.

Regulatory proceedings

In October 1997, the DTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings began in the fourth quarter of 1998 and are expected to be completed in
the first half of 1999.

Each of the Reading Municipal Light Department, the Littleton Electric Light
Department and the West Boylston Municipal Light Department have filed separate
claims for arbitration in Massachusetts alleging that the proposed transfer of
Pilgrim Station constitutes a breach of their respective power sale agreements
and seeking to terminate those agreements.  The remaining municipal light
departments have also indicated that they plan to file similar claims for
arbitration.  Boston Edison has requested the FERC to exercise its pre-emptive
authority to consider the claims of the municipal light departments.  In the
event that either the FERC determines, or as a result of the arbitrations, that
the contracts should be terminated, Boston Edison would continue to be obligated
to purchase power from Entergy that it intended to resell to the municipal light
departments.  Boston Edison may not be able to resell such power in the short-
term power exchange at a price equal to or greater than the price it is required
to pay to Entergy.  However, Boston Edison has filed at the DTE for recovery of
any such shortfall as part of its Pilgrim divestiture filing through the
transition charge.

Management is currently unable to determine the outcome of these proceedings
however, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.

Other litigation

In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison.  The town claims that Boston Edison
has wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts electric industry

                                       27
<PAGE>
 
restructuring legislation.  Boston Edison has disputed the town's claim and will
vigorously defend itself.  In addition to this pending litigation, Boston Edison
and the town of Plymouth are also parties in proceedings before the Appellate
Tax Board and the DTE concerning substantially the same dispute.  Management is
unable to determine the ultimate outcome of these proceedings however, if an
unfavorable outcome were to occur, there could be a material adverse impact on
business operations, the consolidated financial position or results of
operations for a reporting period.

In the normal course of its business BEC and its subsidiaries are also involved
in certain other legal matters.  Management is unable to fully determine a range
of reasonably possible legal costs in excess of amounts accrued.  Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position.  However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.

Refer to Note K.6. to the Consolidated Financial Statements for more information
on legal matters.

Interest rate risk

BEC is exposed to changes in interest rates.  Carrying amounts and fair values
of mandatory redeemable cumulative preferred stock, sewage facility revenue
bonds and unsecured debt as of December 31, 1998, are as follows:
<TABLE>
<CAPTION>
 
                                   Carrying    Fair    Weighted average
(in thousands)                      amount    value      interest rate
---------------------------------  --------  --------  -----------------
<S>                                <C>       <C>       <C>
Mandatory redeemable cumulative
 preferred stock                   $ 49,040  $ 54,190              8.00%
Sewage facility revenue bonds      $ 30,900  $ 33,914              7.32%
Unsecured debt                     $930,000  $994,294              7.79%
</TABLE>

Safe harbor cautionary statement

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

The preceding sections include certain forward-looking statements about the
merger with CES, the divestiture of nuclear generating assets, operating
results, year 2000 and environmental and legal issues.

The merger with CES could differ from current expectations.  This could occur if
the requisite approvals are delayed or not obtained.

The nuclear divestiture plan could differ from current expectations.  The timing
and a final closing of the sale may differ from management's expectations if
required approvals are delayed or not obtained.

The impacts of continued cost control procedures on operating results could
differ from current expectations.  The effects of changes in economic

                                       28
<PAGE>
 
conditions, tax rates, interest rates, technology and the prices and
availability of operating supplies could materially affect the projected
operating results.

The timing and total costs related to the year 2000 plan could differ from
current expectations.  Factors that may cause such differences include the
ability to locate and correct all relevant computer codes and the availability
of personnel trained in this area.  In addition, BEC cannot predict the nature
or impact on operations of third party noncompliance.

The impacts of various environmental and legal issues could differ from current
expectations.  New regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than expected.  The
effects of changes in specific hazardous waste site conditions and cleanup
technology could affect the estimated cleanup liabilities.  The impacts of
changes in available information and circumstances regarding legal issues could
affect the estimated litigation costs.

                                       29
<PAGE>
 
Item 8.  Financial Statements and Supplementary Financial Information
---------------------------------------------------------------------
<TABLE>
<CAPTION>
Consolidated Statements of Income
                                                                                                  years ended December 31,
(in thousands, except earnings per share)                                                      1998         1997          1996
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>         <C>          <C>
Operating revenues                                                                          $1,622,515   $1,778,531     $1,668,856
----------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
    Fuel and purchased power                                                                   567,806      679,131        588,893
    Operations and maintenance                                                                 386,340      423,040        422,642
    Depreciation and amortization                                                              191,701      189,489        186,117
    Demand side management and
     renewable energy programs                                                                  51,839       29,790         30,825
    Taxes-property and other                                                                    84,091      106,428        107,086
    Income taxes                                                                                97,798       93,709         88,313
----------------------------------------------------------------------------------------------------------------------------------
     Total operating expenses                                                                1,379,575    1,521,587      1,423,876
----------------------------------------------------------------------------------------------------------------------------------
 
Operating income                                                                               242,940      256,944        244,980
 
Other income (expense), net                                                                    (11,811)      (6,392)         3,741
----------------------------------------------------------------------------------------------------------------------------------
Operating and other income                                                                     231,129      250,552        248,721
----------------------------------------------------------------------------------------------------------------------------------
Interest charges:
    Long-term debt                                                                              82,951       92,489         94,823
    Other                                                                                        8,800       14,610         14,644
    Allowance for borrowed funds used
     during construction                                                                        (1,668)      (1,189)        (2,292)
----------------------------------------------------------------------------------------------------------------------------------
     Total interest charges                                                                     90,083      105,910        107,175
----------------------------------------------------------------------------------------------------------------------------------
 
Net income                                                                                     141,046      144,642        141,546
 
Preferred dividends of subsidiary                                                                8,765       13,149         15,365
----------------------------------------------------------------------------------------------------------------------------------
Earnings available for common
 shareholders                                                                                $ 132,281   $  131,493     $  126,181
==================================================================================================================================
 
Weighted average common shares outstanding:
    Basic                                                                                       47,973       48,515         48,265
    Diluted                                                                                     48,149       48,562         48,265
 
Earnings per common share:
    Basic                                                                                        $2.76        $2.71          $2.61
==================================================================================================================================
    Diluted                                                                                      $2.75        $2.71          $2.61
==================================================================================================================================

Consolidated Statements of Retained Earnings
                                                                                                  years ended December 31,
(in thousands)                                                                                 1998         1997           1996
----------------------------------------------------------------------------------------------------------------------------------
Balance at the beginning of the year                                                        $  328,802   $  292,191     $  257,749
    Net income                                                                                 141,046      144,642        141,546
----------------------------------------------------------------------------------------------------------------------------------
     Subtotal                                                                                  469,848      436,833        399,295
----------------------------------------------------------------------------------------------------------------------------------
Dividends declared:
    Preferred stock                                                                              8,765       13,149         15,365
    Common stock                                                                                90,610       91,208         90,834
----------------------------------------------------------------------------------------------------------------------------------
     Subtotal                                                                                   99,375      104,357        106,199
----------------------------------------------------------------------------------------------------------------------------------
Provision for preferred stock
 redemption and issuance costs (a)                                                               7,833        3,674            905
Common share repurchase program                                                                  2,131            0              0
----------------------------------------------------------------------------------------------------------------------------------
Balance at the end of the year                                                              $  360,509   $  328,802     $  292,191
==================================================================================================================================
</TABLE> 
(a)  Refer to Note A.7. to the Consolidated Financial Statements.
 
The accompanying notes are an integral part of the consolidated financial
statements.

                                       30
<PAGE>
 
Consolidated Balance Sheets
<TABLE> 
<CAPTION> 
                                                                                                                      December 31,
(in thousands)                                                                                  1998                          1997
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>          <C> 
Assets
Utility plant in service, at
 original cost                                                                $2,720,681                 $4,457,831
  Less: accumulated depreciation                                                 926,020    $1,794,661    1,713,067     $2,744,764
----------------------------------------------------------------------------------------------------------------------------------
Generation-related regulatory
 asset, net                                                                                    366,336                           0
Nuclear fuel, net                                                                               68,706                      67,935
Construction work in progress                                                                   40,965                      33,291
----------------------------------------------------------------------------------------------------------------------------------
  Net utility plant                                                                          2,270,668                   2,845,990
Nonutility property                                                                             21,565                       8,137
Nuclear decommissioning trust                                                                  172,908                     151,634
Equity investments                                                                              84,770                      35,455
Other investments                                                                               30,206                       7,107
Current assets:
  Cash and cash equivalents                                                       98,989                      4,140
  Accounts receivable                                                            202,275                    207,093
  Accrued unbilled revenues                                                       14,322                     30,048
  Fuel, materials and supplies,
   at average cost                                                                15,474                     60,834
  Prepaids and other                                                             102,448       433,508       31,283        333,398
----------------------------------------------------------------------------------------------------------------------------------
Deferred debits:
  Regulatory assets                                                                            167,642                     195,370
  Other                                                                                         32,632                      45,256
----------------------------------------------------------------------------------------------------------------------------------
   Total assets                                                                             $3,213,899                  $3,622,347
==================================================================================================================================
 
Capitalization and Liabilities
Common equity                                                                               $1,051,898                  $1,073,454
Cumulative preferred stock of
 subsidiary                                                                                     92,040                     161,093
Long-term debt                                                                                 955,563                   1,057,076
Current liabilities:
  Long-term debt/preferred
   stock due within one year                                                  $      667                 $  102,667
  Notes payable                                                                   78,000                    137,013
  Accounts payable                                                               110,194                     87,015
  Accrued interest                                                                20,516                     24,289
  Dividends payable                                                               23,878                     24,748
  Other                                                                          183,664       416,919      128,061        503,793
----------------------------------------------------------------------------------------------------------------------------------
Deferred credits:
  Accumulated deferred income taxes                                                            348,557                     485,738
  Accumulated deferred investment
   tax credits                                                                                  45,930                      60,736
  Nuclear decommissioning liability                                                            176,578                     155,182
  Power contracts                                                                               58,415                      71,445
  Other                                                                                         67,999                      53,830
Commitments and contingencies
----------------------------------------------------------------------------------------------------------------------------------
   Total capitalization and liabilities                                                     $3,213,899                  $3,622,347
==================================================================================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.

                                       31
<PAGE>
 
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
                                                                 years ended December 31,
(in thousands)                                                    1998       1997       1996
----------------------------------------------------------------------------------------------
<S>                                                          <C>           <C>        <C>
Operating activities:
  Net income                                                  $  141,046   $144,642   $141,546
  Adjustments to reconcile net income to net
   cash provided by operating activities:
    Depreciation and amortization                                229,668    223,529    228,259
    Deferred income taxes and investment tax
     credits                                                    (152,798)   (21,664)    (4,506)
    Allowance for borrowed funds used during
     construction                                                 (1,668)    (1,189)    (2,292)
  Net changes in:
    Accounts receivable and accrued
     unbilled revenues                                            20,544     45,678    (11,719)
    Fuel, materials and supplies                                  29,565     (5,486)    (2,171)
    Accounts payable                                              23,179    (47,068)       609
    Other current assets and liabilities                         (28,705)    25,428    (44,514)
    Other, net                                                    14,021     (4,640)    50,815
----------------------------------------------------------------------------------------------
Net cash provided by operating activities                        274,852    359,230    356,476
----------------------------------------------------------------------------------------------
Investing activities:
  Plant expenditures (excluding AFUDC)                          (120,202)  (114,110)  (145,347)
  Proceeds from sale of fossil assets                            533,633          0          0
  Nuclear fuel expenditures                                      (26,182)    (4,089)   (52,967)
  Investments                                                    (81,589)   (27,689)   (34,314)
----------------------------------------------------------------------------------------------
Net cash provided by (used in) investing
 activities                                                      305,660   (145,888)  (232,628)
----------------------------------------------------------------------------------------------
Financing activities:
  Issuances/(repurchases):
   Common shares                                                 (53,285)       144     12,559
   Long-term debt                                                      0    100,000          0
  Redemptions:
   Preferred stock                                               (71,519)   (44,000)    (4,000)
   Long-term debt                                               (201,600)  (101,600)  (101,600)
  Net change in notes payable                                    (59,013)   (64,441)    75,013
  Dividends paid                                                (100,246)  (104,956)  (106,010)
----------------------------------------------------------------------------------------------
Net cash used in financing activities                           (485,663)  (214,853)  (124,038)
----------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
 equivalents                                                      94,849     (1,511)      (190)
Cash and cash equivalents at the
 beginning of the year                                             4,140      5,651      5,841
----------------------------------------------------------------------------------------------
Cash and cash equivalents at the end of the year                $ 98,989   $  4,140   $  5,651
==============================================================================================
 
Supplemental disclosures of cash flow information:
 
Cash paid during the year for:
  Interest, net of amounts capitalized                        $   89,720   $100,795   $100,810
  Income taxes                                                $  230,260   $ 99,326   $ 98,668
</TABLE>                                                          
The accompanying notes are an integral part of the consolidated financial
statements.                                                       

                                       32
<PAGE>
 
Notes to Consolidated Financial Statements

Note A. Summary of Significant Accounting Policies

1.  Nature of Operations

Boston Edison Company (Boston Edison) received final approval of its
reorganization plan to form a holding company structure from the Securities and
Exchange Commission (SEC) in May 1998.  Effective May 20, 1998 the holding
company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned
subsidiary of BEC.

Within its newly restructured industry, BEC has announced its intention to focus
its utility operations on the transmission and distribution of energy.  The sale
of Boston Edison's fossil generating assets to Sithe Energies, Inc. (Sithe) was
completed in May 1998.  In November 1998, Boston  Edison signed an agreement
with Entergy Nuclear Generating Company (Entergy) to sell its wholly owned
nuclear generating unit, Pilgrim Nuclear Power Station (Pilgrim).  BEC signed a
merger agreement with Commonwealth Energy System (CES) in December 1998 that
will create an energy delivery company serving approximately 1.3 million
customers located entirely within Massachusetts, including more than one million
electric customers in 81 communities and 240,000 gas customers in 51
communities.

Boston Edison currently supplies electricity at retail to an area of 590 square
miles, including the city of Boston and 39 surrounding cities and towns.  It
also supplies electricity at wholesale for resale to other utilities and
municipalities.  Electric operating revenues are approximately 90% retail and
10% wholesale.  Unregulated activities continue to be conducted through Boston
Energy Technology Group (BETG).  Refer to Note J to these Consolidated Financial
Statements for information on BEC's nonutility operations.

2.  Basis of Consolidation and Accounting

Under the new holding company structure the owners of Boston Edison's common
stock became BEC common shareholders.  Existing debt and preferred stock of
Boston Edison remained obligations of the regulated utility business.  Effective
June 25, 1998, BETG ceased being a subsidiary of Boston Edison and became a
wholly owned subsidiary of BEC.  The accompanying consolidated financial
statements reflect the results of operations and cash flows of Boston Edison
prior to the reorganization.  The consolidated balance sheet at December 31,
1997 reflects the financial position of Boston Edison which also included BETG.
The consolidated financial statements also include the activities of Boston
Edison's wholly owned subsidiary, Harbor Electric Energy Company (HEEC).  All
significant intercompany transactions have been eliminated.  Certain
reclassifications have been made to the prior year data to conform with the
current presentation.

Boston Edison follows accounting policies prescribed by the Federal Energy
Regulatory Commission (FERC) and the Massachusetts Department of
Telecommunications and Energy (DTE).  In addition, BEC and its subsidiaries are
subject to the accounting and reporting requirements of the SEC.  The
consolidated financial statements conform with generally accepted accounting
principles (GAAP).  As a rate-regulated company Boston Edison has been subject
to Statement of Financial Accounting Standards No. 71, Accounting for the
Effects of Certain Types of Regulation (SFAS 71), under GAAP.  The application
of SFAS 71 results in differences in the timing of recognition of certain
expenses from that of other businesses and industries.  As a result of the

                                       33
<PAGE>
 
Massachusetts electric industry restructuring legislation enacted in November
1997 and the DTE order regarding the related Boston Edison settlement agreement,
as of December 31, 1997, the provisions of SFAS 71 are no longer being applied
to the generation business.  The distribution business remains subject to rate-
regulation and continues to meet the criteria for application of SFAS 71.  Refer
to Note B to these Consolidated Financial Statements for more information on the
accounting implications of the electric utility industry restructuring.

The preparation of financial statements in conformity with GAAP requires BEC and
its subsidiaries to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period.  Actual results could differ
from these estimates.

3.  Revenues

Estimates of retail base (transmission and distribution) revenues for
electricity used by customers but not yet billed are recorded at the end of each
accounting period.

4.  Utility Plant

Utility plant is stated at original cost of construction.  The costs of
replacements of property units are capitalized.  Maintenance and repairs and
replacements of minor items are expensed as incurred.  The original cost of
property retired, net of salvage value, and the related costs of removal are
charged to accumulated depreciation.

5.  Depreciation and Nuclear Fuel Amortization

Depreciation of utility plant is computed on a straight-line basis using
composite rates based on the estimated useful lives of the various classes of
property.  Excluding the effect of the adjustment discussed below, the overall
composite depreciation rates were 3.28%, 3.30% and 3.33% in 1998, 1997 and 1996,
respectively.

Upon the completion of a review of Boston Edison's electric generating units,
management determined that the oldest and least efficient fossil units (Mystic
4, 5 and 6) were unlikely to provide competitively-priced power beyond the year
2000.  Therefore the estimated remaining economic lives of these units was
revised to five years in 1996.  These units were sold in May 1998.  Refer to
Note B to these Consolidated Financial Statements.

The cost of decommissioning Pilgrim Station is excluded from depreciation rates.
Refer to Note D to these Consolidated Financial Statements for a discussion of
nuclear decommissioning.  The cost of nuclear fuel is amortized based on the
amount of energy Pilgrim Station generates.  Nuclear fuel expense also includes
an amount for the estimated costs of ultimately disposing of spent nuclear fuel
and for assessments for the decontamination and decommissioning of United States
Department of Energy nuclear enrichment facilities.

6.  Deferred Nuclear Outage Costs

The incremental costs associated with nuclear refueling and maintenance outages
are deferred when incurred and amortized over Pilgrim Station's two-year
operating cycle.

                                       34
<PAGE>
 
7.  Costs Associated with Issuance and Redemption of Debt and Preferred Stock

Consistent with the recovery in electric rates, discounts, redemption premiums
and related costs associated with the issuance and redemption of long-term debt
and preferred stock are deferred.  The costs related to long-term debt are
recognized as an addition to interest expense over the life of the original or
replacement debt.  Beginning in 1996, consistent with an accounting order
received from the FERC, costs related to preferred stock issuances and
redemptions are reflected as a direct reduction to retained earnings upon
redemption or over the average life of the replacement preferred stock series as
applicable.

8.  Allowance for Borrowed Funds Used During Construction (AFUDC)

AFUDC represents the estimated costs to finance utility plant construction.  In
accordance with regulatory accounting, AFUDC is included as a cost of utility
plant and a reduction of current interest charges.  Although AFUDC is not a
current source of cash income, the costs are recovered from customers over the
service life of the related plant in the form of increased revenues collected as
a result of higher depreciation expense.  AFUDC rates in 1998, 1997 and 1996
were 5.88%, 6.04% and 5.87%, respectively, and represented only the cost of
short-term debt.

9.  Cash and Cash Equivalents

Cash and cash equivalents are comprised of highly liquid securities with
maturities of 90 days or less when purchased.  BEC's banking arrangement does
not require it to fund checks until they are presented for payment.  Therefore,
outstanding checks are included in cash and accounts payable until presented for
payment.

10.  Allowance for Doubtful Accounts

Accounts receivable are substantially recoverable.  This recovery occurs both
from customer payments and from the portion of customer charges that provides
for the recovery of bad debt expense.  Accordingly, a significant allowance for
doubtful accounts balance has not been maintained.

11.  Regulatory Assets

Regulatory assets represent costs incurred which are expected to be collected
from customers through future charges in accordance with agreements with
regulators.  These costs are expensed when the corresponding revenues are
received in order to appropriately match revenues and expenses.  The majority of
these costs is currently being recovered from customers over varying time
periods.  Refer to Note B to these Consolidated Financial Statements for
information regarding the recovery of regulatory assets related to the
generation business.

                                       35
<PAGE>
 
Regulatory assets consisted of the following:
<TABLE>
<CAPTION>
 
                                          December 31,
                                         1998      1997
---------------------------------------------------------
<S>                                    <C>       <C>
Power contracts                        $ 58,415  $ 71,445
Income taxes, net                        52,168    51,096
Redemption premiums                      23,419    27,019
Postretirement benefits costs            21,592    22,441
Decontamination and decommissioning      11,351    12,282
Other                                       697    11,087
---------------------------------------------------------
                                       $167,642  $195,370
=========================================================
</TABLE>

12.  Earnings Per Common Share

Basic earnings per common share (EPS) is calculated by dividing net income,
after deductions for preferred dividends, by the weighted average common shares
outstanding during the year.  Statement of Financial Accounting Standards No.
128, Earnings per Share, requires the disclosure of diluted EPS.  Diluted EPS is
similar to the computation of basic EPS except that the weighted average common
shares is increased to include the number of dilutive potential common shares.
Diluted EPS reflects the impact on shares outstanding of the deferred
(nonvested) shares and stock options granted under the Stock Incentive Plan.

The following table summarizes the reconciling amounts between basic and diluted
EPS:
<TABLE>
<CAPTION>
 
(in thousands, except per share amounts)        1998      1997      1996
--------------------------------------------------------------------------
<S>                                           <C>       <C>       <C>
 
Earnings available for common shareholders    $132,281  $131,493  $126,181
 
Basic EPS                                     $   2.76  $   2.71  $   2.61
 
Diluted EPS                                   $   2.75  $   2.71  $   2.61
 
Weighted average common shares outstanding
 for basic EPS                                  47,973    48,515    48,265
 
Effect of dilutive shares:
 
Weighted average dilutive potential common
 shares                                            176        47         -
--------------------------------------------------------------------------
 
Weighted average common shares outstanding
 for diluted EPS                                48,149    48,562    48,265
==========================================================================
</TABLE>

13.  RCN Joint Venture

BETG is a participant in a telecommunications venture with RCN Telecom Services,
Inc. (RCN).  As part of the joint venture agreement, BETG has the option to
exchange certain portions of its joint venture interest for shares of RCN
Corporation common stock.  During 1998, BETG exercised its option to convert a
portion of its interest with a cost of $11 million.  BETG expects to receive
approximately 1.1 million RCN Corporation common shares during the first quarter
of 1999.

                                       36
<PAGE>
 
Note B. Electric Utility Industry Restructuring

1.  Accounting Implications

Under the traditional revenue requirements model, electric rates have been based
on the cost of providing electric service.  Under this model, Boston Edison has
been subject to certain accounting standards that are not applicable to other
businesses and industries in general.  The application of SFAS 71 requires
companies to defer the recognition of certain costs when incurred if future rate
recovery of these costs is expected.  As a result of the Massachusetts electric
industry restructuring legislation enacted in November 1997 and the DTE order
regarding Boston Edison's related settlement agreement, as of December 31, 1997,
the provisions of SFAS 71 are no longer being applied to the generation
business.  Under the settlement agreement, approximately 75% of the net assets
of Pilgrim Station are recoverable through the non-bypassable transition charge
of the utility's distribution business.  The distribution business continues to
be subject to rate-regulation.  The remaining 25% is collected under Pilgrim's
wholesale power contracts.  The 1998 consolidated balance sheet reflects a
reclassification of the Pilgrim net assets recoverable through the transition
charge from utility plant to regulatory asset.  This Pilgrim regulatory asset,
included in the generation-related regulatory asset on the consolidated balance
sheet continues to be grouped with utility plant for financial statement
presentation.

Completion of the sale of Boston Edison's fossil generating assets took place in
May 1998.  Boston Edison received proceeds from the sale of $655 million,
including $121 million for a six-month transitional power purchase contract.
The amount received above net book value on the sale of these assets is being
returned to Boston Edison's customers over the settlement period.  That amount
is partially offset by certain costs recoverable through the transition charge
due to the support of standard offer service provided by Boston Edison's fossil
generating assets prior to the divestiture.  The net deferred gain is included
as a reduction to the generation-related regulatory asset on the 1998
consolidated balance sheet.  In addition, Boston Edison received $19 million
from Sithe for inventory and other closing adjustments.

The implementation of the Boston Edison settlement agreement had certain
accounting implications.  The highlights of these include:

Generation-related plant and other regulatory assets

Plant and other regulatory assets related to the generation business, except for
those related to Pilgrim's wholesale contracts, are recovered through the
transition charge.  This recovery, which includes a return, will occur over a
twelve-year period that began on March 1, 1998 (the retail access date).

Depreciation

The composite depreciation rate for distribution utility plant increased from
2.38% to 2.98% as of the retail access date.

Fuel and purchased power charge

The fuel and purchased power charge ceased as of the retail access date.  The
net remaining overcollection of fuel and purchased power costs will be reflected
in future customer billings.  These over recovered costs are included as an
offset to the settlement recovery mechanisms on the 1998 consolidated balance
sheet.

                                       37
<PAGE>
 
Standard offer charge

Customers have the option of continuing to buy power from the electric delivery
business at standard offer prices as of the retail access date.  The standard
offer charge began at 2.8 cents/kWh at the retail access date, increased to 3.2
cents/kWh on June 1, 1998, to 3.69 cents/kWh on January 1, 1999 and is scheduled
to increase to 5.1 cents/kWh by 2004.  The cost of providing standard offer
service, which includes fuel and purchased power costs, is recovered from
standard offer customers on a fully reconciling basis.

Distribution and transmission charges

Distribution rates are subject to a minimum and maximum return on average common
equity (ROE) through December 31, 2000.  The ROE is subject to a floor of 6% and
a ceiling of 11.75%.  If the ROE is below 6%, Boston Edison is authorized to add
a surcharge to distribution rates in order to achieve the 6% floor.  If the ROE
is above 11%, it is required to adjust distribution rates by an amount necessary
to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above
12.5% by 100%.  No adjustment is made if the ROE is between 6% and 11%.  In
addition, distribution rates will be adjusted for any changes in tax laws or
accounting principles that result in a change in costs of more than $1 million.
The cost of providing transmission service to distribution customers is
recovered on a fully reconciling basis.

Nuclear generation

Under the settlement agreement, the annual performance adjustment charge ceased
and the cost recovery mechanism for Pilgrim Station changed effective March 1,
1998.  Approximately 25% of the operations and capital costs, including a return
on investment, continues to be collected under Pilgrim's wholesale contracts.
Through Pilgrim's sale closing date, 25% of any profit or loss from the sale of
Pilgrim's output will be shared with distribution customers through the
transition charge.  In addition, Boston Edison will obtain transition payments
up to a maximum of $23 million per year depending on the level of costs incurred
for such items as property taxes, insurance, regulatory fees and security
requirements.

2.  Generating Assets Divestiture

The Boston Edison restructuring settlement agreement included a provision for
the divestiture of its fossil generating assets no later than six months after
the retail access date.  In December 1997, Boston Edison entered into a purchase
and sale agreement with Sithe Energies, a privately-held company headquartered
in New York, to purchase these non-nuclear generating assets.  The sale of these
assets was finalized on May 15, 1998.

In April 1998, Boston Edison began soliciting expressions of interest for the
sale of its nuclear generating unit, Pilgrim Station as part of the previously
announced strategy to exit the generation business.  On November 19, 1998,
Boston Edison announced the selection of Entergy, a subsidiary of New Orleans-
based Entergy Corporation, as the winning bidder for the purchase of Pilgrim.
Entergy is expected to purchase Pilgrim in a deal valued at an estimated $121
million.  In addition, under the agreement Boston Edison will fully fund and
transfer its decommissioning trust fund to Entergy and Entergy will then assume
full liability and responsibility for decommissioning the Pilgrim site.  A
purchase and sale agreement has been signed and all required approvals are
anticipated in the second quarter of 1999.  The purchase price includes
reimbursement for certain costs to be expended by Boston Edison in 1999.

                                       38
<PAGE>

Therefore, the actual proceeds could be impacted by the ultimate timing of the
transaction.
 
As part of a benefits package offered to employees affected by the nuclear
divestiture, eligible non-represented nuclear and designated nuclear support
employees were offered unreduced retirement and transition benefits under a
voluntary early retirement program (VERP).  Sixteen employees elected to
participate in the VERP.  A retention benefit program was offered to all non-
represented nuclear and designated nuclear support employees that did not elect
or were ineligible to retire under the VERP who continue to work through the
sale closing date.  It is anticipated that approximately 300 non-represented
nuclear and designated nuclear employees will receive one-time retention
payments under this program.  Costs associated with the VERP and retention
program are recoverable under Boston Edison's settlement agreement.

3.  Nuclear Asset Impairment

As part of the settlement agreement, the net investment in Pilgrim Station as of
December 31, 1995 (adjusted for depreciation through 1997) is recovered through
the distribution transition charge.  Due to the market pressures in the
industry, the ultimate recovery of investments made in Pilgrim since 1995 is not
certain.  Therefore, in 1997 the investment in Pilgrim was reduced by the $13
million invested in the plant since January 1, 1996 as an impairment loss under
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.  An
after tax charge of approximately $8 million due to this reduction was recorded
to non-operating expense on the consolidated statement of income in the fourth
quarter of 1997.

Note C. Income Taxes

Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109).  SFAS 109
requires the recognition of deferred tax assets and liabilities for the future
tax effects of temporary differences between the carrying amounts and the tax
basis of assets and liabilities.  In accordance with SFAS 109 net regulatory
assets of $52.2 million and $51.1 million and corresponding net increases in
accumulated deferred income taxes were recorded as of December 31, 1998 and
1997, respectively.  The regulatory assets represent the additional future
revenues to be collected from customers for deferred income taxes.

Accumulated deferred income taxes consisted of the following:
<TABLE>
<CAPTION>
 
                                                December 31,
(in thousands)                                 1998      1997
-------------------------------------------  --------  --------
<S>                                          <C>       <C>
Deferred tax liabilities:
  Plant-related                              $412,358  $535,460
  Other                                        85,497    79,930
-------------------------------------------  --------  --------
                                              497,855   615,390
                                             --------  --------
Deferred tax assets:
  Plant-related                                13,174    11,926
  Investment tax credits                       29,622    33,125
  Other                                       106,502    84,601
-------------------------------------------  --------  --------
                                              149,298   129,652
-------------------------------------------  --------  --------
    Net accumulated deferred income taxes    $348,557  $485,738
===========================================  ========  ========
</TABLE>
No valuation allowances for deferred tax assets are deemed necessary.

                                       39
<PAGE>
 
Previously deferred investment tax credits are amortized over the estimated
remaining lives of the property giving rise to the credits.

Components of income tax expense were as follows:
<TABLE>
<CAPTION>
 
years ended December 31,
(in thousands)                             1998       1997       1996
--------------------------------------  ----------  ---------  --------
<S>                                     <C>         <C>        <C>
Current income tax expense              $ 239,717   $115,373   $92,370
Deferred income tax expense              (137,992)   (14,104)       14
Investment tax credit amortization         (3,927)    (7,560)   (4,071)
--------------------------------------  ---------   --------   -------
  Income taxes charged to operations       97,798     93,709    88,313
--------------------------------------  ---------   --------   -------
Taxes on other income                     (24,116)   (11,254)     (331)
--------------------------------------  ---------   --------   -------
     Total income tax expense           $  73,682   $ 82,455   $87,982
======================================  =========   ========   =======
</TABLE>

The effective income tax rates reflected in the consolidated financial
statements and the reasons for their differences from the statutory federal
income tax rate were as follows:
<TABLE>
<CAPTION>
 
                                                       1998  1997   1996
--------------------------------------------          ----   ----   ----
<S>                                                <C>       <C>    <C>
Statutory tax rate                                    35.0%  35.0%  35.0%
State income tax, net of federal income
 tax benefit                                           5.2    4.5    4.3
Investment tax credit amortization                    (6.9)  (3.3)  (1.8)
Other                                                  1.0    0.1    0.7
--------------------------------------------          ----   ----   ----
  Effective tax rate                                  34.3%  36.3%  38.2%
============================================          ====   ====   ====
</TABLE>

The 1998 effective tax rate declined by 5.1% as a result of the recognition in
net income of the remaining unamortized investment tax credits related to Boston
Edison's fossil generating assets at the time of their sale.  This shareholder
benefit is included in other expense, net on the 1998 consolidated statement of
income.

The 1997 effective tax rate declined by 0.8% as a result of the favorable
outcome of an Internal Revenue Service appeal related to investment tax credits.

Note D. Nuclear Decommissioning and Nuclear Waste Disposal

1.  Nuclear Decommissioning

As a nuclear generating facility, Pilgrim Station will be required to be
decommissioned upon the expiration of its operating license.  Decommissioning
means to remove nuclear facilities from service safely and reduce residual
radioactivity to a level that permits termination of the Nuclear Regulatory
Commission (NRC) license and release of the property for unrestricted use.
Estimated decommissioning costs are recorded to depreciation expense on the
consolidated statements of income over Pilgrim's expected service life.  These
costs are recovered through charges to retail and wholesale contract customers.
In November 1998, Boston Edison filed an update of Pilgrim Station's
decommissioning cost study with the DTE.  The updated study includes an estimate
of decommissioning and fuel storage costs of approximately $600 million in 1997
dollars.

2.  Spent Nuclear Fuel

The spent fuel storage facility at Pilgrim Station is expected to provide
storage capacity through approximately 2003.  Boston Edison has a license
amendment from the NRC to modify the facility to provide sufficient room for
spent nuclear fuel generated through the end of Pilgrim's operating license in
2012; however, any further modifications are subject to review by the DTE.

                                       40
<PAGE>
 
Delays in identifying a permanent storage site have continually postponed plans
for the United States Department of Energy's (DOE) long-term storage and
disposal for spent nuclear fuel.  The DOE's current estimate for an available
site is no earlier than 2010.  In November 1997, the U.S. Court of Appeals for
the District of Columbia Circuit ruled that the lack of an interim storage
facility does not excuse the DOE from meeting its contract obligation to begin
accepting spent nuclear fuel no later than January 31, 1998.  This decision was
in response to petitions filed by Boston Edison and other interested parties
seeking declaratory rulings concerning enforcement and remedies for the DOE's
failure to accept spent fuel in a timely manner.  The court directed the
plaintiffs to pursue relief under terms of their contracts with the DOE.  Based
on this ruling, the DOE may have to pay contract damages for not taking the
spent nuclear fuel as scheduled.  Under the Nuclear Waste Policy Act of 1982, it
is the ultimate responsibility of the DOE to permanently dispose of spent
nuclear fuel.  Boston Edison currently pays a fee of $1.00 per net megawatthour
sold from Pilgrim Station generation under a nuclear fuel disposal contract with
the DOE.

The DOE denied Boston Edison's petition to suspend payments to the Nuclear Waste
Fund based on its interpretation of the U.S. Court of Appeal's decision made in
November 1997.  The DOE has, however, made an offer to consider amendments to
existing contracts to address the hardships the anticipated delay in accepting
spent fuel may cause individual contract holders.

3.  Nuclear Divestiture

As discussed in Note B to these Consolidated Financial Statements, in November
1998 Boston Edison announced the selection of Entergy as the winning bidder for
the purchase of Pilgrim.  A purchase and sale agreement has been signed and all
required approvals are anticipated in the second quarter of 1999.  Under the
agreement Boston Edison will fully fund and transfer its decommissioning trust
fund to Entergy and Entergy will then assume full liability and responsibility
for decommissioning and waste disposal at Pilgrim Station.

Note E. Pensions and Other Postretirement Benefits

The following information is presented in accordance with Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about Pensions and Other
Postretirement Benefits, effective for fiscal years beginning after December 15,
1997.

1.  Pensions

Boston Edison has a defined benefit funded retirement plan with certain
contributory features that covers substantially all employees and an unfunded
supplemental retirement plan for certain management employees.

                                       41
<PAGE>
 
The changes in the benefit obligation and plan assets were as follows:
<TABLE>
<CAPTION>
 
                                                              December 31,
(in thousands)                                             1998         1997
------------------------------------------------------  ----------  -------------
<S>                                                     <C>         <C>
Change in benefit obligation:
  Benefit obligation at the beginning of the year        $457,436       $409,760
  Service cost                                             13,645         12,625
  Interest cost                                            31,981         31,537
  Plan participants' contributions                            214            248
  Plan amendments                                               -          1,081
  Actuarial loss                                           67,564         32,762
  Curtailment gain                                        (15,644)        (6,916)
  Special termination benefits                                665          3,530
  Settlement payments                                     (16,246)             -
  Benefits paid                                           (41,627)       (27,191)
------------------------------------------------------   --------       --------
    Benefit obligation at the end of the year            $497,988       $457,436
======================================================   ========       ========
 
Change in plan assets:
  Fair value of plan assets at the beginning of
   the year                                              $401,182       $331,299
  Actual return on plan assets                             44,589         60,602
  Employer contribution                                    86,440         36,224
  Plan participants' contributions                            214            248
  Settlement payments                                     (16,246)             -
  Benefits paid                                           (41,627)       (27,191)
------------------------------------------------------   --------       --------
    Fair value of plan assets at the end of the year     $474,552       $401,182
======================================================   ========       ========
 
The plans' funded status were as follows:
 
                                                                    December 31,
(in thousands)                                               1998           1997
------------------------------------------------------   --------       --------
Funded status                                            $(23,436)      $(56,254)
Unrecognized actuarial net loss                            96,310         50,646
Unrecognized transition obligation                          3,856          5,704
Unrecognized prior service cost                            15,557         19,121
------------------------------------------------------   --------       --------
    Net amount recognized                                $ 92,287       $ 19,217
======================================================   ========       ========
 
Amount recognized in the consolidated
 balance sheets consist of:
  Prepaid retirement cost                                $ 94,049       $ 20,584
  Accrued supplemental retirement liability                (9,856)        (9,763)
  Intangible asset                                          8,094          8,396
------------------------------------------------------   --------       --------
    Net amount recognized                                $ 92,287       $ 19,217
======================================================   ========       ========
</TABLE>

The projected benefit obligation, accumulated benefit obligation and fair value
of plan assets for the supplemental retirement plan with accumulated benefit
obligations in excess of plan assets were $11,387,000, $9,856,000 and $0,
respectively, as of December 31, 1998, and $11,076,000, $9,763,000 and $0,
respectively, as of December 31, 1997.

Weighted average assumptions were as follows:
<TABLE>
<CAPTION>
 
                                                1998    1997    1996
                                               ------  ------  ------
<S>                                            <C>     <C>     <C>
Discount rate at the end of the year            6.50%   7.25%   7.75%
Expected return on plan assets for the year    10.00%  10.00%  10.00%
Rate of compensation increase at the end of
 the year                                       4.00%   4.25%   3.90%
</TABLE>

                                       42
<PAGE>
 
Components of net periodic benefit cost were as follows:

<TABLE>
<CAPTION>
years ended December 31,
(in thousands)                               1998       1997       1996
-----------------------------------------  ---------  ---------  ---------
<S>                                        <C>        <C>        <C>
  Service cost                             $ 13,645   $ 12,625   $ 13,452
  Interest cost                              31,981     31,537     32,325
  Expected return on plan assets            (39,140)   (31,250)   (29,826)
  Amortization of prior service cost          1,847      1,827      1,831
  Amortization of transition obligation         860        934        934
  Recognized actuarial loss                     808      1,799      3,790
-----------------------------------------  --------   --------   --------
    Net periodic benefit cost              $ 10,001   $ 17,472   $ 22,506
=========================================  ========   ========   ========
</TABLE>

As a result of the fossil and nuclear divestitures discussed in Note B to these
Consolidated Financial Statements, amounts recognized for curtailment,
settlement and special termination benefit costs were $2,705,000, $0 and
$665,000, respectively for 1998 and $1,300,000, $3,162,000 and $3,530,000,
respectively for 1997.  These amounts are recoverable under Boston Edison's
settlement agreement.

Boston Edison experienced a high number of employee retirements from 1994 to
1996.  A large number of these retirements were as a direct result of the 1995
corporate restructuring.  In 1997, a review of the accounting for the pension
expense related to the retirements revealed that an adjustment to the pension
costs related to these employees was necessary.  Therefore, pension regulatory
asset was increased by $8.6 million in 1997 for the adjustment related to the
period covered by the 1992 Boston Edison settlement agreement.  Through 1995, in
accordance with the 1992 settlement agreement, the difference between the net
pension cost of the retirement plan and its annual funding amount was deferred.
The remaining adjustment did not have a material impact on the consolidated
results of operations or financial position.

Boston Edison also provides defined contribution 401(k) plans for substantially
all employees.  It matches a portion of employees' voluntary contributions to
the plans.  Matching contributions of $8 million were made in 1998, 1997 and
1996, respectively.

2.  Other Postretirement Benefits

In addition to pension benefits, Boston Edison also provides health care and
other benefits to retired employees who meet certain age and years of service
liability requirements.  These benefits are not available to management
employees hired on or after January 1, 1995.

                                       43
<PAGE>
 
The changes in the benefit obligation and plan assets were as follows:
<TABLE>
<CAPTION>
 
                                                                                                             December 31,
(in thousands)                                                                                               1998         1997
-------------------------------------------------------------------------------------------------         ----------  -------------
<S>                                                                                                        <C>        <C> 
Change in benefit obligation:
  Benefit obligation at the beginning of the year                                                         $ 237,616      $ 230,905
  Service cost                                                                                                3,892          3,543
  Interest cost                                                                                              16,895         17,006
  Plan participants' contributions                                                                            1,178            395
  Actuarial loss                                                                                             27,845          4,093
  Curtailment gain                                                                                          (14,665)        (5,531)
  Special termination benefits                                                                                   75            450
  Benefits paid                                                                                             (14,080)       (13,245)
-------------------------------------------------------------------------------------------------         ---------   ------------
    Benefit obligation at the end of the year                                                             $ 258,756      $ 237,616
=================================================================================================         =========   ============
 
Change in plan assets:
  Fair value of plan assets at the beginning of
   the year                                                                                               $ 103,989      $  72,702
  Actual return on plan assets                                                                               14,344         18,852
  Employer contribution                                                                                       8,387         25,285
  Plan participants' contributions                                                                            1,178            395
  Benefits paid                                                                                             (14,080)       (13,245)
-------------------------------------------------------------------------------------------------         ---------   ------------
    Fair value of plan assets at the end of the year                                                      $ 113,818      $ 103,989
=================================================================================================         =========   ============
</TABLE> 
The plan's funded status and amount recognized in the consolidated balance
sheets were as follows:
<TABLE> 
<CAPTION> 
                                                                                                                      December 31,
(in thousands)                                                                                                 1998           1997
-------------------------------------------------------------------------------------------------         ---------   ------------
<S>                                                                                                       <C>         <C> 
Funded status                                                                                             $(144,938)     $(133,627)
Unrecognized actuarial net loss                                                                              24,922         12,916
Unrecognized transition obligation                                                                           88,814        127,107
Unrecognized prior service cost                                                                              (9,827)       (14,128)
-------------------------------------------------------------------------------------------------         ---------   ------------
    Net amount recognized                                                                                 $ (41,029)     $  (7,732)
=================================================================================================         =========   ============
</TABLE> 
Weighted average assumptions were as follows:
<TABLE> 
<CAPTION>  
                                                                                                   1998        1997           1996
                                                                                                   ----   ---------   ------------
<S>                                                                                                <C>    <C>         <C> 
Discount rate at the end of the year                                                               6.50%       7.25%          7.75%
Expected return on plan assets for the year                                                        9.00%       9.00%          9.00%
</TABLE>

For measurement purposes, a 5% annual rate of increase on the per capita cost of
covered health care benefits was assumed.  A 13% annual rate of increase on the
per capita cost of covered prescription drug benefits was assumed, decreasing
gradually to 5% in the year 2012 and remaining level thereafter.  A 4% annual
rate of increase on the per capita cost of covered dental benefits was assumed.

                                       44
<PAGE>
 
A 1% change in the assumed health care cost trend rate would have the following
effects:
<TABLE>
<CAPTION>
One-Percentage-Point
                                                                       Increase   Decrease
                                                                       ---------  ---------
<S>                                                                    <C>        <C>      
Effect on total of service and interest cost
 components for 1998                                                    $ 3,319   $ (2,605)
Effect on December 31, 1998 postretirement benefit
 obligation                                                             $34,088   $(27,270)
</TABLE> 
 
Components of net periodic benefit cost were as follows:
<TABLE> 
<CAPTION> 
                                                                years ended December 31,
(in thousands)                                                  1998       1997       1996
----------------------------------------------------------   -------    -------   --------
<S>                                                          <C>         <C>      <C> 
Service cost                                                 $ 3,892    $ 3,543   $  4,616
Interest cost                                                 16,895     17,006     16,815
Expected return on plan assets                                (8,563)    (6,421)    (4,738)
Amortization of prior service cost                              (942)    (1,017)    (1,614)
Amortization of transition obligation                          8,474      9,151      9,151
Recognized actuarial loss                                        662      1,003      1,977
----------------------------------------------------------   -------    -------   --------
  Net periodic benefit cost                                  $20,418    $23,265   $ 26,207
</TABLE>

As a result of the fossil and nuclear divestitures discussed in Note B to these
Consolidated Financial Statements, amounts recognized for curtailment and
special termination benefit costs were $21,187,000 and $79,000, respectively for
1998 and $7,895,000 and $456,000, respectively for 1997.  These amounts are
recoverable under Boston Edison's settlement agreement.

Note F. Stock-Based Compensation

In 1997, Boston Edison initiated a Stock Incentive Plan (the Plan) which was
adopted by the board of directors and approved by common stockholders.  The Plan
permits a variety of stock and stock-based awards, including stock options and
deferred (nonvested) stock to be granted to certain key employees.  The Plan
limits the terms of awards to ten years.  Subject to adjustment for stock-splits
and similar events, the aggregate number of shares of common stock that may be
delivered under the Plan is 2,000,000, including shares issued in lieu of or
upon reinvestment of dividends arising from awards.  During 1998, 19,150 shares
of deferred stock and 419,200 ten-year non-qualified stock options were granted
under the plan.  During 1997, 73,820 shares of deferred stock and 298,400 ten-
year non-qualified stock options were granted.  The weighted average grant date
fair value of the deferred stock issued during 1998 and 1997 is $39.75 and
$27.26, respectively.  The options were granted at the full market price of the
stock on the date of the grant.  Both awards vest ratably over a three-year
period.

                                       45
<PAGE>
 
Compensation cost for stock-based awards is recognized under the provisions of
Accounting Principals Board Opinion 25, which requires compensation cost to be
measured by the quoted stock market price at the measurement date less the
amount, if any, an employee is required to pay.  The required fair value method
disclosures are as follows:
<TABLE>
<CAPTION>
(in thousands, except per share amounts)                           1998              1997
----------------------------------------------------------      --------           --------
<S>                                                            <C>                <C> 
Net income                                                
   Actual                                                       $141,046           $144,642
   Pro forma                                                    $140,661           $144,572
Basic earnings per common share                           
   Actual                                                       $   2.76           $   2.71
   Pro forma                                                    $   2.75           $   2.71
Diluted earnings per common share                         
   Actual                                                       $   2.75           $   2.71
   Pro forma                                                    $   2.74           $   2.71
</TABLE> 
Stock option activity of the Plan was as follows:         
<TABLE> 
<CAPTION> 
                                                                  1998                1997
----------------------------------------------------------      --------           --------
<S>                                                            <C>                <C> 
Options outstanding at January 1                                 273,000                  0
   Options granted                                               419,200            298,400
   Options exercised                                              (3,800)                 0
   Options forfeited                                             (21,800)           (25,400)
----------------------------------------------------------      --------           --------
Options outstanding at December 31                               666,600            273,000
==========================================================      ========           ========
</TABLE> 
Summarized information regarding stock options outstanding at December 31, 1998:
<TABLE> 
<CAPTION> 
       Range of        Weighted Average Remaining   Weighted Average
Exercise Prices          Contractual Life (Years)     Exercise Price
---------------        --------------------------   ----------------
<S>                    <C>                          <C> 
 $25.75-$26.00                       8.44           $  25.85
 $39.75-$40.50                       9.30           $  39.75
</TABLE>

There were 87,200 stock options exercisable at December 31, 1998 with a weighted
average exercise price of $25.85.

The stock options granted during 1998 have a weighted average grant date fair
value of $4.61.  The fair value was estimated using the Black-Scholes option
pricing model with the following weighted average assumptions:
<TABLE> 
<S>                                                        <C> 
        Expected life (years)                               4.0
        Risk-free interest rate                            5.66%
        Volatility                                           16%
        Dividends                                          4.88%
</TABLE> 
Compensation cost recognized in the consolidated statements of income for stock-
based compensation awards in 1998 and 1997 was $850,000 and $275,000,
respectively.

                                       46
<PAGE>
 
Note G. Capital Stock
<TABLE> 
<CAPTION> 
                                                                               December 31,
(dollars in thousands, except per share amounts)                            1998            1997
-------------------------------------------------------------------   ----------      ----------
<S>                                                                   <C>             <C> 
Common equity:                                                                     
Common stock, par value $1 per share,                                              
 100,000,000 shares authorized; 47,184,073                                         
 and 48,514,973 shares issued and                                                  
 outstanding:                                                         $   47,184      $   48,515
Premium on common stock                                                  644,205         696,137
Retained earnings                                                        360,509         328,802
-------------------------------------------------------------------   ----------      ----------
    Total common equity                                               $1,051,898      $1,073,454
===================================================================   ==========      ==========
</TABLE> 
Dividends declared per share of common stock were $1.895 in 1998
 and $1.88 in 1997 and 1996.
 
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
 authorized; issued and outstanding:
  Nonmandatory redeemable series:
<TABLE> 
<CAPTION> 
                                            Current Shares                Redemption                         
   Series                                      Outstanding               Price/Share                         
------------------------------------------------------------------------------------------------------------- 
<S>                                          <C>                         <C>            <C>           <C> 
   4.25%                                          180,000                  $103.625     $ 18,000     $ 18,000
   4.78%                                          250,000                  $102.800       25,000       25,000
   7.75%                                                -                         -            0       40,000
-------------------------------------------------------------------------------------------------------------
    Total nonmandatory redeemable series                                                $ 43,000     $ 83,000
============================================================================================================= 
<CAPTION> 
  Mandatory redeemable series: 
                                            Current Shares                Redemption                         
   Series                                      Outstanding               Price/Share                         
------------------------------------------------------------------------------------------------------------- 
<S>                                          <C>                         <C>         <C>           <C> 
   7.27%                                                -                      -     $      0        $ 36,000
   8.00%                                          500,000                      -       50,000          50,000
------------------------------------------------------------------------------------------------------------- 
                                                                                       50,000          86,000
  Less:  redemption and issuance costs                                                   (960)         (5,907)
     due within one year                                                                    0          (2,000)
------------------------------------------------------------------------------------------------------------- 
    Total mandatory redeemable series                                                $ 49,040        $ 78,093
=============================================================================================================
</TABLE> 
1.  Common Stock
 
Common stock issuances and repurchases in 1996 through 1998 were
 as follows:
<TABLE> 
<CAPTION> 
 
                                                                          Number       Total    Premium on
(in thousands)                                                         of Shares   Par Value  Common Stock
---------------------------------------------------------------------------------------------------------
<S>                                                                    <C>         <C>        <C> 
Balance at December 31, 1995                                              48,003    $ 48,003     $683,686
    Dividend reinvestment plan                                               507         507       12,037
---------------------------------------------------------------------------------------------------------
Balance at December 31, 1996                                              48,510      48,510      695,723
    Dividend reinvestment plan                                                 5           5          414
---------------------------------------------------------------------------------------------------------
Balance at December 31, 1997                                              48,515      48,515      696,137
    Common share repurchase program                                       (1,331)     (1,331)     (49,823)
    Stock incentive plan                                                       -           -       (2,109)
---------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                                              47,184    $ 47,184     $644,205
=========================================================================================================
</TABLE>
2.  Cumulative Mandatory Redeemable Preferred Stock

Boston Edison redeemed the remaining 360,000 shares of 7.27% sinking fund series
cumulative preferred stock during 1998.  The stock was subject to a mandatory
sinking fund requirement of 20,000 shares each May at par plus accrued
dividends.  Boston Edison also had the noncumulative option each May 

                                       47
<PAGE>
 
to redeem additional shares, not to exceed 20,000, through the sinking fund at
$100 per share plus accrued dividends. It redeemed, at par value, 40,000 shares
in 1998, 1997 and 1996. In addition, 320,000 shares were redeemed in 1998 at
$101.94 per share.

Boston Edison is not able to redeem any part of the 500,000 shares of 8% series
cumulative preferred stock prior to December 2001.  The entire series is subject
to mandatory redemption in December 2001 at $100 per share plus accrued
dividends.
<TABLE>
<CAPTION>
 
Note H. Indebtedness
                                                             December 31,
(in thousands)                                         1998         1997
------------------------------------------------   --------   ----------
<S>                                                 <C>       <C>
 
Long-term debt:
 
Debentures:
   5.950%, due March 1998                          $      0   $  100,000
   6.800%, due February 2000                         65,000       65,000
   6.050%, due August 2000                          100,000      100,000
   6.800%, due March 2003                           150,000      150,000
   7.800%, due May 2010                             125,000      125,000
   9.875%, due June 2020                            100,000      100,000
   9.375%, due August 2021                          115,000      115,000
   8.250%, due September 2022                        60,000       60,000
   7.800%, due March 2023                           200,000      200,000
------------------------------------------------   --------   ----------
  Total debentures                                  915,000    1,015,000
  Less:  due within one year                              0     (100,000)
------------------------------------------------   --------   ----------
  Net long-term debentures                          915,000      915,000
------------------------------------------------   --------   ----------
 
Sewage facility revenue bonds                        30,900       32,500
 Less: due within one year                             (667)        (667)
 Less: funds held by trustee                         (4,670)      (4,757)
------------------------------------------------   --------   ----------
  Net long-term sewage facility revenue bonds        25,563       27,076
------------------------------------------------   --------   ----------
 
Massachusetts Industrial Finance Agency bonds:
   5.750%, due February 2014                         15,000       15,000
 
6.662% bank loan, due 1999                                0      100,000
------------------------------------------------   --------   ----------
    Total long-term debt                           $955,563   $1,057,076
================================================   ========   ==========
 
Short-term debt:
 
Notes payable:
   Bank loans                                      $ 78,000   $   94,013
   Commercial paper                                       0       43,000
------------------------------------------------   --------   ----------
    Total notes payable                            $ 78,000   $  137,013
================================================   ========   ==========
</TABLE>

1.  Long-term Debt

The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption
price of 104.483%, the 9 3/8% series due 2021 are first redeemable in August
2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September
2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March
2003 at 103.730%.  No other series are redeemable prior to maturity.  There is
no sinking fund requirement for any series of debentures.

Sewage facility revenue bonds were issued by HEEC.  The bonds are tax-exempt,
subject to annual mandatory sinking fund redemption requirements and mature

                                       48
<PAGE>
 
through 2015.  Scheduled redemptions of $1.6 million were made in 1998, 1997 and
1996.  The weighted average interest rate of the bonds is 7.3%.  A portion of
the proceeds from the bonds is in reserve with the trustee.  If HEEC should have
insufficient funds to pay for extraordinary expenses, Boston Edison would be
required to make additional capital contributions or loans to the subsidiary up
to a maximum of $1 million.

The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in
February 2004 at a redemption price of 102%.  The redemption price decreases to
101% in February 2005 and to par in February 2006.

The aggregate principal amounts of Boston Edison's long-term debt (including
HEEC sinking fund requirements) due through 2003 are $1.6 million in 1999,
$166.6 million in 2000, $1.6 million in 2001 and 2002 and $151.6 million in
2003.

2.  Short-term Debt

In 1998, BEC established a $225 million revolving credit agreement with a group
of banks effective through July 2001.  Under the terms of this agreement, it is
required to maintain a consolidated common equity ratio of not less than 35% at
all times and to maintain a ratio of consolidated earnings before interest and
taxes to consolidated total interest expense of not less than 2 to 1 for each
period of four consecutive fiscal quarters.  Commitment fees must be paid on the
total agreement amount.  Approximately $78 million was outstanding under this
agreement as of December 31, 1998.

Boston Edison currently has regulatory authority to issue up to $350 million of
short-term debt.  Boston Edison has a $200 million revolving credit agreement
with a group of banks.  This agreement is intended to provide a standby source
of short-term borrowings.  Under the terms of this agreement Boston Edison is
required to maintain a common equity ratio of not less than 30% at all times.
Commitment fees must be paid on the unused portion of the total agreement
amount.  It also has arrangements with several banks to provide additional
short-term credit on an uncommitted and as available basis.

Information regarding consolidated BEC short-term borrowings is as follows:
<TABLE>
<CAPTION>
 
                     (dollars in thousands)    1998       1997       1996
-------------------------------------------  ---------  ---------  ---------
<S>                                          <C>        <C>        <C>
Maximum short-term borrowings                $219,000   $316,100   $272,500
Weighted average amount outstanding          $ 76,249   $212,663   $208,914
Weighted average interest rates excluding
 commitment fees                                 5.85%      5.85%      5.65%
-------------------------------------------  --------   --------   --------
</TABLE>
Note I. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of
each class of securities for which it is practicable to estimate the value:

Nuclear decommissioning trust:

The cost of $173 million approximates fair value based on quoted market prices
of securities held.

Cash and cash equivalents:

The carrying amount of $99 million approximates fair value due to the short-term
nature of these securities.

                                       49
<PAGE>
 
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds
and unsecured debt:

The fair values of these securities are based upon the quoted market prices of
similar issues.  Carrying amounts and fair values as of December 31, 1998, are
as follows:
<TABLE>
<CAPTION>
 
Carrying                                             Fair
                                   (in thousands)   Amount      Value
-------------------------------------------------  ---------  ---------
<S>                                                <C>        <C>
Mandatory redeemable cumulative preferred stock     $ 49,040   $ 54,190
Sewage facility revenue bonds                       $ 30,900   $ 33,914
Unsecured debt                                      $930,000   $994,294
-------------------------------------------------   --------   --------
</TABLE>
Note J. Segment and Related Information

Statement of Financial Accounting Standards No. 131, Disclosures about Segments
of an Enterprise and Related Information, requires the disclosure of certain
financial and descriptive information by operating segments.  For the purpose of
providing segment information, BEC's principal operating segment, or its
traditional core business, is the electric utility that provides electric energy
service, primarily in the city of Boston and 39 surrounding cities and towns.
The utility also supplies electricity at wholesale for resale to other utilities
and municipalities.  The unregulated operating segment engages in certain
nonutility business activities.  Such activities include telecommunications,
construction management and district energy primarily in the Boston area.
Financial data for the operating segments are as follows (dollars in thousands):

                                       50
<PAGE>
 
<TABLE>
<CAPTION>
                                         Electric     Unregulated
                                          Utility      Nonutility     Consolidated
                                       Operations      Operations            Total
                                       ----------  --------------  ----------------
<S>                                    <C>         <C>             <C>
1998
----
Operating revenues                     $1,622,435    $     80        $1,622,515
Interest charges                       $   88,516    $  1,567        $   90,083
Depreciation and amortization          $  188,738    $  2,963        $  191,701
Operating income tax expense
 (benefit)                             $  101,492    $ (3,694)       $   97,798
Segment net income (loss)              $  170,374    $(29,328)(a)    $  141,046
Equity income (loss) in investments
 accounted for by the equity method    $    1,725    $(11,967)       $  (10,242)(b)
Equity investments                     $   20,769    $ 64,001        $   84,770
Segment assets                         $3,082,921    $130,978        $3,213,899
Expenditures for property              $  108,344    $ 11,858        $  120,202
 
1997
----
Operating revenues                     $1,776,233    $  2,298        $1,778,531
Interest charges                       $  105,710    $    200        $  105,910
Depreciation and amortization          $  188,687    $    802        $  189,489
Operating income tax expense
 (benefit)                             $   95,021    $ (1,312)       $   93,709
Segment net income (loss)              $  153,738    $ (9,096)(a)    $  144,642
Equity income (loss) in investments
 accounted for by the equity method    $    1,534    $ (5,571)       $   (4,037)(b)
Equity investments                     $   23,326    $ 12,129        $   35,455
Segment assets                         $3,584,384    $ 37,963        $3,622,347
Expenditures for property              $  106,659    $  7,451        $  114,110
 
1996
----
Operating revenues                     $1,666,303    $  2,553        $1,668,856
Interest charges                       $  107,082    $     93        $  107,175
Depreciation and amortization          $  185,494    $    623        $  186,117
Operating income tax expense
(benefit)                              $   88,703    $   (390)       $   88,313
Segment net income (loss)              $  144,476    $ (2,930)(a)    $  141,546
Equity income (loss) in investments
accounted for by the equity method     $    1,880    $      -        $    1,880 (b)
Equity investments                     $   23,054    $  5,698        $   28,752
Segment assets                         $3,719,248    $ 10,043        $3,729,291
Expenditures for property              $  145,131    $    216        $  145,347
</TABLE> 
(a)  During the latter half of 1998 BEC decided to discontinue the operations
     of Coneco, a wholly owned unregulated subsidiary that provided energy
     management services and to cease its participation in EnergyVision, an
     energy marketing joint venture with Williams Energy Services Company.
     The net income (loss) from these businesses was ($11,450,000),
     ($3,160,000) and $209,000 for 1998, 1997 and 1996, respectively.
 
(b)  The net equity income (loss) from equity investments is included in
     other income (expense), net on the consolidated statements of income.

Note K. Commitments and Contingencies

1.  Contractual Commitments

At December 31, 1998, BEC and its subsidiaries had estimated contractual
obligations for plant and equipment of approximately $28 million.  This includes
$13.5 million for nuclear fuel fabrication.  Under the Pilgrim 

                                       51
<PAGE>
 
purchase and sale agreement, Entergy will assume any unpaid portion of this
obligation for the current refueling and maintenance outage scheduled for May
1999 upon the sale closing date.

BEC and its subsidiaries also have leases for certain facilities and equipment.
The estimated minimum rental commitments under both transmission agreements and
noncancellable leases for the years after 1998 are as follows:
<TABLE> 
<CAPTION> 
(in thousands)
------------------------------------------------------
<S>                                           <C> 
1999                                          $ 18,905
2000                                            18,188
2001                                            15,160
2002                                            13,710
2003                                            11,617
Years thereafter                                94,484
------------------------------------------------------
         Total                                $172,064
======================================================
</TABLE> 
The total of future minimum rental income to be received under noncancellable
subleases related to the above leases is $146,125.

BEC and its subsidiaries will capitalize a portion of lease rentals as part of
plant expenditures in the future.  The total expense for both lease rentals and
transmission agreements was $29.6 million in 1998, $27.5 million in 1997 and
$26.3 million in 1996, net of capitalized expenses of $1.6 million in 1998, $1.2
million in 1997 and $2.9 million in 1996.

Boston Edison had previously entered into various take or pay and throughput
agreements, primarily to supply the New Boston fossil generating station with
natural gas.  As part of the fossil divestiture agreement, Sithe Energies
assumed these obligations.  The total expense under these agreements was $47.1
million in 1997 and $49.5 million in 1996.

2.  Electric Company Investments

Boston Edison has an approximately 11% equity investment in two companies which
own and operate transmission facilities to import electricity from the Hydro-
Quebec system in Canada.  As an equity participant Boston Edison is required to
guarantee, in addition to its own share, the total obligations of those
participants who do not meet certain credit criteria.  At December 31, 1998,
Boston Edison's portion of these guarantees was $15.2 million.

Boston Edison has a 9.5% equity investment of approximately $2 million in Yankee
Atomic Electric Company (Yankee Atomic).  In 1992 the board of directors of
Yankee Atomic decided to discontinue operations of the Yankee Atomic nuclear
generating station permanently and decommission the facility.

Yankee Atomic received approval from the FERC to continue to collect its
investment and decommissioning costs through 2000, the period of the plant's
operating license.  The estimate of Boston Edison's share of Yankee Atomic's
investment and costs of decommissioning is approximately $8 million as of
December 31, 1998.  This estimate is recorded on the consolidated balance sheet
as a power contract liability and an offsetting regulatory asset.

Boston Edison also has a 9.5% equity investment in Connecticut Yankee Atomic
Power Company (CYAPC) of approximately $10 million.  In December 1996, the board
of directors of CYAPC, which owns and operates the Connecticut Yankee nuclear
electric generating unit (Connecticut Yankee), unanimously voted to retire the
unit.  The decision was based on an economic analysis of the costs of operating
the unit through 2007, the period of its operating license,

                                       52
<PAGE>

compared to the costs of closing the unit and incurring replacement power costs
for the same period.
 
Boston Edison's share of Connecticut Yankee's remaining investment and estimated
costs of decommissioning is approximately $51 million as of December 31, 1998.
This estimate is recorded on the consolidated balance sheet as a power contract
liability and an offsetting regulatory asset similar to Yankee Atomic.

In December 1996, CYAPC filed for rate relief at the FERC seeking to recover
certain post-operating costs, including decommissioning.  In August 1998, the
FERC Administrative Law Judge (ALJ) released an initial decision regarding
CYAPC's filing.  This decision called for the disallowance of the common equity
return on the CYAPC investment subsequent to the shutdown.  The decision also
stated that decommissioning collections should continue to be based on a
previously approved estimate, with an adjustment for inflation, until a more
reliable estimate is developed.  In October 1998, both CYAPC and Northeast
Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ
decision.  If the initial decision is upheld, CYAPC could be required to write
off a portion of its investment in the generating unit and refund a portion of
the previously collected return on investment.  Management is currently unable
to determine the ultimate outcome of this proceeding, however, the estimate of
the effect of the ALJ's initial decision does not have a material impact on its
consolidated financial position or results of operations.

3.  Nuclear Insurance

The federal Price-Anderson Act currently provides $9.8 billion of financial
protection for public liability claims and legal costs arising from a single
nuclear-related accident.  The first $200 million of nuclear liability is
covered by commercial insurance.  Additional nuclear liability insurance up to
$9.6 billion is provided by a retrospective assessment of up to $88.1 million
per incident levied on each of the 109 nuclear generating units currently
licensed to operate in the United States, with a maximum assessment of $10
million per reactor per accident in any year.

Boston Edison has purchased insurance from Nuclear Electric Insurance Limited
(NEIL) to cover some of the costs to purchase replacement power during a
prolonged accidental outage and the cost of repair, replacement, decontamination
or decommissioning of utility property resulting from covered incidents at
Pilgrim Station.  Boston Edison's maximum potential total assessment for losses
which occur during current policy years is $8.1 million under both the
replacement power and excess property damage, decontamination and
decommissioning policies.

4.  Hazardous Waste

Boston Edison is an owner or operator of approximately 20 properties where oil
or hazardous materials were spilled or released.  As such, Boston Edison is
required to clean up these remaining properties in accordance with a timetable
developed by the Massachusetts Department of Environmental Protection.  There
are uncertainties associated with these costs due to the complexities of cleanup
technology, regulatory requirements and the particular characteristics of the
different sites.  Boston Edison also faces possible liability as a potentially
responsible party in the cleanup of five multi-party hazardous waste sites in
Massachusetts and other states where it is alleged to have generated,
transported or disposed of hazardous waste at the sites.  Boston 

                                       53
<PAGE>
 
Edison is one of many potentially responsible parties and currently expects to
have only a small percentage of the total potential liability for these sites.
Through December 31, 1998, BEC had approximately $6 million accrued on its
consolidated balance sheet related to these cleanup liabilities. Management is
unable to fully determine a range of reasonably possible cleanup costs in excess
of the accrued amount. Based on its assessments of the specific site
circumstances, it does not believe that it is probable that any such additional
costs will have a material impact on its consolidated financial position.
However, it is reasonably possible that additional provisions for cleanup costs
that may result from a change in estimates could have a material impact on the
results of a reporting period in the near term.

5.  Generating Unit Performance Program

Boston Edison's generating unit performance program ceased March 1, 1998.  Under
this program the recovery of incremental purchased power costs resulting from
generating unit outages occurring through the retail access date is subject to
review by the DTE.  Proceedings relative to generating unit performance remain
pending before the DTE.  These proceedings will include the review of
replacement power costs associated with the shutdown of the Connecticut Yankee
nuclear electric generating unit which is discussed in item 2.  Management is
unable to fully determine a range of reasonably possible disallowance costs in
excess of amounts accrued.  Based on its assessment of the information currently
available, it does not believe that it is probable that any such additional
costs will have a material impact on its consolidated financial position.
However, it is reasonably possible that additional disallowance costs that may
result from a change in estimates could have a material impact on the results of
a reporting period in the near term.

6.  Legal Proceedings

Industry and corporate restructuring legal proceedings

The DTE order approving the Boston Edison settlement agreement and the DTE order
approving the formation of BEC as a holding company were appealed by certain
parties to the Massachusetts Supreme Judicial Court (SJC).  In December 1998,
the SJC dismissed the appeal of the order approving the holding company
formation.  One settlement agreement appeal remains pending, however there has
to date been no briefing, hearing or other action taken with respect to this
proceeding.

In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.

Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.

A referendum seeking repeal of the Massachusetts electric industry restructuring
legislation that was enacted in November 1997 was overwhelmingly defeated by a
better than 70% to 30% margin in a state-wide general election held on November
3, 1998.  This outcome allows the comprehensive framework established for the
restructuring of the electric industry to continue as intended under the enacted
legislation.

                                       54
<PAGE>
 
Regulatory proceedings

In October 1997, the DTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings began in the fourth quarter of 1998 and are expected to be completed in
the first half of 1999.

Each of the Reading Municipal Light Department, the Littleton Electric Light
Department and the West Boylston Municipal Light Department have filed separate
claims for arbitration in Massachusetts alleging that the proposed transfer of
Pilgrim Station constitutes a breach of their respective power sale agreements
and seeking to terminate those agreements.  The remaining municipal light
departments have also indicated that they plan to file similar claims for
arbitration.  Boston Edison has requested the FERC to exercise its pre-emptive
authority to consider the claims of the municipal light departments.  In the
event that either the FERC determines, or as a result of the arbitrations, that
the contracts should be terminated, Boston Edison would continue to be obligated
to purchase power from Entergy that it intended to resell to the municipal light
departments.  Boston Edison may not be able to resell such power in the short-
term power exchange at a price equal to or greater than the price it is required
to pay to Entergy.  However, Boston Edison has filed at the DTE for recovery of
any such shortfall as part of its Pilgrim divestiture filing through the
transition charge.

Management is currently unable to determine the outcome of these proceedings
however, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.

Other litigation

In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison.  The town claims that Boston Edison
has wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts electric industry
restructuring legislation.  Boston Edison has disputed the town's claim and will
vigorously defend itself.  In addition to this pending litigation, Boston Edison
and the town of Plymouth are also parties in proceedings before the Appellate
Tax Board and the DTE concerning substantially the same dispute.  Management is
unable to determine the ultimate outcome of these proceedings however, if an
unfavorable outcome were to occur, there could be a material adverse impact on
business operations, the consolidated financial position or results of
operations for a reporting period.

In the normal course of its business BEC and its subsidiaries are also involved
in certain other legal matters.  Management is unable to fully determine a range
of reasonably possible legal costs in excess of amounts accrued.  Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position.  However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.

                                       55
<PAGE>
 
Note L. Long-Term Power Contracts

1.  Long-Term Contracts for the Purchase of Electricity

Boston Edison entered into a 13-month agreement effective December 1, 1998 to
transfer all of the unit output entitlements from its long-term power purchase
contracts to Select Energy (Select), a subsidiary of Northeast Utilities, Inc.
In return, Select will provide full energy service requirements to Boston
Edison, including NEPOOL capability responsibilities, at FERC approved tariff
rates through December 31, 1999.

Information relating to the contracts as of December 31, 1998 is as follows:
<TABLE> 
<CAPTION> 
                                            proportionate share (in thousands) 
                                 Units of  ----------------------------------- 
                                 Capacity                      Debt            
                   Contract     Purchased   Minimum     Outstanding            
                 Expiration    -----------     Debt   Through Cont.     Annual                                      
Generating Unit       Date       %    MW    Service      Exp. Date       Cost
------------------------------------------------------------------------------
<S>              <C>          <C>   <C>   <C>         <C>             <C> 
Canal Unit 1         2002      25.0   141   $ 1,433        $ 4,496    $ 22,936
Mass. Bay Trans-
portation
Authority - 1        2005     100.0    34         -              -       1,089
Ocean State Power -
Unit 1               2010      23.5    72     3,996         15,970      22,120
Ocean State Power -
Unit 2               2011      23.5    72     3,420         14,370      23,111
Northeast Energy
Associates           (a)       (a)    219         -              -     116,248
L'Energia (b)        2013      73.0    63         -              -      28,220
MassPower            2013      44.3   117    10,727         65,127      53,143
Mass. Bay Trans-
portation
 Authority - 2       2019     100.0    34         -              -         450
------------------------------------------------------------------------------
         Total                              $19,576        $99,963    $267,317
==============================================================================
</TABLE> 
(a)  Boston Edison purchases 75.5% of the energy output of this unit under
     two contracts.  One contract represents 135MW and expires in the year
     2015.  The other contract is for 84MW and expires in 2010.  Energy is
     paid for based on a price per kWh actually received.  Boston Edison does
     not pay a proportionate share of the unit's capital and fixed operating
     costs.

(b)  Boston Edison pays for this energy based on a price per kWh actually
     received.  An agreement has been made with L'Energia to terminate this
     contract.  FERC approval of this agreement is pending.

                                       56
<PAGE>

Boston Edison's total fixed and variable costs associated with these contracts
in 1998, 1997 and 1996 were approximately $267 million, $288 million and $281
million, respectively.  Boston Edison's minimum fixed payments under these
contracts for the years after 1998 are as follows:
<TABLE> 
<CAPTION> 
(in thousands)
------------------------------------------------------
<S>                                         <C> 
1999                                        $   86,072
2000                                            88,291
2001                                            88,662
2002                                            91,431
2003                                            81,927
Years thereafter                               856,790
------------------------------------------------------
         Total                              $1,293,173
======================================================
Total present value                         $  743,716
======================================================
</TABLE> 
2.  Long-Term Power Sales Contracts

In addition to other wholesale power sales, Boston Edison sells a percentage of
Pilgrim Station's output to other utilities and municipalities under long-term
contracts.  Information relating to these contracts is as follows:
<TABLE>
<CAPTION>
 
                                  Contract
                                 Expiration   Units of Capacity Sold
                                              -----------------------
Contract Customer (a)               Date           %           MW
-------------------------------  -----------  -----------  ----------
<S>                              <C>          <C>          <C>
 
Commonwealth Electric Company          2012         11.0         73.7
Montaup Electric Company               2012         11.0         73.7
Various municipalities                 2000 (b)      3.7         25.0
-------------------------------  ----------         ----        -----
     Total                                          25.7        172.4
===============================                     ====        =====
</TABLE>

(a)  Under these contracts, the utilities and municipalities pay their
     proportionate share of the costs of operating Pilgrim Station and
     associated transmission facilities.  These costs include operation and
     maintenance expense, insurance, local taxes, depreciation,
     decommissioning and a return on investment.  The long-term power sales
     contracts with Commonwealth Electric Company and Montaup Electric Company
     will be terminated upon the closing of the sale of Pilgrim Station to
     Entergy.  The contracts with the municipalities remain in place whereby
     Boston Edison will purchase power for resale to the municipalities under
     a purchase power agreement entered into with Entergy.

(b)  Subject to certain adjustments.

                                       57
<PAGE>
 
Selected Consolidated Quarterly Financial Data (Unaudited)
<TABLE> 
<CAPTION> 
(in thousands, except earnings per share)

                                                      Earnings         Basic
                                                     Available      Earnings
               Operating   Operating         Net    for Common   Per Average
                Revenues      Income      Income  Shareholders  Common Share(a) 
             ----------------------------------------------------------------
<S>             <C>         <C>         <C>       <C>           <C> 
1998
----

First quarter   $394,117    $ 49,203     $22,859       $19,940         $0.41
Second quarter   385,708      64,748      34,323        31,452          0.65
Third quarter    479,537     100,047      75,490        74,004          1.55
Fourth quarter   363,153      28,942       8,374         6,885          0.15

1997
----

First quarter   $422,856    $ 47,138     $20,935       $17,118         $0.35
Second quarter   426,835      59,633      33,978        30,484          0.63
Third quarter    520,414     106,673      81,418        78,499          1.62
Fourth quarter   408,426      43,500       8,311         5,392          0.11
</TABLE> 
(a)  Based on the weighted average number of common shares outstanding during
     each quarter.

Item 9.  Changes in and Disagreements with Accountants on Accounting and
------------------------------------------------------------------------
Financial Disclosure
--------------------

Not applicable.

                                       58
<PAGE>
 
                                   Part III
                                   --------

Item 10.  Trustees and Executive Officers of the Registrant
-----------------------------------------------------------

(a)  Identification of Trustees
-------------------------------

Information about Nominees and Incumbent Trustees

Throughout Item 10, there are references to Trustees/Directors of BEC Energy and
Boston Edison.  Note that prior to the reorganization into the holding company
structure, Boston Edison Company was the parent company of the consolidated
group.

The BEC Energy board has fixed the number of trustees at eleven as permitted
under its bylaws.  BEC Energy's declaration of trust provides for the
classification of the BEC Energy board into three classes serving staggered
three-year terms.  The four persons named below have been nominated by the BEC
Energy board for election as Class II trustees for a term expiring at the year
2002 annual meeting and until their successors are duly chosen and qualified.
The remaining trustees will continue to serve as provided below, with the Class
III trustees having terms expiring in 2000 and the Class I trustees having terms
expiring in 2001.  If any of the nominees shall be unavailable as a candidate at
the BEC Energy annual meeting by reason of death, disability or resignation,
votes exercised through the proxies will be cast for a substitute candidate as
may be designated by the BEC Energy board, or in the absence of a designation,
in a manner the trustees may determine in their discretion.  Alternatively, in
this situation, the BEC Energy board may take action to fix the number of
trustees for the ensuing year at the number of nominees named herein who are
then able to serve.

The BEC Energy board has adopted the following trustee retirement policy.
Trustees who are employees of BEC Energy or Boston Edison Company, with the
exception of the chief executive officer, retire from the BEC Energy board when
they retire from employment with BEC Energy or Boston Edison Company.  Under the
BEC Energy board's current policy, trustees who are not employees of BEC Energy
or Boston Edison Company or who have served as chief executive officer retire
from the board at the annual shareholder meeting following their seventieth
birthday.

The BEC Energy board, which held five regular meetings and two special meetings
in 1998 since the establishment of BEC Energy on May 20, 1998, has an Executive
Committee, an Audit, Finance and Risk Management Committee, an Executive
Personnel Committee, and a Pricing Committee.  During 1998, the Executive
Committee met three times.  The Executive Committee is authorized to act as a
nominating committee and to review trustee compensation during the intervals
between BEC Energy's board meetings.  The Audit, Finance and Risk Management
Committee met one time.  Its responsibilities include recommendations as to the
selection of independent auditors, review of the scope of the independent audit,
annual financial statements, internal audit reports, and financial and
accounting controls and procedures, and review of BEC Energy's financial
requirements, insurance coverages, and legal compliance programs.  The Executive
Personnel Committee, which is responsible for reviewing executive officer
compensation, personnel planning and performance, some company benefit programs,
and human resources policies, also met one time.  The Pricing Committee, which
is authorized to approve the terms of debt and equity offerings, did not meet in
1998.  All trustees attended at least 75% of the aggregate of the total number
of meetings of the BEC Energy board and the total number of meetings held by all
committees of the BEC Energy

                                       59
<PAGE>

board on which he or she served, with the exception of Mr. Egan, who attended
65% of these meetings.
 
(b)  Identification of Executive Officers
-----------------------------------------

The information required by this item is included at the end of Part I of this
Form 10-K/A under the caption Executive Officers of the Registrant.

(c)  Identification of Certain Significant Employees
----------------------------------------------------

Not applicable.

(d)  Family Relationships
-------------------------

Not applicable.

(e)  Business Experience
------------------------

The names of the nominees as Class II trustees and the incumbent Class I and
Class III trustees and selected information concerning them are shown in the
table below.  Unless a specific time period is indicated, each nominee and
trustee has held the position first listed across from his or her name for at
least five years.

            Nominees as Class II Trustees - Terms Expiring in 2002
            ------------------------------------------------------
<TABLE>
<CAPTION>
 
Nominees                     Principal Occupation and Directorships
---------------------------  --------------------------------------------------------------
<S>                          <C>
 
Charles K. Gifford           Chairman (since 1997 and from 1995-1996) and
Age:  56                     Chief Executive Officer (since 1995), formerly
Trustee since:  1998         President (1989-1995), BankBoston Corporation
Boston Edison Company        (Bank Holding Company), and Chairman and Chief
Director since:  1990        Executive Officer (since 1995), formerly
Member:  Audit, Finance      President (1989-1996), BankBoston, N.A.;
and Risk Management,         Director, Boston Edison Company, BankBoston
Executive Personnel          Corporation, BankBoston, N.A., Massachusetts
And Pricing Committees       Mutual Life Insurance Company.
 
Paul A. LaCamera             President and General Manager (since 1997),
Age:  55                     WCVB-TV Channel 5, formerly Vice President and
Trustee and Boston           General Manager (1994-1997); Director, Boston
Edison Company Director      Edison Company.
since:  1998
Member:  Audit, Finance
and Risk Management
Committee
 
Thomas J. May                Chairman, President and Chief Executive Officer
Age:  51                     (since 1998), BEC Energy, and Chairman,
Trustee since:  1998         President (since 1995) and Chief Executive
Boston Edison Company        Officer, Boston Edison Company; Director, Boston 
Director since:  1991        Edison Company, BankBoston Corporation,
Member:  Executive           BankBoston, N.A., Liberty Mutual Insurance
and Pricing Committees       Company, Liberty Mutual Fire Insurance Company,
                             Liberty Financial Companies, Inc., RCN
                             Corporation.

</TABLE> 

                                       60
<PAGE>
 
<TABLE>
<CAPTION>
Nominees                     Principal Occupation and Directorships
-----------------------      -----------------------------------------------
<S>                          <C>
 
Sherry H. Penney             Chancellor (1988-1995 and 1996 to present),
Age:  61                     University of Massachusetts at Boston, formerly
Trustee since:  1998         President (1995) (interim), University of
Boston Edison Company        Massachusetts; Director, Boston Edison Company.
Director since:  1990
Member:  Audit, Finance
and Risk Management and
Executive Personnel
Committees
<CAPTION> 

          Incumbent Class III Trustees - Terms Expiring in 2000
          -----------------------------------------------------
Trustees                     Principal Occupation and Directorships
---------------------------  ------------------------------------------------
<S>                          <C>
 
Gary L. Countryman           Chairman of the Board, Liberty Mutual Insurance
Age:  59                     Company and Liberty Life Assurance Company of
Trustee since:  1998         Boston, formerly Chief Executive Officer (1985-
Boston Edison                1998), Liberty Mutual Insurance Company and
Company Director             Liberty Life Assurance Company of Boston;
since:  1986                 Director, Boston Edison Company, Liberty Mutual
Member:  Executive           Insurance Company, Liberty Life Assurance
And Executive                Company of Boston, Liberty Mutual Fire Insurance
Personnel Committees         Company, Liberty Financial Companies, Inc.,
                             BankBoston Corporation, BankBoston, N.A., The
                             Neiman-Marcus Group, Inc., Alliance of American
                             Insurers.
 
Thomas G. Dignan, Jr. (1)    Partner, Ropes & Gray (Law Firm); Director,
Age:  58                     Boston Edison Company.
Trustee since:  1998
Boston Edison Company
Director since:  1983
Member:  Executive
Committee
 
Herbert Roth, Jr.            Former Chairman of the Board (1978-1985) and
Age:  70                     Chief Executive Officer (1968-1985), LFE
Trustee since:  1998         Corporation (Traffic and Industrial Process
Boston Edison Company        Control Systems); Director/Trustee, Boston
Director since:  1978        Edison Company, Landauer, Inc., Tech/Ops Sevcon,
Member:  Audit,              Inc., Phoenix Home Life Mutual Insurance
Finance and Risk             Company, Phoenix Series Fund, Phoenix Total
Management Committee         Return Fund, Inc., Phoenix Multi-Portfolio Fund,
                             The Bid Edge Series Fund, Mark IV Industries.
 
Stephen J. Sweeney           Former Chairman of the Board (1986-1992) and
Age:  70                     Chief Executive Officer (1984-1990), Boston
Trustee since:  1998         Edison Company; Director, Boston Edison Company,
Boston Edison Company        Selecterm, Inc., Liberty Mutual Insurance
Director since:  1983        Company, Liberty Mutual Fire Insurance Company,
Member:  Audit,              Liberty Life Assurance Company of Boston,
Finance and Risk             Liberty Financial Companies, Inc., Uno
Management Committee         Restaurant Corporation.
</TABLE>

                                       61
<PAGE>
 
           Incumbent Class I Trustees - Terms Expiring in 2001
           ---------------------------------------------------
<TABLE>
<CAPTION>
 
Trustees                 Principal Occupation and Directorships
-----------------------  ------------------------------------------------
<S>                      <C>
 
Nelson S. Gifford        Principal, Fleetwing Capital (Venture
Age:  68                 Investments); formerly Chairman (1986-1990) and
Trustee since:  1998     Chief Executive Officer (1975-1990), Dennison
Boston Edison Company    Manufacturing Company (Stationery Products,
Director since:  1981    Systems and Packaging); Director, Boston Edison
Member:  Executive       Company, John Hancock Mutual Life Insurance
Committee                Company, Reed and Barton, J.M. Huber Corp.,
                         Nypro Inc, Partners Fund.
 
Richard J. Egan          Chairman of the Board, EMC Corporation (Storage
Age:  63                 Related Computer System Products); Director,
Trustee since:  1998     Boston Edison Company, Cognition Inc., Shiva
Boston Edison Company    Corporation, New York Stock Exchange Listed
Director since:  1997    Company Advisory Committee.
Member:  Executive
Personnel Committee
 
Matina S. Horner         Executive Vice President, Teachers Insurance and
Age:  59                 Annuity Association/College Retirement Equities
Trustee since:  1998     Fund; formerly President (1972-1989), Radcliffe
Boston Edison Company    College; Director, Boston Edison Company, The
Director since:  1988    Neiman-Marcus Group, Inc.
Member:  Executive,
Audit, Finance and
Risk Management and
Pricing Committees
</TABLE>

(1)  During 1998, Boston Edison Company and BEC Energy paid legal fees to the
     firm of Ropes & Gray.

(f)  Involvement in Certain Legal Proceedings
---------------------------------------------

Not applicable.

(g)  Promoters and Control Persons
----------------------------------

Not applicable.

Item 11.  Executive Compensation
--------------------------------

Trustee Compensation

In 1998, the compensation programs for trustees were reviewed and revised with
the assistance of an external compensation consultant.  The review was initiated
to assure that the level of compensation be appropriate in reference to
comparable programs, the plan design supports BEC Energy's strategic objectives,
and the interests of the trustees are aligned with those of shareholders.

Each trustee who is not an employee of BEC Energy receives an annual board
retainer of $20,000 in cash.  Each trustee also receives an annual retainer of
$20,000 worth of BEC Energy common shares which is deferred until the trustee
retires from the board.  Each non-employee trustee who is a member of the
Executive Committee receives an additional retainer of $3,000 and each trustee
who chairs a BEC Energy board committee receives an additional retainer of

                                       62
<PAGE>
 
$3,000.  All other retainers were discontinued as of October 1998.  Each trustee
who is not an employee of BEC Energy receives $1,000 for attendance in person at
each meeting of the BEC Energy board or a committee and $500 for participating
in a meeting by telephone.  Trustees may elect to defer part or all of their
trustees' fees under BEC Energy's deferred fee plan.  Two programs were
discontinued:  the 1991 Director Stock Plan and the 1993 Directors' Retirement
Benefit.  An amount equal to the present value of the benefit each outside
trustee accrued under the Directors' Retirement Benefit was deposited in
deferred accounts.  Receipt is deferred until the trustee's retirement from the
BEC Energy board.

Report of the Executive Personnel Committee

Under the rules established by the SEC, BEC Energy is required to provide
specified data and information with regard to the compensation and benefits
provided to its executive officers, including BEC Energy's chief executive
officer and the four other most highly compensated executive officers.  The
disclosure requirements for these officers (the "Named Executive Officers")
include tables summarizing total compensation and a report explaining the
rationale and considerations that led to fundamental executive compensation
decisions affecting those individuals for the prior year.

The Executive Personnel Committee

BEC Energy's executive compensation program is administered by the Executive
Personnel Committee, a committee of the BEC Energy board composed of the four
non-employee trustees listed as signatories to this report.  Except as discussed
below, none of these non-employee trustees has any interlocking or other
relationship with BEC Energy that would require disclosure to the SEC.
Generally, all decisions of the Executive Personnel Committee regarding the
compensation of the chief executive officer are subject to the approval of the
non-employee trustees of BEC Energy, none of whom is eligible to participate in
the incentive plans described below.  The Executive Personnel Committee
administers the 1997 Stock Incentive Plan discussed below.

The Named Executive Officers

The officers identified as the five most highly compensated executive officers
of BEC Energy are all employees of Boston Edison Company, BEC Energy's principal
subsidiary.  Three of the Named Executive Officers, Messrs. May, Horan and
Judge, also serve as officers of BEC Energy, in the following capacities:  Mr.
May as Chairman, President and Chief Executive Officer; Mr. Horan as Senior Vice
President and General Counsel; and Mr. Judge as Senior Vice President and
Treasurer.  BEC Energy does not have any employees of its own.

Compensation Philosophy

The executive compensation philosophy of BEC Energy is to provide competitive
levels of compensation that advance BEC Energy's annual and long-term
performance objectives, reward corporate performance, and assist BEC Energy in
attracting, retaining and motivating highly qualified executives.  The framework
for the compensation committee's executive compensation program is to establish
base salaries which are competitive with electric utilities in general and to
incentivize excellent performance by providing executives with the opportunity
to earn additional remuneration under the annual and long-term incentive plans.
The incentive plan goals are designed to improve the effectiveness and enhance
the efficiency of BEC Energy's operations and to create value for shareholders.
The committee also seeks to link executive and 

                                       63
<PAGE>
 
shareholder interests through equity-based incentive plans. Accordingly, in
1997, upon the committee's recommendation, the Boston Edison board approved
stock ownership guidelines of three times base salary for the chief executive
officer and one to one-and one-half times base salary for the other executive
officers of BEC Energy and Boston Edison Company. These guidelines allow the
executives five years to acquire this amount of stock.

Components of Compensation

Compensation paid to the Named Executive Officers, as reflected in the following
tables, consists of three primary elements:  base salary, annual incentive
awards, and long-term incentive awards.  BEC Energy compares its compensation
levels against those of other growth-oriented investor-owned electric utility
companies.  BEC Energy's strategy is to establish total compensation, i.e., base
salary and annual incentives, at the 60th percentile of the utility industry,
and to compare its long-term incentive plan to those of more aggressive
utilities and general industry companies that focus on value creation.

During 1998, the committee thoroughly reviewed data collected by nationally
recognized compensation experts as well as by Boston Edison's human resources
group to determine whether BEC Energy's compensation strategy was being met.
The review evaluated base salary and annual incentives of nearly all electric
utility companies, and long-term incentives of a blend of utilities and general
industry.  The data demonstrated that BEC Energy was in conformity with its
compensation strategy to the satisfaction of the committee.

The income tax deductions of publicly traded companies may be limited to the
extent total compensation for particular executive officers exceeds one million
dollars during any year.  This deduction limit, however, does not apply to
payments which qualify as "performance based".  The committee has reviewed the
regulations issued by the Internal Revenue Service and will continue to review
the application of these rules to future compensation.  However, the committee
intends to continue basing its executive compensation decisions primarily upon
performance achieved, both corporate and individual, while retaining the right
to make subjective decisions and to award compensation that may or may not meet
all of the Internal Revenue requirements for deductibility.

Annual Incentive Plan

Annual incentive payments to the Named Executive Officers, reported in the
fourth column of the Summary Compensation Table below, are based on both
corporate and business unit performance objectives which are derived from the
corporate operating plan and approved by the committee.  Corporate performance
objectives include a comparison of target to actual earnings per share from
operations.  Business unit performance objectives include predetermined levels
for operating and capital budgets, as well as key operating goals.  The annual
incentive plan award for Mr. May is based solely on BEC Energy's achieving the
earnings per share objective.  In 1998, basic earnings per share were $2.76,
which exceeded the plan target.  The annual incentive plan awards for Messrs.
Gustin, Horan, Judge and Ledgett were based 50% on earnings per share and 50% on
specific business unit performance objectives to achieve various budget and
operating plan targets.  All four officers exceeded the specified business unit
performance levels.

                                       64
<PAGE>
 
Long-Term Compensation

Under the 1997 Stock Incentive Plan, executive officers and other key employees
are eligible to receive grants from time to time of stock-related awards of
seven general types:  (i) stock options, (ii) stock appreciation rights, (iii)
restricted stock awards, (iv) deferred stock awards, (v) performance unit
awards, (vi) dividend equivalent awards, and (vii) other stock-based awards.
The long-term grant in May of 1998 consisted of non-qualified stock options,
deferred shares and dividend equivalents on the deferred shares, and was based
upon the committee's evaluation of performance towards key strategic objectives,
and competitive award data provided by an external consultant.  The committee
did not weight any of these factors.  The options and the deferred shares vest
at the rate of 33% per year over a three-year period from the date of grant, and
the options may be exercised over a ten-year period.

Other Plans

At various times in the past, BEC Energy and Boston Edison Company have adopted
various broad-based employee benefit plans in which officers are permitted to
participate on the same terms as non-executive employees who meet applicable
eligibility criteria.  These plans include pension, life, and health insurance
plans, as well as a section 401(k) savings plan which includes a company
matching contribution equal to the first six percent of pay contributed by the
employee up to a maximum excludable 401(k) contribution allowed by the Internal
Revenue Code.  In addition, Boston Edison Company has a deferred compensation
plan in which officers and senior managers may elect to participate.

In 1996, the committee implemented a supplemental executive retirement plan
which provides eligible participates with supplementary retirement income of up
to 60% of final average cash compensation, depending upon each participant's
years of service, reduced by 50% of the participant's social security benefit
and further reduced by benefits the participant receives under Boston Edison's
pension plan.

Mr. May's 1998 Compensation

The Executive Personnel Committee makes decisions regarding the compensation of
the chief executive officer using the same philosophy and criteria described
above.  As with the compensation of all officers, BEC Energy compares
compensation levels for the chief executive officer to those of all other
investor-owned electric utility companies.

Each year BEC Energy approves the adjustment of salary ranges for the chief
executive officer and other corporate officers based on studies conducted by
external executive compensation consultants and Boston Edison Company's human
resources group.  The 1998 studies found BEC Energy's executive compensation
levels to be within the approved 60th percentile position to market.  Mr. May
received a 5% increase to his base salary in 1998.

Mr. May's annual incentive award, shown in the fourth column of the Summary
Compensation Table below, was in conformity with the provisions of the annual
incentive plan described above, and was based on BEC Energy surpassing its
operating plan targets.  The committee's policy is to base individual long-term
incentive awards on an annual study by the compensation consultant comparing the
value of long-term incentive grants to salary levels for a blend of electric
utility and general industry companies.  The 6,000 deferred shares and 60,000
options granted Mr. May in 1998 reflect this policy.

                                       65
<PAGE>
 
Compensation Committee Interlocks and Insider Participation

Charles K. Gifford, who is a member of BEC Energy's Executive Personnel
Committee, is Chairman and Chief Executive Officer of BankBoston Corporation and
BankBoston, N.A.  Thomas J. May, BEC Energy's Chairman, President and Chief
Executive Officer, serves on the boards of directors of BankBoston Corporation
and BankBoston, N.A.

Gary L. Countryman, who is the Chairman of BEC Energy's Executive Personnel
Committee, is Chairman of the Board and Chief Executive Officer of Liberty
Mutual Insurance Company and Liberty Mutual Fire Insurance Company and Chairman
of the Board of Liberty Financial Companies, Inc.  Mr. May serves on the boards
of directors of Liberty Mutual Insurance Company, Liberty Mutual Fire Insurance
Company, and Liberty Financial Companies, Inc.

                                 By the Executive Personnel Committee,


                                 Gary L. Countryman (Chairman)
                                 Richard J. Egan
                                 Charles K. Gifford
                                 Sherry H. Penney

Executive Compensation Tables

The following information is given regarding annual and long-term compensation
earned by the chief executive officer and the four other most highly compensated
executive officers of BEC Energy and Boston Edison Company with respect to the
years 1996, 1997 and 1998.

                                       66
<PAGE>
 
                          Summary Compensation Table
                          --------------------------
<TABLE> 
<CAPTION>  
                                  Annual                               Long-Term
                               Compensation                      Compensation Awards       Payouts
                             ------------------               -------------------------   ----------
                                                                             Securities
                                                    Other         Deferred   Underlying
Name and                                            Annual         Share      Options/       LTIP        All Other
Principal Position    Year    Salary    Bonus    Compensation(1)  Awards(2)    SARs(#)      Payouts   Compensation(3)
-------------------  -----   --------  --------  -------------- -------------  ----------   ----------  ---------------
<S>                  <C>     <C>       <C>       <C>             <C>           <C>          <C>         <C>
 
Thomas J. May.....     1998  $519,583  $600,000          -          238,500      60,000            -       $ 9,600
 Chairman,             1997   496,875   498,750          -          426,400     100,000            -         9,600
  President and        1996   463,625   324,750          -                -           -            -         9,000
  Chief Executive
  Officer
 BEC Energy and
  Boston Edison
  Company
 
Ronald A. Ledgett.     1998   277,875   248,850          -           99,375      27,000            -        84,600
 Executive Vice        1997   232,500   216,750          -          118,450      28,600            -         9,600
  President,           1996   193,667   119,300          -                -           -            -         9,000
 Boston Edison
  Company
 
Douglas S. Horan..     1998   208,750   196,750          -           59,625      14,000            -        59,600
 Senior Vice           1997   195,417   140,000          -          103,000      25,000            -         9,600
  President,           1996   175,833    83,750          -                -           -            -         9,000
 BEC Energy and
  Boston Edison
  Company
 
James J. Judge....     1998   205,417   196,750          -           59,625      14,000            -        59,600
 Senior Vice           1997   183,667   136,400          -           97,850      23,400            -         9,600
 President,            1996   167,000    80,000          -                -           -            -         9,000
BEC Energy and
 Boston Edison
 Company

L. Carl Gustin....     1998   194,375   163,875          -           51,675      12,000            -         9,600
Senior Vice            1997   187,813   121,250          -           97,850      23,800            -         9,600
 President,            1996   182,507    67,262          -                -           -            -         9,000
Boston Edison
 Company
</TABLE> 
(1)  None of the Named Executive Officers received amounts of other annual
     compensation in 1996, 1997, or 1998 which would require disclosure
     under SEC rules.

(2)  Deferred common share awards are valued at the closing market price as
     of the date of the grant.  The awards vest one-third on each of the
     first, second and third anniversaries of the date of the grant.
     Dividends will accrue on the awards from the date of grant and will be
     be payable in the form of additional shares which will vest at the same
     time the awards vest.  Aggregate deferred common share holdings and
     values based on the closing price of the common shares on December 31,
     1998 are as follows:  Mr. May, 16,933 shares ($697,428); Mr. Ledgett,
     5,567 shares ($229,291); Mr. Gustin, 3,833 shares ($157,872); Mr. Horan,
     4,167 shares ($171,628) and Mr. Judge, 4,033 shares ($166,109).

(3)  Messrs. Ledgett, Horan and Judge received payments in the amounts of
     $75,000, $50,000 and $50,000 respectively, under retention agreements
     entered into in 1996.  All other amounts in this column represent Boston
     Edison's matching contribution under its 401(k) plan.

                                       67
<PAGE>
 
                       Option Grants in Last Fiscal Year
                       ---------------------------------
<TABLE>
<CAPTION>
                                                                  Individual Grants
                                                ---------------------------------------------------
                                                                    % of
                                                                    Total
                                                                   Options                              Grant
                                                     Number of     Granted     Exercise                 Date
                                                    Securities        to          or                   Present
                                                    Underlying     Employees     Base    Expiration     Value
Name                                            Options Granted(1)  in 1998     Price        Date         (2)
----                                            -----------------  ---------  ---------  ----------    -------
<S>                                             <C>                <C>         <C>        <C>          <C>      
 
Thomas J. May.................................       60,000           14.3%     $ 39.75    4/22/08     $276,600
Ronald A. Ledgett.                                   27,000            6.4%     $ 39.75    4/22/08     $124,470
L. Carl Gustin................................       12,000            2.9%     $ 39.75    4/22/08     $ 55,320
Douglas S. Horan..............................       14,000            3.3%     $ 39.75    4/22/08     $ 64,540
James J. Judge................................       14,000            3.3%     $ 39.75    4/22/08     $ 64,540
 
</TABLE> 
(1)  Options vest one-third annually beginning April 22, 1999.
 
(2)  The grant date present values were determined using the Black-Scholes
     option pricing model. There is no assurance that the value realized would
     be at or near the value estimated by the Black-Scholes model. Assumptions
     used for the model are as follows: stock volatility, 16%; risk-free
     interest rate, 5.66%; dividend yield, 4.88%; and time to exercise, four
     years.
     
              Aggregated Option/SAR Exercises and Fiscal Year-End
              ---------------------------------------------------
                              Option Value Table
                              ------------------
<TABLE> 
<CAPTION> 
                                                                               Number of Securities       Value of Securities
                                                                                   Underlying            Underlying Unexercised
                                                                               Unexercised Options       In-the-Money Options
                                                Shares/SARs                    At Fiscal Year-End       At Fiscal Year-End (1)
                                                Acquired on     Value     ---------------------------  -------------------------
Name                                             Exercise      Realized     Exercisable/Unexercisable  Exercisable/Unexercisable
----------------------------------------------  -----------   ---------   ---------------------------  --------------------------
<S>                                             <C>           <C>         <C>                          <C>  
Thomas J. May.................................            0          $0        33,333  /  126,667        $506,245  /  $1,098,755
Ronald A. LedgettA............................            0          $0         9,533  /   46,067        $147,166  /  $333,159
L. Carl Gustin................................            0          $0         7,933  /   27,867        $122,466  /  $262,197
Douglas S. Horan..............................            0          $0         8,333  /   30,667        $128,641  /  $277,422
James J. Judge................................            0          $0         7,800  /   29,600        $120,413  /  $260,950
</TABLE> 
(1)  Based on the closing price of BEC Energy common shares on December 31,
     1998 of $41.1875.

                                       68
<PAGE>
 
Pension Plan Table

The following table shows the estimated annual retirement benefits payable to
executive officers under the qualified pension plan and the supplemental
executive retirement plan, assuming retirement at age 65.  The supplemental
executive retirement plan is a non-qualified pension plan providing a maximum
benefit of 60% of compensation after the executive has accumulated 20 years of
credited service and has reached age 60.  The supplemental executive retirement
plan provides the incremental benefits in excess of the benefits paid under the
qualified plan necessary to reach the benefit shown in the table.  Each of the
officers named in the Summary Compensation Table participates in the
supplemental executive retirement plan.  The benefits presented are based on a
straight life annuity and do not take into account a reduction in benefits of up
to 50% of the participant's primary social security benefit.
<TABLE>
<CAPTION>
 
                   Years of Credited Service
Average Annual    ----------------------------
Compensation         10        15        20
----------------  --------  --------  --------
<S>               <C>       <C>       <C>
 
$200,000........  $ 60,000  $ 90,000  $120,000
$300,000........    90,000   135,000   180,000
$400,000........   120,000   180,000   240,000
$500,000........   150,000   225,000   300,000
$600,000........   180,000   270,000   360,000
$700,000........   210,000   315,000   420,000
$800,000........   240,000   360,000   480,000
$900,000........   270,000   405,000   540,000
</TABLE>

For purposes of the retirement plans, Messrs. May, Ledgett, Gustin, Horan and
Judge currently have 23, 18, 18, 21 and 21 years of credited service,
respectively.

Final average compensation for purposes of calculating the benefits under the
supplemental executive retirement plan is the highest average annual
compensation of the participant during any consecutive 36-month period.
Compensation taken into account in calculating the benefits described above
includes salary and annual bonus, including any amounts deferred under the terms
of the deferred compensation plan.

Mr. May can elect, and Mr. Ledgett receives, an alternative supplemental
retirement benefit equal to 33% of final base salary annually for 15 years,
which at the current level would provide Mr. Ledgett with approximately $7,000
in excess of the amounts shown in the table above.

Change of Control Agreements

BEC Energy, through its Boston Edison Company subsidiary has change of control
agreements with various key employees, including those named in the Summary
Compensation Table, which provide severance benefits in the event of specified
terminations of employment following a change in control of Boston Edison.
Events which constitute a change of control under these agreements are described
below.  If, following a change in control, the employee's employment is
terminated without cause or the employee terminates employment for good reason,
the employee receives severance pay in an amount equal to two times, three times
in the case of Mr. May, the sum of annual base salary (at the rate in effect
immediately prior to the date of termination or immediately before the change of
control, whichever is higher) plus actual bonus paid in respect of the most
recently completed fiscal year or target bonus for the fiscal year in which the
termination occurs, whichever is higher.  In addition, the change 

                                       69
<PAGE>
 
of control agreements provide for a pro rated bonus payment for the year in
which the termination occurs, the immediate vesting of bonus awards, immediate
payment of deferred compensation amounts upon the termination and payments equal
to the benefit the employee would have received under Boston Edison Company's
retirement plan assuming the executive was vested and remained employed for an
additional two years, three years in the case of Mr. May. For two years, three
years in the case of Mr. May, following termination of employment, the employee
would be entitled to continue to participate in all welfare plans provided by
Boston Edison Company. The change of control agreements further provide for a
"gross-up" payment under which, if amounts paid under these agreements would be
effectively reduced a federal excise tax on "excess parachute payments," Boston
Edison Company will pay the employee an additional amount of cash, so that,
after payment of all parachute taxes by the employee, the employee will have
received the amount the employee would have received in the absence of any such
tax. A change of control under these agreements generally includes the following
events: (i) a person or group becomes the beneficial owner of more than 30% of
the voting power of Boston Edison Company's securities; (ii) continuing
directors cease to be a majority of the Boston Edison Company board; (iii) a
consolidation, merger or other reorganization or sale or other disposition of
all or substantially all of the assets of Boston Edison Company, other than
certain defined transactions; or (iv) approval by the stockholders of a complete
liquidation or dissolution of Boston Edison Company.

Item 12.  Security Ownership of Certain Beneficial Owners and Management
------------------------------------------------------------------------

(a)  Security Ownership of Certain Beneficial Owners
----------------------------------------------------

To the knowledge of management, no person owns beneficially more than five
percent of the BEC Energy common shares.

(b)  Security Ownership of Management
-------------------------------------

The following table sets forth certain information regarding the beneficial
ownership of BEC Energy common shares as of January 31, 1999, assuming the
exercise of all options exercisable on, or within 60 days of, such date, by (i)
each trustee, (ii) the chief executive officer and each of the other four most
highly compensated executive officers of BEC Energy/Boston Edison Company, (iii)
all executive officers and trustees as a group.  None of the individual or
collective holdings below exceeds 1% of the outstanding BEC Energy common
shares.  No member of the group is the beneficial owner of Boston Edison
Company's cumulative preferred stock.

                                       70
<PAGE>
 
<TABLE> 
<CAPTION> 
                                                      Number of Shares of
                                                       BEC Energy Common
Name of Beneficial Owner                            Stock Beneficially Owned
------------------------                            ------------------------
<S>                                                 <C> 
Gary L. Countryman................................            4,614
Thomas G. Dignan, Jr..............................            5,290
Richard J. Egan...................................            1,777
Charles K. Gifford................................            3,515
Nelson S. Gifford.................................            8,412
L. Carl Gustin....................................           18,684
Douglas S. Horan..................................           17,609
Matina S. Horner..................................            4,365
James J. Judge....................................           16,437
Paul A. LaCamera..................................              233
Ronald A. Ledgett.................................           22,523
Thomas J. May.....................................           74,445
Sherry H. Penney..................................            4,342
Herbert Roth, Jr..................................            8,759
Stephen J. Sweeney................................            5,873
All trustees and executive officers as a group,
including those named above (18 persons)..........          228,586
</TABLE> 
(1)  The following BEC Energy common shares are held in Boston Edison
     Company's Deferred Compensation Trust due to deferrals by the following
     participants under Boston Edison Company's Deferred Compensation Plan:
     Mr. Horan, 1,564 shares; Mr. Judge, 1,351 shares; Mr. Ledgett, 4,052
     shares; Mr. May, 13,813 shares; all executive officers as a group,
     25,725 shares.  Trustees and officers who are participants in Boston
     Edison Company's Deferred Compensation Plan may instruct the trustee to
     vote BEC Energy common shares held in the trust in accordance with their
     allocable share of such deferrals, but trustee participants have no
     dispositive power with respect to shares held in the trust.

(2)  These totals include the following number of BEC Energy common shares
     held in Boston Edison Company's 401(k) Plan:  Mr. Gustin, 4,346 shares;
     Mr. Horan, 2,772 shares; Mr. Judge, 2,655 shares; Mr. Ledgett, 3,062
     shares; Mr. May, 8,163 shares; all executive officers as a group, 28,713
     shares.

(3)  3,629 of Mr. Sweeney's 5,873 shares are held in a charitable annuity
     remainder trust, of which he, as a co-trustee of the trust, shares
     dispositive and voting power with respect to the shares.

(c)  Changes in Control
-----------------------

Not applicable.

Item 13.  Certain Relationships and Related Transactions
--------------------------------------------------------

Not applicable.

                                       71
<PAGE>
 
                                    Part IV
                                    -------

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K
-------------------------------------------------------------------------

(a) The following documents are filed as part of this Form 10-K/A:


1.  Financial Statements:
                                                                        Page
                                                                        ----
Consolidated Statements of Income for the years ended
December 31, 1998, 1997 and 1996                                         30

Consolidated Statements of Retained Earnings for the
years ended December 31, 1998, 1997 and 1996                             30

Consolidated Balance Sheets as of December 31, 1998 and 1997             31

Consolidated Statements of Cash Flows for the years
ended December 31, 1998, 1997 and 1996                                   32

Notes to Consolidated Financial Statements                               33

Selected Consolidated Quarterly Financial Data (Unaudited)               58

Report of Independent Accountants                                        81


2.  Financial Statement Schedules:

No financial statement schedules are included as they are either not required or
not applicable.


3.  Exhibits:

Refer to the exhibits listing beginning on the following page.



(b) Reports on Form 8-K:

A Form 8-K dated November 23, 1998, was filed during the fourth quarter of 1998
disclosing that Entergy Nuclear Company was selected as the winning
bidder for the purchase of Pilgrim Station.  In addition, a Form 8-K dated
December 10, 1998, was filed announcing that BEC and Commonwealth Energy System
entered into an Agreement and Plan of Merger.

                                       72
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


Exhibit 2     Plan of Acquisition, Reorganization,
---------     ------------------------------------
              Arrangement, Liquidation or Succession
              --------------------------------------

Incorporated herein by reference:

      2.1    Agreement and Plan of Merger by and         2.1  1-14768
             among BEC Energy, Boston Energy                  Form 8-K
             Technology Group, Inc., Commonwealth             dated
             Energy System, COM/Energy Resources,             December 10,
             Inc. and BEC Newco, Inc., dated                  1998
             December 5, 1998


Exhibit 3     Articles of Incorporation and By-Laws
---------     -------------------------------------

Incorporated herein by reference:

      3.1    Restated Articles of Organization           3.1  1-2301
                                                              Form 10-Q
                                                              for the
                                                              quarter ended
                                                              June 30, 1994


      3.2    Boston Edison Company Bylaws                3.1  1-2301
             April 19, 1977, as amended                       Form 10-Q
             January 22, 1987, January 28, 1988,              for the
             May 24, 1988 and November 22, 1989               quarter ended
                                                              June 30, 1990


      3.3    BEC Energy Declaration of Trust           3.1.1  Registration on
                                                              Form S-4
                                                              (File No.
                                                              333-23439)


      3.4    BEC Energy Bylaws                         3.1.2  Registration on
                                                              Form S-4
                                                              (File No.
                                                              333-23439)


Exhibit 4     Instruments Defining the Rights of
---------     ----------------------------------
              Security Holders, Including Indentures
              --------------------------------------

Incorporated herein by reference:

      4.1    Medium-Term Notes Series A - Indenture      4.1  1-2301
             dated September 1, 1988, between                 Form 10-Q
             Boston Edison Company and Bank of                for the
             Montreal Trust Company                           quarter ended
                                                              September 30,
                                                              1988

                                       73
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


    4.1.1    First Supplemental Indenture                4.1   1-2301
             dated June 1, 1990 to                             Form 8-K
             Indenture dated September 1, 1988                 dated
             with Bank of Montreal Trust Company -             June 28, 1990
             9 7/8% debentures due June 1, 2020


    4.1.2    Indenture of Trust and Agreement among   4.1.26   1-2301
             the City of Boston, Massachusetts                 Form 10-K
             (acting by and through its Industrial             for the
             Development Financing Authority) and              year ended
             Harbor Electric Energy Company and                December 31,
             Shawmut Bank, N.A., as Trustee, dated             1991
             November 1, 1991


    4.1.3    Votes of the Pricing Committee of the    4.1.27   1-2301
             Board of Directors of Boston Edison               Form 10-K
             Company taken August 5, 1991 re                   for the
             9 3/8% debentures due August 15, 2021             year ended
                                                               December 31,
                                                               1991


    4.1.4    Revolving Credit Agreement dated         4.1.24   1-2301
             February 12, 1993                                 Form 10-K
                                                               for the
                                                               year ended
                                                               December 31,
                                                               1992


  4.1.4.1    First Amendment to Revolving Credit      4.1.10   1-2301
             Agreement dated May 19, 1995                      Form 10-K
                                                               for the
                                                               year ended
                                                               December 31,
                                                               1995


  4.1.4.2    Second Amendment to Revolving Credit    4.1.4.2  1-2301
             Agreement dated July 1, 1997                     Form 10-K
                                                              for the
                                                              year ended
                                                              December 31,
                                                              1997


    4.1.5    Votes of the Pricing Committee of the    4.1.25  1-2301
             Board of Directors of Boston Edison              Form 10-K
             Company taken September 10, 1992 re              for the
             8 1/4% debentures due September 15, 2022         year ended
                                                              December 31,
                                                              1992

                                       74
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


    4.1.6    Votes of the Pricing Committee of the    4.1.26  1-2301
             Board of Directors of Boston Edison              Form 10-K
             Company taken January 27, 1993 re                for the
             6.80% debentures due February 1, 2000            year ended
                                                              December 31,
                                                              1992


    4.1.7    Votes of the Pricing Committee of the    4.1.27  1-2301
             Board of Directors of Boston Edison              Form 10-K
             Company taken March 5,1993 re                    for the
             6.80% debentures due March 15, 2003,             year ended
             7.80% debentures due March 15, 2023              December 31,
                                                              1992


    4.1.8    Votes of the Pricing Committee of the    4.1.28  1-2301
             Board of Directors of Boston Edison              Form 10-K
             Company taken August 18, 1993 re                 for the
             6.05% debentures due August 15, 2000             year ended
                                                              December 31,
                                                              1993


    4.1.9    Votes of the Pricing Committee of the     4.1.9  1-2301
             Board of Directors of Boston Edison              Form 10-K
             Company taken May 10, 1995 re                    for the
             7.80% debentures due May 15, 2010                year ended
                                                              December 31,
                                                              1995


Management agrees to furnish to the Securities and Exchange Commission, upon
request, a copy of any agreements or instruments defining the rights of holders
of any long-term debt whose authorization does not exceed 10% of total assets.



                                                      Exhibit  SEC Docket
                                                      -------  ----------


Exhibit 10    Material Contracts
----------    ------------------

Incorporated herein by reference:

     10.1    Key Executive Benefit Plan               10.3.1  1-2301
             Standard Form of Agreement, May                  Form 10-K
             1986, with modifications                         for the
                                                              year ended
                                                              December 31,
                                                              1991

                                       75
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


     10.2    Executive Annual Incentive                 10.5  1-2301
             Compensation Plan                                Form 10-K
                                                              for the
                                                              year ended
                                                              December 31,
                                                              1988


   10.2.1    Supplemental Executive Retirement          10.1  1-2301
             Plan                                             Form 10-Q
                                                              for the
                                                              quarter ended
                                                              June 30, 1997


   10.2.2    1997 Stock Incentive Plan                  10.2  1-2301
                                                              Form 10-Q
                                                              for the
                                                              quarter ended
                                                              June 30, 1997


     10.3    Boston Edison Company Deferred            10.11  1-2301
             Fee Plan dated January 14, 1993                  Form 10-K
                                                              for the
                                                              year ended
                                                              December 31,
                                                              1992


     10.4    Deferred Compensation Trust               10.10  1-2301
             between Boston Edison Company                    Form 10-K
             and State Street Bank and                        for the
             Trust Company dated                              year ended
             February 2, 1993                                 December 31,
                                                              1992


   10.4.1    Amendment No. 1 to Deferred              10.5.1  1-2301
             Compensation Trust dated                         Form 10-K
             March 31, 1994                                   for the
                                                              year ended
                                                              December 31,
                                                              1994


     10.5    Boston Edison Company Deferred             10.9  1-2301
             Compensation Plan, Amendment and                 Form 10-K
             Restatement dated January 31, 1995               for the
                                                              year ended
                                                              December 31,
                                                              1994

                                       76
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


     10.6    Employment Agreement applicable to        10.10  1-2301
             Ronald A. Ledgett dated April 30, 1987           Form 10-K
                                                              for the
                                                              year ended
                                                              December 31,
                                                              1994


     10.7    Change in Control Agreement applicable     10.2  1-2301
             to Thomas J. May dated July 8, 1996              Form 10-Q
                                                              for the
                                                              quarter ended
                                                              June 30, 1996


     10.8    Form of Change in Control Agreement        10.3  1-2301
             applicable to Ronald A. Ledgett,                 Form 10-Q
             L. Carl Gustin, Douglas S. Horan,                for the
             James J. Judge and certain other                 quarter ended
             officers dated July 8, 1996                      June 30, 1996


     10.9    Boston Edison Company Restructuring       10.12  1-2301
             Settlement Agreement dated July 1997             Form 10-K
                                                              for the
                                                              year ended
                                                              December 31,
                                                              1997


    10.10    Boston Edison Company and Sithe            10.1  1-2301
             Energies, Inc. Purchase and Sale                 Form 10-Q
             and Transition Agreements dated                  for the
             December 10, 1997                                quarter ended
                                                              March 31, 1998


Filed herewith:

    10.11    Boston Edison Company Directors'
             Deferred Fee Plan Restatement
             effective October 1, 1998


    10.12    Boston Edison Company and Entergy
             Nuclear Generation Company Purchase
             and Sale Agreement dated November 18,
             1998


Exhibit 21    Subsidiaries of the Registrant
----------    ------------------------------

     21.1    Boston Edison Company (incorporated
             in Massachusetts), a wholly owned
             subsidiary of BEC Energy

                                       77
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------


     21.2    Boston Energy Technology Group, Inc.
             (incorporated in Massachusetts),
             a wholly owned subsidiary of BEC
             Energy


     21.3    Harbor Electric Energy Company
             (incorporated in Massachusetts),
             a wholly owned subsidiary of Boston
             Edison Company


Exhibit 23    Consent of Independent Accountants
----------    ----------------------------------

Filed herewith:

     23.1    Consent of Independent Accountants
             to incorporate by reference their
             opinion included with this Form
             10-K/A in the Form S-3 Registration
             Statement filed by BEC Energy on
             July 2, 1998 (File No. 33-59693);
             Form S-8 Registration Statements
             filed by BEC Energy on June 17,
             1998 (File Nos. 33-58457, 33-59662
             and 33-59682) and June 29, 1998
             (File No. 333-30975-99) 


Exhibit 27    Financial Data Schedule
----------    -----------------------

Filed herewith:

     27.1    Schedule UT


Exhibit 99    Additional Exhibits
----------    -------------------

Incorporated herein by reference:

     99.1    Settlement Agreement between Boston        28.1  1-2301
             Edison Company and Commonwealth                  Form 8-K
             Electric Company, Montaup Electric               dated
             Company and the Municipal                        December 21,
             Light Department of the Town of                  1989
             Reading, Massachusetts, dated
             January 5, 1990


     99.2    Settlement Agreement Between Boston        28.2  1-2301
             Edison Company and City of Holyoke               Form 10-Q
             Gas and Electric Department et. al.,             for the
             dated April 26, 1990                             quarter ended
                                                              March 31, 1990
 

                                       78
<PAGE>
 
                                                      Exhibit  SEC Docket
                                                      -------  ----------



     99.3    Information required by SEC Form                 1-2301
             11-K for certain employee benefit                Form 10-K/A
             plans for the years ended                        Amendments to
             December 31, 1997, 1996 and 1995                 Form 10-K for
                                                              the years ended
                                                              December 31,
                                                              1997, 1996 and
                                                              1995 dated
                                                              June 25,1998,
                                                              June 26, 1997
                                                              and June 27,
                                                              1996,
                                                              respectively

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<PAGE>
 
                                  SIGNATURES
                                  ----------


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

                                    BEC ENERGY



                            By:  /s/ Robert J. Weafer, Jr.
                                 --------------------------------------
                                    Robert J. Weafer, Jr.
                                    Vice President-Finance, Controller
                                    and Chief Accounting Officer



                            Date:  May 12, 1999

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<PAGE>
 
                   Report of Independent Accountants


To the Shareholders and Trustees of BEC Energy:


In our opinion, the accompanying consolidated financial statements listed in
Item 14(a) of this Form 10-K/A present fairly, in all material respects, the
consolidated financial position of BEC Energy and its subsidiaries at December
31, 1998 and 1997 and the consolidated results of their operations and their
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 BEC'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.



                                 PricewaterhouseCoopers LLP



Boston, Massachusetts
January 28, 1999

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