<PAGE>
1997 Annual Report

[FOLLOWING TEXT VERTICALLY PLACED TO LEFT OF COVER PHOTO]
New England Electric System

                         [COVER PHOTO]



































                                                             [NEES LOGO]

<PAGE>
On the Cover
Caretakers of our wires include
Thomas Boyle, Massachusetts
Electric crew leader.










[PHOTO OF NEES BUCKET TRUCK IN SNOWSTORM WITH
LINEMAN WORKING ON LINES]

















[SIX MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM PHOTO
THROUGH APRIL TO FOCUS ON WIRES TEXT]

JANUARY      FEBRUARY      MARCH     APRIL      MAY      JUNE



                    Focus on Wires Business

                An April storm knocked out power
         to more than 130,000 customers. Our line crews
         responded with speed and precision, restoring
               most of those customers to service
                        within 24 hours.


<PAGE>
[1997 IN GHOSTED PRINT ALONG RIGHT SIDE OF REPORT]

The events of 1997
transformed our company
and greatly increased the
security of your investment
in NEES. At the same time,
our employees kept their
focus on their first priorities:
keeping the lights on and
the revenues flowing.

                  [PHOTO OF GOVERNOR CELLUCCI
               SIGNING NEW LEGISLATION INTO LAW]






Generation Sales Agreement

We reached an agreement to sell
our fossil-fueled and hydroelectric generation
business, an action that will dramatically
reduce our stranded investment.







[SIX MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM
GENERATION SALES AGREEMENT TEXT THROUGH AUGUST
AND FROM PHOTO THROUGH NOVEMBER TO MASSACHUSETTS LAW TEXT]

JULY    AUGUST    SEPTEMBER     OCTOBER    NOVEMBER    DECEMBER



                         Massachusetts Law

                         New legislation in Massachusetts
[PHOTO OF POWER PLANT]   opened electricity wires to competitive
                         power suppliers while treating
                         utilities fairly.


<PAGE>
To Our Shareholders

  New England Electric System (NEES) celebrated its fiftieth
anniversary in 1997, amid events that both transformed our
company and greatly increased the security of your investment in
NEES. We have become one of the first utilities in the nation to
open our wires to competitive power suppliers and guarantee
savings to customers. We have done so while providing for
recovery of generating plant and power purchase commitments that
might otherwise be forfeited, or "stranded," when access is given
to our wires. Since these stranded investments could have
exceeded our total equity, their recovery has been our first
priority.

[PHOTO OF RICHARD P. SERGEL APPEARS HERE]
Richard P. Sergel, President and Chief Executive Officer

- We implemented the Rhode Island Utility Restructuring Act so
that on January 1, 1998, Rhode Island became the first state in
the nation where all customers can choose their power supplier,
just as they can choose their long-distance telephone carrier.
Customers in Rhode Island have also received rate decreases
averaging nearly 8 percent off of standard rates.

- We helped secure the passage of legislation in Massachusetts
that made it the second state in the U.S. to fully open
electricity wires to competitive power suppliers.

- We became the first utility in the country to reach an
agreement to sell its fossil-fueled and hydroelectric generation
business, an action that will halve our stranded investment and
increase the safety of our right to recover the remainder.

  We believe that this national leadership in dealing with the
onset of competition has served you well during a most difficult
period.

  1997 operating results
  Meanwhile, our employees have kept their focus on their first
priorities: keeping the lights on and the revenues flowing. Their
hard work produced our ninth consecutive year of solid financial
performance and a dramatic list of service and operating
improvements. Earnings per average common share in 1997 were
$3.39, compared with $3.22 in 1996. Return on common equity was
12.8 percent, which placed us in the top quarter of both our
region's and nation's electric utilities. Our average cost per
kilowatthour was the second lowest among major New England
utilities. In sum, 1997 was an excellent year for both
shareholders and customers.

[SIX MONTH EMPTY TIME LINE ACROSS PAGE]


<PAGE>
[FOLLOWING TEXT APPEARS AT BOTTOM OF PAGE]

  New England Electric System (NEES) is a public utility holding company
  headquartered in Westborough, Massachusetts. Its subsidiaries are engaged
  in the transmission, distribution, sale, and generation of electricity,
  and the marketing of energy commodities and services. The electricity
  delivery companies serve 1.3 million customers in Massachusetts, Rhode
  Island, and New Hampshire. Other business activities include independent
  transmission projects and telecommunications project management. NEES has
  entered into an agreement to sell its fossil-fueled and hydroelectric
  generation business.

  Vision and goals
  At our April 1997 annual shareholders meeting, we introduced
NEES 2000, a set of five business goals that are aimed at
preserving and enhancing your investment in our company. These
goals continue to drive the efforts of our management team and
our employees.

  The first goal is to get our stranded investment back, as this
is absolutely vital to our financial health, the security of your
investment, and NEES' constitutionally protected rights. In 1997,
we built on our past progress through regulatory orders in
Massachusetts and Rhode Island and at the Federal Energy
Regulatory Commission (FERC), and through the Massachusetts
Electric Utility Industry Restructuring Act signed into law in
November by Governor Paul Cellucci.

  The Massachusetts Act permits customers to choose their
electricity supplier beginning March 1, 1998. It opens our
distribution and transmission systems to competitive suppliers,
and calls for an immediate 10 percent reduction in electricity
rates, plus an additional 5 percent by September 1, 1999. Our
system does 75 percent of its electricity delivery business in
Massachusetts.

  As with the statute passed the previous year in Rhode Island,
the Massachusetts Act recognizes the right of our company and
other utilities to recover stranded costs. In spite of the
consensus that supported the Massachusetts legislation, certain
opponents initiated a referendum for its repeal which will appear
on the November 1998 ballot.

  Quick, effective implementation of the Rhode Island statute
and Massachusetts Act will be possible through settlements
approved by the FERC and supported by regulators in those two
states. The Rhode Island Public Utilities Commission and
Massachusetts Department of Telecommunications and Energy have
also approved our company's implementation plans.


<PAGE>
  We reached an agreement in February 1998 with New Hampshire
Governor Jeanne Shaheen, key state legislators, and several
consumer, business, and environmental groups on a plan to bring
choice of power supplier to Granite State Electric's 36,000
customers no later than July 1, 1998. The agreement, which
requires state and federal approvals, calls for 10 percent
savings to customers, additional savings after our generation
sale is completed, and recovery of our stranded costs.

                            [PHOTO OF JOAN T. BOK APPEARS HERE]
                            Joan T. Bok, Chairman of the Board

[TEXT IN SHADED BOX IN CENTER COLUMN LEFT OF JOAN BOK PHOTO]
In April 1998, Joan T. Bok will retire as chairman of the NEES
board, a position she has held with distinction since 1984. She
has provided wise counsel sparked by a keen intellect. Her many
contributions include co-authoring the original NEESPLAN, setting
NEES on its path of national leadership in resource planning. She
will remain a member of the board.

  Generation sale
  The second goal we put forth at our April 1997 annual meeting
was to get as much money as possible for our generating business.
Reaching a sales agreement required an immense undertaking by our
generation and administrative employees during an intense, six-
month stretch. Their effort was without precedent. No other U.S.
utility had sold its entire fossil-fueled and hydroelectric
generation fleet and operations.



[SIX MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM
DECEMBER TO GRAPH]
                                                     December


[GRAPH APPEARS HERE, FINANCIAL RESULTS]


<PAGE>
  USGen New England, Inc., a subsidiary of PG&E Corporation, was
the winning bidder with an offer of $1.59 billion, and, in
August, signed a purchase and sales agreement with our company.
The price was approximately 45 percent over the book value of the
generation being sold. We expect the sale to close later this
year, subject to receipt of regulatory approvals.

  We are delighted to report that the purchase price will
effectively recover our investments not only in our fossil and
hydro plants, but in nuclear plants as well. The proceeds will
reduce NEES' potential stranded costs by roughly 50 percent. This
in turn will reduce, by about half, the related transition charge
that customers will pay on their electric bills. We expect
average rate reductions to exceed 15 percent in both Rhode Island
and Massachusetts.

  In addition to reducing stranded costs, the sale will provide
NEES with a substantial amount of cash that will require
reinvestment. After paying taxes and other sale-related
transaction costs, retiring debt, and repurchasing up to five
million shares, that net amount will be approximately $500
million. This money will give us the flexibility to combine with
other energy delivery companies, increase our investments in
unregulated businesses, repurchase additional NEES shares, or
complete a combination of these actions. We are carefully
studying the options to determine the use of this money that will
contribute the most to shareholder value.

  While a financial success, the sale hastens the day in which
some of our most valued people - many with decades of experience
in NEES' generation activities - will leave for employment with
USGen or to seek opportunities with other firms. With additional
reductions through early retirements and severances during 1998,
we expect that our workforce for the reshaped NEES will be
significantly reduced.

  In September, Senior Vice President Jeffrey Tranen left NEES
to become president and chief executive officer of the California
Independent System Operator, which manages the electricity
transmission system in that state. We are pleased that Jeff's
talents have been recognized by others, and believe this will be
the case with many of the wonderful people who run the region's
best generation fleet.

  Meanwhile, our generation employees turned in a record year,
with only one lost-time accident and perfect environmental
compliance at all 18 power plants; the highest total energy
production on record from our Brayton Point and Salem Harbor coal
units; and, at Manchester Street Station, the best thermal
efficiency among New England's fossil-fueled plants.

[NEES YEAR 2000 LOGO APPEARS UNDER COLUMNS ONE AND TWO]


<PAGE>
[SIX-MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM NEES 2000
LOGO THROUGH APRIL TO NEES 2000 BUSINESS GOALS TO PHOTO ON NEXT
PAGE]

                              APRIL

[TEXT AND GOALS NUMBER 1 AND 2 ON BOTTOM QUARTER OF PAGE]

            Introduced in April 1997, the NEES 2000
     Business goals guide the day-to-day activities of our
                 management team and employees.

  1      Get our stranded investment back
  2      Get as much as possible for the generation business


[PHOTO OF MANCHESTER STREET STATION SPANNING TWO COLUMNS
APPEARS HERE]
Reviewing operations at Manchester Street Station in Providence
are USGen's Carl Cimino (top left) and New England Power's Bill
Freddo, plant manager.

  Wires business
  Our third goal is to run the best wires business in the
Northeast. In our region, storms provide the acid test of such
aspirations. Once again, our people passed with honors. A
snowstorm on April 1, 1997 dropped more than 25 inches of snow
throughout our service area and knocked out power to about
135,000 of our customers. Our crews worked day and night to
restore power to more than 100,000 of those customers within 24
hours. We matched our excellent service restoration record of
other recent major storms, and exceeded the restoration
performance of our neighboring utilities. Our customer service
staffs in Northborough, Mass. and Providence, R.I. responded to
more than 75,000 phone calls on outages and repair activities,
and our automated phone system handled an additional 72,000
messages.

  The low cost and reliability of our performance, during
emergencies and in day-to-day service, show that our wires
operation is already one of the best in our region. Technology is
enhancing the value of that business, and is helping our people
do their jobs with even greater efficiency. For example, we are
merging aerial photos and data from various departments to
produce a computer-based map of all of our equipment, including
poles, wires, and transformers. Having this information in one
place will help our engineers and crews respond more quickly to
customers' requests for new electrical service, information, or
repairs.
[EMPTY SIX-MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM PHOTO
TO NEES 2000 BUSINESS GOALS ON PREVIOUS PAGE]

[NEES GOALS NUMBER 3 THROUGH 5 ON BOTTOM QUARTER OF PAGE]

  3      Run the best wires business in the Northeast
  4      Increase the size of our energy delivery business
  5      Profit from growth in unregulated ventures

<PAGE>
  As a convenience to our customers, we have introduced an
interactive feature on our Internet web site that allows
customers to view their payment, billing, and energy usage
history, using their home or office computer.

  Our popular energy efficiency programs marked their tenth
anniversary in 1997. During the year, these programs helped more
than 200,000 customers use energy more efficiently and
contributed approximately seven cents per share to our bottom
line.

[PHOTO OF SYSTEM CONTROL CENTER IN WESTBOROUGH SPANNING TWO
COLUMNS APPEARS HERE]
The System Control Center in Westborough, Massachusetts is the
hub for dispatching power throughout the NEES companies' network
of transmission lines and substations

  Expansion
  Know-how, technology, customer focus... all are important
ingredients as we build the best wires business. But scale
matters, too, and our fourth goal is to increase the size of our
energy delivery business. Two years ago, we began serving
Nantucket Island's 9,700 customers by acquiring Nantucket
Electric Company. Now, with the industry restructuring effort
just about complete in two states and the generation sale process
coming to an end, we can turn more of our attention to mergers
and acquisitions, and are seeking the most promising
possibilities, both in electricity and natural gas. Our low-cost
position among electric utilities in the Northeast should prove
an important element in forging potential combinations and for
winning support from regulators, customers, and shareholders.
While the cash from the generation sale gives us important
capabilities for such expansion, we intend to use it
conservatively. An expansion is only worthwhile to us if we can
make it pay for you.

[EMPTY SIX-MONTH TIME LINE ACROSS PAGE - DOTTED LINE FROM SYSTEM
CONTROL CENTER PHOTO TO PHOTO OF JESSE LYONS]


[PHOTO OF JESSE LYON APPEARS HERE WITH FOLLOWING TEXT TO ITS
LEFT]

  The professionalism of our line workers, including Granite
State Electric's Jesse Lyons, was of great benefit to utilities in New
         Hampshire, Maine, Vermont, and Canada, where
          our people helped local crews restore power
       following a devastating ice storm in January 1998.


<PAGE>
  Building new businesses
  Our final NEES 2000 goal is to profit from growth in
unregulated ventures. We are making carefully considered
investments in ventures that are closely aligned with our core
abilities.

  One such opportunity is represented by our purchase in
December of Eastern Enterprises' 50 percent interest in our joint
venture, AllEnergy Marketing Company, L.L.C., which offers energy
commodities (electricity, gas, propane, oil) and related value-
added services to customers in New England, New Jersey, and New
York. With this purchase, AllEnergy became a wholly owned
subsidiary of NEES. We are committed to making AllEnergy a
regional leader in the emerging competitive energy marketplace.
We are optimistic that the decision to increase our ownership,
while costly in the short term, will yield value over the long
term.

  Our subsidiary NEES Global Transmission, Inc. has teamed up
with the Connecticut-based utility United Illuminating and
Swedish equipment manufacturer ABB Power Systems AB in a proposal
to build a cable under Long Island Sound. The cable would allow
the transfer of competitively priced energy between New England
and Long Island, New York.

  Our subsidiary NEES Communications, Inc. is exploring
opportunities in the telecommunications industry, building on our
successful experience with fiber optic cable projects in the
Providence, R.I., Westborough, Mass., Nantucket, Mass., and
Wilder, Vt., regions. NEES Communications' services include
engineering, constructing, owning, and leasing fiber optic cable.

[PHOTO OF CARMEN BERNAZAR APPEARS HERE]

           "The strength of our service to customers
       is our ability to understand their needs, provide
         reliable and accurate information, and go the
       extra mile to find solutions to their problems."
    Carmen Bernazar, Senior Customer Service Representative

[EMPTY SIX-MONTH TIME LINE ACROSS PAGE]

[JANUARY 1998 DOTTED LINE TO PHOTO ON PREVIOUS PAGE]

                           January 1998

<PAGE>
[PHOTO OF TIM BERTSCHMANN AND DAVID MCCAUGHEY SPANNING TWO
COLUMNS APPEARS HERE]
AllEnergy's Tim Bertschmann (left) and David McCaughey,
facilities manager for the Brooks Pharmacy chain, discuss gas
heating needs at the Pawcatuck, Connecticut location.

  Business opportunities are being created from our experience
in industry restructuring. We've gleaned important lessons from
our successful customer-choice pilot programs and our
constructive record of collaboration and negotiation in electric
industry restructuring. We have developed several marketable
products and services related to this expertise, and have been
engaged by utilities in a dozen states and in Alberta, Canada, to
assist them with their transition to a competitive electricity
industry.

  Commitment
  Although the restructuring of the electricity industry
provides new opportunities such as those just described, it will
reduce NEES earnings beginning in 1998. The reasons include
limits on return on equity for our generation and electricity
delivery businesses, and the eventual sale of the generation
business, historically our most profitable enterprise. These
measures were agreed to in order to assure recovery of our
stranded costs and a fair opportunity to compete and thrive in
the future. Our unregulated ventures will be under early pressure
to perform against formidable competition.

  NEES has consistently overcome challenges - from the oil
embargoes and inflation of the 1970s, to a severe recession in
the early 1990s - to provide competitive financial performance
for our shareholders. We are confident that, despite the new
challenges of a restructured industry, NEES will remain a solid
investment.

  One of the most compelling reasons for this confidence is that
the employees of the NEES companies have a vital self-interest in
performance for shareholders. Collectively, through various
investment programs, our employees are our single largest
shareholder, holding some 8 percent of all shares. From 12 to 46
percent of each employee's total pay (depending on position)
hinges on NEES meeting annual targets for financial performance.
We have agreements with labor unions that base part of union
employees' pay on the company's financial performance for
shareholders. Each executive has minimum shareholding
requirements. In short, we succeed only when we succeed for you.

[EMPTY SIX-MONTH TIME LINE ACROSS PAGE]

[FOLLOWING TEXT ON LOWER QUARTER OF PAGE DOTTED LINE TO PHOTO OF
CHRISTINE KEIGHER ON NEXT PAGE]

"AllEnergy offers customized energy solutions to help our customers
compete. We have the personnel, financial resources, and experience
  to offer the reliability and service our customers demand."
      Christine Keigher, Director of Marketing, AllEnergy


<PAGE>
  Executive changes
  In February 1998, John W. Rowe resigned his position as NEES
president and chief executive officer to become chairman,
president, and chief executive officer of Chicago-based Unicom
Corporation and its subsidiary Commonwealth Edison. In light of
Mr. Rowe's departure, the NEES board of directors in February
1998 approved changes to the management team. Richard P. Sergel,
senior vice president, was elected NEES president and chief
executive officer and a member of the board of directors
effective February 6, 1998, succeeding Mr. Rowe. Alfred D.
Houston, executive vice president, was elected to the board of
directors effective February 6, 1998. The board announced its
intention to elect Mr. Houston NEES chairman when Joan Bok
retires as chairman of the board in April 1998.

[PHOTO OF JOHN ROWE APPEARS HERE UNDER FIRST COLUMN]
John W. Rowe, former President and Chief Executive Officer of
NEES

  We thank those people who helped make 1997 an historic and
successful year: our employees in the generation business and
other areas of our company, for their steadfastness during a time
of change; John Rowe, for his bold leadership through the arduous
process of industry restructuring which positioned NEES well to
succeed in the future; our customers, for their business and for
their help in encouraging workable restructuring legislation that
will deliver the price and performance that are important to
them; and our regulators and government officials, particularly
the leaders of the state legislatures in Massachusetts and Rhode
Island, for their willingness to shape restructuring legislation
in which all stakeholders win.

  We believe that during the past few years our company has done
more than any utility in the region - and has few peers in the
nation - in preserving shareholder value in the midst of dramatic
industry change. We thank you, fellow shareholders, for
recognizing our efforts through your continued confidence in NEES
and the employees of our companies.

S/Joan T. Bok
Chairman of the Board

S/Richard P. Sergel
President and Chief Executive Officer

March 2, 1998

[EMPTY SIX-MONTH TIME LINE ACROSS PAGE]

[PHOTO OF CHRISTINE KEIGHER DOTTED LINE TO TEXT ON PREVIOUS PAGE
APPEARS ON BOTTOM OF PAGE]


<PAGE>
                        Financial Review

  Overview of Financial Results
  Earnings were $3.39 per share in 1997 compared with $3.22 and
$3.15 per share in 1996 and 1995, respectively. The return on
common equity was 12.8 percent in 1997, 12.6 percent in 1996, and
12.8 percent in 1995. The market price of New England Electric
System (NEES) common shares was 42 3/4 per share at the end of
1997 compared with 34 7/8 per share and 39 5/8 per share at the
end of 1996 and 1995, respectively.

  The increase in 1997 earnings reflects increased revenues from
a 2.0 percent increase in kilowatthour (kWh) deliveries as well
as rate increases and reversals of prior period refund accruals.
Also contributing to the higher earnings was a decrease in the
nonfuel component of purchased power expense. Partially
offsetting the higher earnings were increased operation and
maintenance expenses, increased expenses associated with NEES'
unregulated ventures, and costs incurred to repurchase a portion
of the preferred stock of NEES subsidiaries.

  The increase in 1996 earnings reflects retail rate increases
and higher kWh deliveries as well as decreased purchased power
costs, partially offset by a decreased allowance for funds used
during construction (AFDC) and increased property tax expense.

[GRAPH APPEARS HERE, EARNINGS PER AVERAGE SHARE ($)]

  Outlook
  Starting in 1998, NEES earnings will be reduced by the
restructuring of the electric utility business in the states
served by the NEES companies. During the first quarter of 1998,
customers in Massachusetts and Rhode Island, representing
approximately 95 percent of the NEES companies' revenues from the
sale of electricity, will have the ability to choose their power
supplier. Upon the introduction of consumer choice, settlement
agreements related to recovery of stranded costs will limit the
return on equity earned on the NEES companies' generating
business to approximately 9.4 percent, before mitigation
incentives, which is significantly lower than earned by the
generating business in recent years. (The settlement agreements
also will cap earnings for the majority of NEES' distribution
business at 11.75 percent.) Following completion of the sale of
the NEES companies' nonnuclear generating business, which is
discussed in more detail below, NEES earnings will be affected by
the return on the reinvestment of the sale proceeds, whether
through retirement of debt, the repurchase of NEES shares,
investments in new ventures, or otherwise. This reinvestment
return is expected, at least in the near term, to be considerably
less than the return historically earned in the generating
business.

  This report contains statements that may be considered forward
looking under the securities laws. Actual results may differ
materially for the reasons discussed in this Financial Review.


<PAGE>
  Industry Restructuring
  Historically, electric utilities have provided their customers
bundled electric service within exclusive franchise service
territories. As the result of a number of trends, including a
disparity in electric rates among regions of the country and new
regulations and legislation intended to foster competition,
distribution customers are being allowed to choose their power
supplier, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems.
Because of legislation enacted in the states served by the NEES
companies, most customers served by the NEES companies will have
the ability to choose their power supplier during the first
quarter of 1998.

  When customers are allowed to choose their power supplier,
utilities face the risk that market prices may not be sufficient
to recover the costs of the commitments incurred to supply
customers under a regulated structure. The amounts by which such
costs exceed market prices are commonly referred to as "stranded
costs." As described below, the NEES companies have reached
settlement agreements with parties representing all of their
distribution customers. In each case, these settlements provide
for recovery of stranded costs. Agreements have not yet been
reached with certain wholesale customers that represent less than
2 percent of the NEES companies' stranded cost exposure; however,
these customers continue to pay their share of NEES' generation
and transmission subsidiary's, New England Power Company (NEP),
costs through their wholesale rates.

  Massachusetts Legislation and Settlement Agreement
  In November 1997, legislation was enacted which provides
customers of Massachusetts' investor-owned utilities with the
ability to choose their power supplier beginning on March 1,
1998. The legislation requires electric companies to provide
customers who do not choose a power supplier with a transition
rate (or "standard offer generation service") which results in a
10 percent rate reduction, with the discount increasing to 15
percent on or before September 1, 1999. The legislation also
provides a mechanism for the recovery of stranded costs resulting
from the introduction of customer choice.

  In December 1997, the Massachusetts Department of
Telecommunications and Energy (MDTE) found that a settlement
agreement (the Massachusetts Settlement) previously reached among
the NEES companies' Massachusetts subsidiaries (NEP,
Massachusetts Electric Company (Massachusetts Electric), and
Nantucket Electric Company (Nantucket Electric)) and various
governmental agencies and other interested parties substantially
complies with or is consistent with the Massachusetts statute.
The Massachusetts Settlement was also conditionally approved by
the Federal Energy Regulatory Commission (FERC) in November 1997,
subject to a compliance filing to clarify the impact of the
settlement on nonsettling parties.


<PAGE>
  In accordance with the Massachusetts Settlement, NEP's
wholesale contracts with Massachusetts Electric and Nantucket
Electric have been amended effective March 1, 1998. The
Massachusetts Settlement provides that Massachusetts Electric's
and Nantucket Electric's share of NEP's stranded costs will be
recovered from distribution customers through a transition access
charge, which will be collected by these distribution companies.
Under the Massachusetts Settlement, the recovery of NEP's
stranded costs is divided into several categories. Unrecovered
costs associated with generating plants and regulatory assets
would be recovered over 12 years and would earn a return on
equity of 9.4 percent. The above-market component of purchased
power contracts and nuclear decommissioning costs would be
recovered as incurred over the life of those obligations, a
period expected to extend beyond 12 years. Initially, the
transition access charge would be set at 2.8 cents per kWh and
would be reduced upon completion of the sale of NEP's generating
business, as described below. As the transition access charge
declines, NEP would earn incentives based on successful
mitigation of its stranded costs. These incentives would
supplement NEP's return on equity.

  In addition to addressing customer choice and the recovery of
stranded costs, the Massachusetts Settlement also required the
NEES companies to divest their nonnuclear generating business. In
August 1997, NEP and NEES' Rhode Island subsidiary, The
Narragansett Electric Company (Narragansett Electric), entered
into an agreement to sell substantially all of their nonnuclear
generating business to USGen New England, Inc. (USGen), an
indirect wholly owned subsidiary of PG&E Corporation (PG&E). See
"Divestiture of Generating Business" below. The net proceeds from
the sale of the nonnuclear generating business to USGen will be
used to reduce the transition access charge from 2.8 cents per
kWh to approximately 1.5 cents per kWh. In addition, the FERC
accepted the NEES companies' proposal in conjunction with their
divestiture filing that the recovery of the remaining above-
market nuclear generating plant investment and regulatory assets
be completed by the end of the year 2000.

  A referendum question which asks voters to repeal the
Massachusetts statute is expected to be on the ballot in November
1998. The NEES companies are unable to predict the outcome. While
by itself, repeal of the statute is not expected to materially
impair the effectiveness of the previously approved Massachusetts
Settlement, the potential exists that following repeal, there
could be legislative or regulatory actions which could be
materially adverse to the NEES companies.

[GRAPH APPEARS HERE, DIVIDENDS DECLARED PER SHARE/ANNUAL
RATE ($)]


<PAGE>
  Rhode Island Legislation and Settlement Agreement
  In August 1996, the state of Rhode Island enacted legislation
that allows customers in that state the opportunity to choose
their power supplier. Under the Rhode Island statute, state
accounts, certain new customers, and the largest manufacturing
customers were able to choose their power supplier beginning on
July 1, 1997. The balance of Rhode Island customers gained the
ability to choose their power supplier on January 1, 1998. The
Rhode Island statute also provided utilities with the ability to
recover stranded costs.

  In November 1997, the FERC conditionally approved a settlement
agreement (the Rhode Island Settlement) among NEP, Narragansett
Electric, the Rhode Island Public Utilities Commission and the
Rhode Island Division of Public Utilities and Carriers to
implement the stranded cost recovery provisions of the Rhode
Island statute, subject to a compliance filing to clarify the
impact of the settlement on nonsettling parties. The terms of the
Rhode Island Settlement are substantially the same as the
Massachusetts Settlement.

[GRAPH APPEARS HERE, DIVESTITURE REDUCES NEES' STRANDED COSTS]

  New Hampshire Legislation and Settlement Agreement
  On February 3, 1998, NEES' New Hampshire subsidiary, Granite
State Electric Company (Granite State Electric), and NEP reached
a comprehensive settlement agreement with the Governor's office
of the State of New Hampshire and a number of other interested
parties on a plan to provide choice of power supplier to its
customers by no later than July 1, 1998. This settlement
agreement was reached in response to a previously enacted New
Hampshire statute which requires customer choice of power
supplier. The principle terms of the New Hampshire settlement
agreement, which require approval by state and federal
regulators, are substantially similar to the Massachusetts
Settlement and Rhode Island Settlement, including rate reductions
for customers and the ability to recover stranded costs.

  Divestiture of Generating Business
  As described above, in August 1997, NEP and Narragansett
Electric (collectively, the Sellers) reached an agreement to sell
their nonnuclear generating business to USGen. The nonnuclear
generating business includes three fossil-fueled and 15
hydroelectric generating stations, totaling approximately 4,000
megawatts (MW) of capacity, as well as NEES' 100 percent interest
in Narragansett Energy Resources Company (NERC), a 20 percent
general partner in the Ocean State Power project, all of which
has a book value of $1.1 billion. USGen will pay the Sellers
$1.59 billion in cash, of which $225 million will be contingent
upon the introduction of customer choice of power supplier in
Massachusetts. Based on the enactment of the Massachusetts
statute, the NEES companies believe that the conditions for
payment of the full purchase price have been met. USGen will also
reimburse the NEES companies for $85 million of costs associated
with early retirement and special severance programs for

<PAGE>
employees affected by industry restructuring. USGen will assume
responsibility for environmental conditions at the Sellers'
nonnuclear generating stations. USGen will also assume the
Sellers' obligations under long-term fuel and fuel transportation
contracts and certain collective bargaining agreements.

  In addition to the purchase of the nonnuclear generating
stations, USGen will purchase NEP's entitlement to approximately
1,100 MW of power procured under long-term contracts. NEP will
make a monthly fixed contribution towards the above-market cost
of the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.

  The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale on
various grounds, including allegations that following the sale,
USGen would be able to exercise unlawful levels of market power.
On February 25, 1998, the FERC issued an order that rejected the
market power allegations, approved the sale, and conditionally
approved most supporting filings. While the timing of receipt of
final regulatory approvals is uncertain, receipt of all approvals
is unlikely before mid-1998. Closing is contingent upon all
regulatory approvals being obtained by February 1999.

  In order to meet the terms of NEP's mortgage indenture, NEP
will be required, prior to the consummation of the sale, to
either defease or call approximately $278 million of its mortgage
bonds. Any defeasance of bonds would be by deposit of cash
representing principal and interest to the maturity date, or
interest, principal, and general redemption premium to an earlier
redemption date. In addition, NEP will retire approximately $372
million of mortgage bonds securing the issuance of a like amount
of pollution control revenue bonds (PCRBs) by various public
agencies. However, NEP expects that substantially all of the
underlying PCRBs will remain outstanding as unsecured obligations
of NEP. In addition, the long-term debt of NERC will be retired
prior to the closing.

  As part of the divestiture plan, in February 1998, New England
Energy Incorporated (NEEI) (a wholly owned subsidiary of NEES)
sold its oil and gas properties for approximately $50 million.
NEEI's loss on the sale of approximately $120 million, before
tax, has been reimbursed by NEP.  See the "Liquidity and Capital
Resources" section of Financial Review for information on NEEI
debt retirements.

  At the divestiture date, any gain or loss from the divestiture
of nonnuclear generating assets and oil and gas assets will be
recorded as a regulatory asset or liability to be recovered as
part of NEP's stranded costs, through the ongoing transition
access charge, consistent with the settlement agreements. NEP may
be required to record a liability for the monthly fixed
contribution towards the above-market cost of purchased power. In
such an event, NEP would also record a regulatory asset
consistent with the settlement agreements.

<PAGE>
  In addition, NEP will endeavor to sell, or otherwise transfer,
its minority interest in three nuclear power plants and a 60 MW
interest in a fossil-fueled generating station in Maine to
nonaffiliates. Until such time as the nuclear interests are
divested, NEP will share with customers 80 percent of the
revenues and operating costs related to the units, with
shareholders retaining the balance. In the event that NEP
determines that it has an impairment of its nuclear plant
balances 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 (FAS 121), it will record any
such impairment as a regulatory asset.

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

[GRAPH APPEARS HERE, DIVESTITURE REDUCES NEES' TRANSITION ACCESS
CHARGE]

  The Massachusetts Settlement also eliminated Massachusetts
Electric's and Nantucket Electric's purchased power cost
adjustment (PPCA) mechanisms as of July 31, 1996. These
mechanisms allowed Massachusetts Electric and Nantucket Electric
to recover purchased power rate changes from NEP and the effects
of NEP's seasonal rates. The Massachusetts Settlement required
that Massachusetts Electric's net $18 million PPCA refund
liability balance at July 31, 1996 be transferred on its books to
establish a storm contingency fund account of $3 million
initially, with the remainder applied to reduce regulatory assets
for hazardous waste costs.

  Under the Rhode Island statute, Narragansett Electric
increased distribution rates by approximately $11 million in 1997
and another $7 million in 1998. The statute also provides that
Narragansett Electric may request increased distribution rates
which would take effect no earlier than 1999.


<PAGE>
  Workforce Reduction
  The NEES companies expect to implement substantial workforce
reductions beginning in 1998 as a result of industry
restructuring and the sale of the nonnuclear generating business.
The NEES companies are in the process of offering early
retirement programs to their union and non-union employees,
contingent upon the closing of the sale of the nonnuclear
generating business to USGen. In addition, the NEES companies
intend to offer enhanced severance benefits to affected
employees. As previously described, the costs of the early
retirement and severance programs are expected to be
substantially recovered from the proceeds of the sale of the
nonnuclear generating business. Since the early retirement
program is contingent upon the divestiture, its cost will not be
accrued until that time.

[GRAPH APPEARS HERE, ANTICIPATED USE OF DIVESTITURE PROCEEDS]

  Risk Factors
  While the NEES companies believe that the previously described
settlements and legislation and the sale agreement with USGen and
other developments constitute substantial progress in reducing
the impacts associated with industry restructuring, significant
risks remain. These include, but are not limited to: (i) the
potential that ultimately the settlements will not be implemented
in the manner anticipated by NEES, (ii) the possibility that a
voter referendum in November 1998 could overturn the
Massachusetts legislation, followed by materially adverse
legislative or regulatory actions, (iii) the possibility of
federal legislation that would increase the risks to shareholders
above those contained in the settlements and the Massachusetts
and Rhode Island statutes, (iv) the potential for adverse
stranded cost recovery decisions involving wholesale customers
with whom settlements have not yet been reached, and (v) the
failure to complete the sale of the nonnuclear generating
business to USGen.

  Accounting Implications
  Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates. At December 31, 1997, the NEES companies had approximately
$600 million in regulatory assets in compliance with FAS 71, of
which approximately $60 million relate to the transmission and
distribution business.


<PAGE>
  In response to concerns expressed by the staff of the
Securities and Exchange Commission, the Emerging Issues Task
Force (EITF) of the Financial Accounting Standards Board took
under consideration how FAS 71 should be applied in light of
recent changes within the regulated utility industry. In July
1997, the EITF concluded that a utility whose ongoing generation
operations would not permit the application of FAS 71, but had
otherwise received approval to recover stranded costs through
regulated transmission and distribution rates, would be permitted
to continue to apply FAS 71 to the recovery of the stranded
costs.

  The restructuring settlements and statutes each provide for
recovery of stranded costs of generating assets and oil and gas
related assets (including regulatory assets) not recoverable from
the proceeds of the divestiture of NEP's generating business. The
cost of these assets would be recovered as part of a cost-based
transition access charge imposed on all distribution customers.
Additionally, FERC Order No. 888 enables transmission companies
to recover their specific costs of providing transmission
service. Therefore, after the proposed divestiture, substantially
all of NEP's business, including the recovery of its stranded
costs, would remain under cost-based rate regulation. NEES
further believes the restructuring settlements and statutes will
enable the NEES distribution companies to recover through rates
their specific costs of providing ongoing distribution services.
NEES believes these factors and the EITF conclusion will allow
its principal utility subsidiaries to continue to apply FAS 71.
As a result of the FERC approval of the restructuring settlements
in November 1997, NEP was required to cease to apply FAS 71 to 20
percent of its ongoing nuclear operations, as described under
"Divestiture of Generation Business," the impact of which is
expected to be immaterial.

  Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations. In addition, write-downs of
plant assets under FAS 121 could be required, including a write-
off of any gain or loss from the divestiture of the generating
business.

  Operating Revenue
  Operating revenue increased $152 million in 1997 and reflects
higher kWh deliveries, rate increases, increased revenues related
to rate adjustment mechanisms, and increased fuel revenues.

  In 1997, kWh deliveries to ultimate customers increased 2.0
percent, reflecting the effects of an improving regional economy.

  Rate increases include a Narragansett Electric $11 million
increase in distribution rates that became effective in January
1997, and a transmission rate increase that went into effect in
mid-1996.


<PAGE>
  Rate adjustment mechanisms referred to above include
Massachusetts Electric's and Nantucket Electric's PPCA
mechanisms, which, upon approval of the Massachusetts Settlement
in November 1997, eliminated the mechanisms as of July 31, 1996.
Pending final approval of the settlement, Massachusetts Electric
and Nantucket Electric had accrued refund reserves of $9 million
for the last five months of 1996 and an additional $9 million in
the first nine months of 1997. Upon final approval of the
settlement, these refund reserves were reversed in the fourth
quarter of 1997, thereby increasing revenue. Massachusetts
Electric also accrued refund reserves of $17 million during the
first seven months of 1996, which were part of the net $18
million PPCA balance at July 31, 1996 discussed in "Impact of
Restructuring on Distribution Business."

[GRAPH APPEARS HERE, 1997 DISTRIBUTION OF REVENUE (%)]

  Operating revenue increased $79 million in 1996 and reflected
growth in kWh deliveries and Massachusetts Electric and
Narragansett Electric base rate increases in the fourth quarter
of 1995. These increases were partially offset by decreases in
revenues under rate adjustment mechanisms due to the accrued
refund reserves booked in Massachusetts Electric related to the
PPCA mechanism as discussed above.

  KWh deliveries to ultimate customers increased 1.7 percent in
1996. The increase was primarily due to an improving regional
economy and the acquisition of Nantucket Electric, partially
offset by the effects of milder weather in the last half of 1996.

  The distribution companies (Massachusetts Electric, Nantucket
Electric, Narragansett Electric, and Granite State Electric)
received approval from their respective regulatory agencies to
recover demand-side management (DSM) program expenditures in
rates on a current basis through 1997. These expenditures were
$63 million, $59 million, and $64 million in 1997, 1996, and
1995, respectively. Narragansett Electric and Granite State
Electric have received approvals from their respective state
regulatory agencies to recover substantially all of their 1998
DSM program expenditures. The Massachusetts Settlement and
statute provide for recovery of DSM-related costs. Massachusetts
Electric and Nantucket Electric have filed DSM program
expenditure recovery plans with the MDTE for the period 1998
through 2002, and are currently awaiting MDTE approval. Since
1990, the distribution companies have been allowed to earn
incentives based on the results of their DSM programs and have
recorded before-tax incentives of $7.6 million, $6.0 million, and
$5.7 million in 1997, 1996, and 1995, respectively.

[GRAPH APPEARS HERE, GROWTH IN KILOWATTHOUR DELIVERIES TO
ULTIMATE CUSTOMERS (%)]


<PAGE>
  Operating Expenses
  Operating expenses increased $133 million in 1997. This
increase reflects increased fuel costs, including the fuel
component of purchased power expense, and increased operation and
maintenance expenses, partially offset by decreased depreciation
and amortization expense. The increase in the fuel component of
purchased power expense was partially offset by a reduction in
the nonfuel component.

  Fuel costs, including the fuel component of purchased power
expense, increased in 1997 primarily due to increased wholesale
sales to other utilities and increased replacement power costs
due to the reduced generation from partially owned nuclear units.
See the "Nuclear Units" section.

  In 1997, the increase in operation and maintenance expenses
reflects increased costs of partially owned nuclear plants,
transmission wheeling costs, start-up costs associated with the
new regional transmission control organization, increased
distribution system related costs, and the NEES companies' share
of costs associated with the restoration to service of previously
idled generating facilities throughout New England, in response
to a tightening regional power supply. The increase also reflects
increased general and administrative costs, including the
accelerated amortization, in accordance with a 1995 NEP rate
agreement, of previously deferred costs associated with
postretirement benefits other than pensions (PBOPs), as discussed
below.

  The decrease in the nonfuel component of purchased power
expense, which amounted to $6 million in 1997, reflects reduced
charges from the Connecticut Yankee nuclear power plant which was
permanently shut down in late 1996 and the expiration of certain
purchased power contracts, partially offset by increased charges
from the Maine Yankee nuclear power plant which was permanently
shut down in mid-1997.

  The decrease in depreciation and amortization expense reflects
the completion of the amortization of NEP's pre-1988 investment
in the Seabrook 1 nuclear unit and NEP's investment in the
canceled Seabrook 2 nuclear unit. In accordance with a FERC 1995
settlement agreement, upon completion of the amortization of
Seabrook 1 and Seabrook 2, NEP agreed to accelerate its
amortization of previously deferred costs associated with PBOPs.
Upon completion of the PBOP amortization, which occurred in July
1997, NEP was required to accelerate its depreciation of its
investment in the Millstone 3 nuclear unit. This accelerated
depreciation is recorded as a regulatory liability.

  Total operating expenses increased $54 million in 1996
compared with 1995, reflecting increased fuel costs and increased
taxes, partially offset by decreased maintenance expense, lower
purchased power costs, and decreased depreciation and
amortization expense.


<PAGE>
  Fuel costs increased in 1996, reflecting increased generation
due to growth in sales to ultimate customers and other utilities
and fixed pipeline demand charges related to the Manchester
Street plant that had been partially deferred until the
completion of the plant in the second half of 1995.

  The nonfuel component of purchased power costs decreased in
1996 by $28 million as a result of the expiration of certain
purchased power contracts and higher 1995 costs related to NEP's
share of costs for repairs at the Maine Yankee nuclear power
plant.

  The 1996 decrease in maintenance expense reflected reduced
thermal and hydro generating plant overhaul activity, partially
offset by costs to correct deficiencies at Millstone 3.

  Depreciation and amortization expense decreased in 1996,
reflecting a decrease in oil and gas amortization expense as well
as the completion in 1995 of the amortization of a portion of
Seabrook 1 costs and Salem Harbor coal conversion costs,
partially offset by increased depreciation of other plant assets,
including the Manchester Street plant.

  Taxes other than income taxes increased in 1996 primarily as a
result of increased taxes on the Manchester Street plant.

  Other Income
  The decrease in other income in 1997 reflects expenses
associated with NEES' unregulated ventures. These costs are
expected to be higher in 1998 due to NEES' increased involvement
in such unregulated ventures.

  In the fourth quarter of 1997, AllEnergy Marketing Company,
L.L.C. (AllEnergy) became a wholly owned indirect subsidiary of
NEES. NEES previously owned a 50 percent interest. AllEnergy is
an energy marketing company which offers energy commodities
(electricity, gas, propane, and oil) and related value-added
services to customers in the emerging competitive energy markets
in the Northeast. The results of AllEnergy's operations are
expected to negatively impact NEES' earnings in 1998.

  Allowance for Funds Used During Construction (AFDC)
  The decrease in AFDC in 1996 is due to the completion of the
Manchester Street plant repowering project.

[GRAPH APPEARS HERE, CUSTOMERS SERVED PER EMPLOYEE]

  Nuclear Units
  Nuclear Units Permanently Shut Down
  Three of the four regional nuclear generating companies in
which NEP has a minority interest own nuclear generating units
which have been permanently shut down. These three units are as
follows:


<PAGE>
<TABLE>
<CAPTION>
                                                               Future
                                                              Estimated
                                 NEP's                        Billings
                              Investment         Date          To NEP
Unit                         %  $(millions)     Retired      $(millions)
--------------------------------------------------------------
<S>                         <C>                     <C>          <C>            <C>
Yankee Atomic                30                       7     Feb 1992             44
Connecticut Yankee           15                      17     Dec 1996             92
Maine Yankee                 20                      16     Aug 1997            164

</TABLE>

  In the case of each of these units, NEP has recorded an
estimate of the total future payment obligation as a liability
and an offsetting regulatory asset, reflecting estimated future
billings from the companies. In a 1993 decision, the FERC allowed
Yankee Atomic to recover its undepreciated investment in the
plant as well as unfunded nuclear decommissioning costs and other
costs. Connecticut Yankee and Maine Yankee have both filed
similar requests with the FERC. Several parties have intervened
in opposition to both filings. NEP's stranded cost settlements
allow NEP to recover all costs that the FERC allows the Yankee
companies to bill to NEP.

  In October 1997, the Citizen's Awareness Network and Nuclear
Information and Resource Service filed a petition with the
Nuclear Regulatory Commission (NRC) that would require formal NRC
approval of a decommissioning plan for the Connecticut Yankee and
Maine Yankee plants. In 1998, the petitioners indicated their
intention to file a request with the NRC designed to overturn a
current NRC rule on decommissioning. NEP cannot predict what
impact, if any, these activities will have on the cost of
decommissioning the plants.

[GRAPH APPEARS HERE, NEES' RETURN ON COMMON EQUITY (%)]

  At Maine Yankee, the NRC has identified numerous apparent
violations of its regulations, which may result in the assessment
of significant civil penalties.

  In the 1970s, NEP and several other shareholders (Sponsors) of
Maine Yankee entered into 27 contracts (Secondary Purchase
Agreements) under which they sold portions of their entitlement
to Maine Yankee power output through 2002 to various entities,
primarily municipal and cooperative systems in New England
(Secondary Purchasers). Virtually all of the Secondary Purchasers
have ceased making payments under the Secondary Purchase
Agreements and have demanded arbitration, claiming that such
agreements excuse further payments upon plant shutdown. NEP has
notified the Secondary Purchasers that the shutdown does not
relieve them of their obligation to make payments under the
Secondary Purchase Agreements and that they are in default of
such agreements. NEP has asked the FERC to enforce NEP's rights

<PAGE>
under the agreements. In the event that no further payments are
forthcoming from Secondary Purchasers, NEP, as a primary obligor
to Maine Yankee, would be required to pay an additional $9
million of future shutdown costs. These costs are not included in
the $164 million estimate disclosed in the table above. Shutdown
costs are recoverable from customers under the stranded cost
settlements.

  A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.

  Operating Nuclear Units
  NEP has minority interests in three other nuclear generating
units, Vermont Yankee, Millstone 3, and Seabrook 1. In October
1996, the NRC issued letters to operators of nuclear power plants
requiring them to document that the plants are operated and
maintained within their design and licensing bases, and that any
deviations are reconciled in a timely manner. The Seabrook 1 and
Vermont Yankee nuclear power plants responded to the NRC letters
in February 1997. Millstone 3 is currently shut down and has been
placed on the NRC "Watch List," signifying that its safety
performance exhibits sufficient weakness to warrant increased NRC
attention. Millstone 3 may not restart without NRC approval.

  Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. NEP performs periodic economic viability reviews of
operating nuclear units in which it holds ownership interests.

  Millstone 3
  In April 1996, the NRC ordered Millstone 3, which has
experienced numerous technical and nontechnical problems, to
remain shut down pending verification that the unit's operations
are in accordance with NRC regulations and the unit's operating
license. Millstone 3 is operated by a subsidiary of Northeast
Utilities (NU). NEP is not an owner of the Millstone 1 and 2
nuclear generating units, which are also shut down under NRC
orders.

  A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective actions taken at the unit,
an NRC assessment concluding a safety conscious work environment
exists, public meetings, and a vote of the NRC Commissioners. NEP
cannot predict when Millstone 3 will be allowed by the NRC to
restart, but believes restart of the unit is unlikely prior to
the summer of 1998.


<PAGE>
  Since April 1996, NEP has incurred an estimated $35 million in
incremental replacement power costs, which it has been recovering
from customers through its fuel clause. During the outage, NEP is
incurring incremental replacement power costs of approximately $2
million per month.

  Several criminal investigations related to Millstone 3 are
ongoing. In December 1997, the NRC assessed civil penalties
totaling $2.1 million for numerous violations at the three
Millstone units. NEP's share of this fine was less than $100,000.
The Connecticut Department of Environmental Protection and
Connecticut Attorney General have filed suit against NU for
alleged wastewater discharge violations at the Millstone units,
which may result in the assessment of substantial civil
penalties.

  In August 1997, NEP filed suit against NU in Massachusetts
Superior Court for damages resulting from the tortious conduct of
NU relating to Millstone 3. NEP is seeking compensation for the
losses it has suffered, including the costs of lost power and
costs necessary to assure that Millstone 3 can safely return to
operation. NEP also seeks punitive damages. NU has filed for
dismissal of the suit and sought to consolidate it with suits
filed by other joint owners in Massachusetts Superior Court.

  NEP also sent a demand for arbitration to Connecticut Light &
Power Company and Western Massachusetts Electric Company, both
subsidiaries of NU, seeking damages resulting from their breach
of obligations under an agreement with NEP and others regarding
the operation and ownership of Millstone 3.

  Brayton Point
  In October 1996, the Environmental Protection Agency (EPA)
announced it was beginning a process to determine whether to
modify or revoke and reissue NEP's water discharge permit for its
Brayton Point 1,576 MW power plant. This action came two years
before the permit expiration date. The EPA stated it took this
step in response to a request from the Rhode Island Department of
Environmental Management (RIDEM). A RIDEM report asserted a
statistical correlation between the decline in the fish
population in Mount Hope Bay and a change in operations at
Brayton Point that occurred in the mid-1980s.

  In April 1997, NEP signed a memorandum of agreement negotiated
with the various federal and state environmental agencies under
which NEP will voluntarily operate under more stringent
conditions than under its existing permit. The agreement was in
lieu of any immediate action on the permit, and will remain in
effect until a renewal permit is issued. On January 16, 1998, NEP
applied for a new water discharge permit with both the EPA and
the Massachusetts Department of Environmental Protection. NEP
cannot predict at this time what permit changes will be required
or the impact on Brayton Point's operations and economics.
However, permit changes may substantially impact the plant's
capacity and ability to produce energy and/or require substantial
capital expenditures to construct equipment to address the
concerns raised by the environmental agencies.

<PAGE>
  Hazardous Waste
  The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The most prevalent types of hazardous
waste sites with which NEES and its subsidiaries have been
associated are manufactured gas locations. (Until the early
1970s, NEES was a combined electric and gas holding company
system.) NEES is aware of approximately 40 such manufactured gas
locations, including 10 for which the NEES companies have been
identified by either federal or state environmental regulatory
agencies as potentially responsible parties, mostly located in
Massachusetts. NEES has reported the existence of all
manufactured gas locations of which it is aware to state
environmental regulatory agencies. NEES is engaged in various
phases of investigation and remediation work at approximately 20
of the manufactured gas locations. NEES and its subsidiaries are
currently aware of other possible hazardous waste sites, and may
in the future become aware of additional sites, that they may be
held responsible for remediating.

  In 1993, the Massachusetts Department of Public Utilities
approved a settlement agreement that provides for rate recovery
of remediation costs of former manufactured gas sites and certain
other hazardous waste sites in Massachusetts. A more detailed
discussion of this settlement agreement and of potential
hazardous waste liabilities is contained in Note D-4 of the Notes
to the Financial Statements. Predicting the potential costs to
investigate and remediate hazardous waste sites continues to be
difficult. At December 31, 1997, NEES had total reserves of $44
million. NEES believes that hazardous waste liabilities for all
sites of which it is aware, and which are not covered by a rate
agreement, are not material to its financial position.

  Year 2000 Computer Issues
  In the next two years, most large companies will face a
potentially serious information systems (computer) problem
because most software applications and operational programs
written in the past will not properly recognize calendar dates
beginning in the year 2000. This could force computers to either
shut down or lead to incorrect calculations. The NEES companies
began the process of identifying the changes required to their
computer programs and hardware during 1996. The necessary
modifications to the NEES companies' centralized financial,
customer, and operational information systems are expected to be
completed by the end of 1998. Noncentralized systems are also
being reviewed for Year 2000 problems. The NEES companies believe
total costs associated with making the necessary modifications to
all centralized and noncentralized systems will be approximately
$25 million, of which approximately $8 million has been incurred
as of December 31, 1997. Most of the remaining costs are expected
to be incurred prior to December 31, 1998.

  New Accounting Standards
  In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in

<PAGE>
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. NEES is
currently evaluating the impact that these new accounting
standards will have on its future reporting requirements.

Liquidity and Capital Resources
Capital requirements for 1997 and projections for 1998 are shown below:

<TABLE>
<CAPTION>
Year ended December 31 (millions of dollars)               1997          1998
                                                           ----          ----
<S>                                                         <C>           <C>
Cash expenditures for utility plant                        $203          $200
Oil and gas exploration and development*                     13             -
                                                           ----          ----
  Total capital expenditures                                216           200
Maturing debt and prepayment requirements                    80            90
                                                           ----          ----
  Total capital requirements                               $296          $290
                                                           ----          ----
Cash from utility operations after
     payment of dividends                                  $244          $200
Cash from oil and gas operations*                            29             -
                                                           ----          ----
  Total cash from operations after
     the payment of dividends                              $273          $200
                                                           ----          ----
<FN>
*NEEI oil and gas assets sold as of February 5, 1998.
</FN>
</TABLE>

  The long-term debt financing activities of the NEES
subsidiaries for 1997 and the projected long-term debt financings
for 1998 are summarized as follows:

<TABLE>
<CAPTION>                            1997 Actual        1998 Projected
(millions of dollars)             Issues Retirements              Issues              Retirements
                                  ------ -----------              ------              -----------
<S>                                  <C>         <C>                 <C>                      <C>
NEP*                                $  -        $ 38                $  -                     $ 50
Massachusetts Electric                15          30                  55                       40
Narragansett Electric                 10          33                   5                        5
Granite State Electric                 -           -                   5                        -
Nantucket Electric                     -           1                   -                        1
Hydro-Transmission companies           -          11                   -                       12
NERC**                                 -           2                   -                        2
NEEI***                                -          27                   -                      122
                                  ------ -----------              ------                ---------
                                     $25        $142                 $65                     $232
<FN>
*  See"Divestiture of Generating Business"in Financial Review for
   information on potential NEP bond defeasance.
** $29 million of NERC debt will be retired in 1998 contingent upon
   completion of the sale of the nonnuclear generating business to USGen.
***                           NEEI debt retired on February 5, 1998.
</FN>
</TABLE>


<PAGE>
  The interest rate on the long-term debt issued in 1997 is 7.39
percent.

  In August 1997, the NEES Board of Directors authorized the
repurchase of up to five million NEES common shares through open
market purchases. Through December 31, 1997, NEES purchased
283,000 shares under the repurchase program.

  On December 19, 1997, NEES purchased, pursuant to a tender
offer, preferred stock of its subsidiaries with an aggregate par
value of $87 million. These purchases resulted in an after-tax
charge to net income of approximately $5 million.

  At December 31, 1997, NEES and its consolidated subsidiaries
had lines of credit and standby bond purchase facilities with
banks totaling $1.2 billion. These lines and facilities were used
at December 31, 1997 for liquidity support for $252 million of
commercial paper borrowing and $372 million of NEP mortgage bonds
in tax-exempt commercial paper mode. Fees are paid on the lines
and facilities in lieu of compensating balances.


<PAGE>
New England Electric System and Subsidiaries
Selected Financial Data
Year ended December 31 (dollar amounts expressed in millions, except per share
data)

<TABLE>
<CAPTION>
                                      1997           1996           1995           1994           1993
                                   -------        -------        -------        -------        -------
<S>                                            <C>            <C>                   <C>            <C>            <C>
Operating revenue:
Electric sales (excluding
 fuel cost recovery)                $1,592         $1,531         $1,521         $1,518         $1,488
Fuel cost recovery                     708            662            600            568            582
Other revenue                          162            125            121            117            117
Oil and gas sales                       41             33             30             40             47
                                   -------        -------        -------        -------        -------
  Total operating revenue           $2,503         $2,351         $2,272         $2,243         $2,234

Net income                          $  220         $  209         $  205         $  199         $  190

Average common shares (000's)
 Basic                              64,899         64,960         64,970         64,970         64,970
 Diluted                            64,952         64,986         64,986         64,988         64,985

Per share data:
Net income-Basic and Diluted        $ 3.39         $ 3.22         $ 3.15         $ 3.07         $ 2.93
Dividends declared                  $ 2.36         $ 2.36         $2.345         $2.285         $ 2.22
Return on average common equity      12.8%          12.6%          12.8%          12.7%          12.6%
Total assets                        $5,312         $5,223         $5,191         $5,085         $4,796

Capitalization:
Common share equity                 $1,744         $1,685         $1,632         $1,581         $1,530
Minority interests                      43             46             49             55             56
Cumulative preferred stock              39            126            147            147            147
Long-term debt                       1,488          1,615          1,675          1,520          1,512
                                   -------        -------        -------        -------        -------
  Total capitalization              $3,314         $3,472         $3,503         $3,303         $3,245

Deliveries to ultimate
 customers (millions of kWh)        22,097         21,674         21,311         21,155         20,832
Cost per kWh sold to ultimate
 customers (cents)                    9.88           9.51           9.54           9.29           9.50
System maximum
 demand (MW)                         4,326          4,091          4,381          4,385          4,081
Electric capability
 (net MW)-year end                   5,093          5,276          5,482          5,533          5,362
Number of employees                  4,665          4,787          4,832          4,990          4,969
Number of ultimate customers
 (in thousands)                      1,349          1,333          1,314          1,300          1,288
                                   -------        -------         ------        -------        -------
</TABLE>


<PAGE>
New England Electric System and Subsidiaries
Statements of Consolidated Income
Year ended December 31 (thousands of dollars, except per share data)

<TABLE>
<CAPTION>
                                                1997                1996           1995
                                          ----------          ----------     ----------
<S>                                                        <C>                      <C>            <C>
Operating revenue                         $2,502,591          $2,350,698     $2,271,712
                                          ----------          ----------     ----------
Operating expenses:
Fuel for generation                          372,461             334,994        237,498
Purchased electric energy                    528,229             509,400        548,370
Other operation                              556,658             501,090        500,721
Maintenance                                  143,372             127,785        136,058
Depreciation and amortization                236,492             246,379        264,666
Taxes, other than income taxes               146,494             143,733        132,631
Income taxes                                 152,024             139,199        128,340
                                          ----------          ----------     ----------
  Total operating expenses                 2,135,730           2,002,580      1,948,284
                                          ----------          ----------     ----------
Operating income                             366,861             348,118        323,428

Other income:
Allowance for equity funds used
 during construction                               -                   -          7,852
Equity in income of generating companies      10,240              10,334         10,552
Other income (expense), net                  (15,755)             (8,166)        (6,306)
                                          ----------          ----------     ----------
Operating and other income                   361,346             350,286        335,526
                                          ----------          ----------     ----------
Interest:
Interest on long-term debt                   107,311             110,479        108,365
Other interest                                16,939              19,527         19,826
Allowance for borrowed funds
 used during construction                     (1,908)             (2,246)       (14,016)
                                          ----------          ----------     ----------
  Total interest                             122,342             127,760        114,175
                                          ----------          ----------     ----------
Income after interest                        239,004             222,526        221,351
Preferred dividends and net gain/loss
 on reacquisition of preferred
 stock of subsidiaries                        12,319               6,463          8,690
Minority interests                             6,647               7,127          7,904
                                          ----------          ----------     ----------
Net income                                $  220,038          $  208,936     $  204,757
                                          ----------          ----------     ----------
Average common shares - Basic             64,899,322          64,960,496     64,969,652
Average common shares - Diluted           64,952,185          64,986,136     64,985,697
Per share data:
Net income - Basic and Diluted            $    3.39           $    3.22      $    3.15
Dividends declared                        $    2.36           $    2.36      $    2.345
                                          ----------          ----------     ----------
</TABLE>

Statements of Consolidated Retained Earnings
Year ended December 31 (thousands of dollars)
<TABLE>
<CAPTION>
                                                1997                1996           1995
                                          ----------          ----------     ----------
<S>                                                        <C>                      <C>            <C>
Retained earnings at beginning of year     $ 887,292           $ 831,529      $ 779,045
Net income                                   220,038             208,936        204,757
Dividends declared on common shares         (152,812)           (153,173)      (152,273)
                                          ----------          ----------     ----------
Retained earnings at end of year           $ 954,518           $ 887,292      $ 831,529
                                          ----------          ----------     ----------
</TABLE>

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


<PAGE>
New England Electric System and Subsidiaries
Consolidated Balance Sheets
At December 31 (thousands of dollars)

<TABLE>
<CAPTION>
                                                          1997           1996
                                                    ----------     ----------
<S>                                                                  <C>            <C>
Assets
Utility plant, at original cost                     $5,860,101     $5,692,956
Less accumulated provisions for depreciation
 and amortization                                    1,995,017      1,853,003
                                                    ----------     ----------
                                                     3,865,084      3,839,953
Construction work in progress                           48,708         56,652
                                                    ----------     ----------
  Net utility plant                                  3,913,792      3,896,605
                                                    ----------     ----------
Oil and gas properties, at full cost (Note A)        1,299,817      1,286,661
Less accumulated provision for amortization          1,128,659      1,081,940
                                                    ----------     ----------
  Net oil and gas properties                           171,158        204,721
                                                    ----------     ----------
Investments:
Nuclear power companies, at equity (Note D)             49,825         47,902
Other subsidiaries, at equity                           37,418         40,124
Other investments                                      117,645         96,399
                                                    ----------     ----------
  Total investments                                    204,888        184,425
                                                    ----------     ----------
Current assets:
Cash                                                    14,264          8,477
Accounts receivable, less reserves
 of $17,834 and $18,702                                257,185        262,103
Unbilled revenues                                       71,260         59,093
Fuel, materials, and supplies, at average cost          66,509         74,111
Prepaid and other current assets                        64,265         85,096
                                                    ----------     ----------
  Total current assets                                 473,483        488,880
                                                    ----------     ----------
Accrued Yankee nuclear plant costs (Note D)            299,564        166,413
Deferred charges and other assets (Note B)             248,762        282,207
                                                    ----------     ----------
                                                    $5,311,647     $5,223,251
                                                    ----------     ----------
Capitalization and liabilities
Capitalization (see accompanying statements):
Common share equity                                 $1,744,442     $1,685,417
Minority interests in consolidated subsidiaries         43,062         46,293
Cumulative preferred stock of subsidiaries              39,113        126,166
Long-term debt                                       1,487,481      1,614,578
                                                    ----------     ----------
  Total capitalization                               3,314,098      3,472,454
                                                    ----------     ----------
Current liabilities:
Long-term debt due within one year                      89,910         79,705
Short-term debt                                        251,950        145,050
Accounts payable                                       136,218        148,592
Accrued taxes                                           14,831         14,911
Accrued interest                                        24,969         27,494
Dividends payable                                       36,162         37,276
Other current liabilities (Note G)                     120,002        109,582
                                                    ----------     ----------
  Total current liabilities                            674,042        562,610
                                                    ----------     ----------
Deferred federal and state income taxes                720,375        750,929
Unamortized investment tax credits                      90,018         91,936
Accrued Yankee nuclear plant costs (Note D)            299,564        166,413
Other reserves and deferred credits                    213,550        178,909
Commitments and contingencies (Note D)
                                                    ----------     ----------
                                                    $5,311,647     $5,223,251
                                                    ----------     ----------
</TABLE>

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

<PAGE>
New England Electric System and Subsidiaries
Consolidated Statements of Cash Flows
Year ended December 31 (thousands of dollars)

<TABLE>
<CAPTION>
                                                 1997                1996           1995
                                             --------            --------       --------
<S>                                                         <C>                      <C>            <C>
Operating activities
Net income                                   $220,038            $208,936       $204,757
Adjustments to reconcile net income to net
  cash provided by operating activities:
 Depreciation and amortization                239,654             250,508        270,292
 Deferred income taxes and
  investment tax credits, net                 (31,178)            (30,328)        24,056
 Allowance for funds used during
  construction                                 (1,908)             (2,246)       (21,868)
 Amortization of unbilled revenues                  -                   -         (8,209)
 Minority interests                             6,647               7,127          7,904
 Decrease (increase) in accounts
  receivable, net and unbilled revenues         4,217              30,770          1,194
 Decrease (increase) in fuel,
  materials, and supplies                      10,664                 126         20,707
 Decrease (increase) in prepaid
  and other current assets                     24,729              (7,209)          (955)
 Increase (decrease) in accounts payable      (15,710)             (9,568)       (11,451)
 Increase (decrease) in other current
  liabilities                                  (2,718)             33,999         (4,784)
 Other, net                                    66,678              40,455        (11,790)
                                             --------            --------       --------
  Net cash provided by operating
   activities                                $521,113            $522,570       $469,853
                                             --------            --------       --------
Investing activities
Plant expenditures, excluding allowance
 for funds used during construction         $(203,095)          $(234,409)     $(329,385)
Oil and gas exploration and development       (13,156)            (20,371)       (17,947)
Other investing activities                    (22,669)            (10,309)       (32,460)
                                            ---------           ---------      ---------
  Net cash used in investing activities     $(238,920)          $(265,089)     $(379,792)
                                            ---------           ---------      ---------
Financing activities
Dividends paid to minority interests        $  (6,809)          $  (8,878)     $ (12,159)
Dividends paid on NEES common shares         (152,763)           (153,759)      (151,335)
Short-term debt                               105,900             (59,862)       (30,720)
Long-term debt - issues                        25,000              97,850        425,000
Long-term debt - retirements                 (142,205)           (106,811)      (311,920)
Preferred stock - redemptions                 (87,221)            (20,900)             -
Premium on reacquisition of long-term debt     (2,163)                  -         (2,003)
Return of capital to minority interests
 and related premium                           (3,348)             (1,633)        (1,364)
Repurchase of common shares                   (12,797)             (2,075)        (1,543)
                                            ---------           ---------      ---------
  Net cash provided by (used in)
   financing activities                     $(276,406)          $(256,068)     $ (86,044)
                                            ---------           ---------      ---------
Net increase in cash and cash equivalents   $   5,787           $   1,413      $   4,017
Cash and cash equivalents at beginning
 of year                                        8,477               7,064          3,047
                                            ---------           ---------      ---------
Cash and cash equivalents at end of year    $  14,264           $   8,477      $   7,064
                                            ---------           ---------      ---------
Supplementary information
Interest paid less amounts capitalized      $ 115,545           $ 119,710      $ 105,459
                                            ---------           ---------      ---------
Federal and state income taxes paid         $ 174,000           $ 168,255      $  68,312
                                            ---------           ---------      ---------
Dividends received from investments
 at equity                                  $  10,802           $  12,987      $  14,748
                                            ---------           ---------      ---------
</TABLE>

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


<PAGE>
New England Electric System and Subsidiaries
Consolidated Statements of Capitalization
At December 31 (thousands of dollars)

<TABLE>
<CAPTION>
Common share equity                                     1997        1996
                                                  ----------  ----------
<S>                                                                  <C>            <C>
Common shares, par value $1 per share
 Authorized - 150,000,000 shares
 Issued - 64,969,652 shares                       $   64,970  $   64,970
Paid-in capital                                      736,605     736,773
Retained earnings                                    954,518     887,292
Treasury stock - 431,875 and 102,957 shares,
 respectively                                        (16,415)     (3,618)
Unrealized gain on securities, net                     4,764           -
                                                  ----------  ----------
  Total common share equity                       $1,744,442  $1,685,417
                                                  ----------  ----------
</TABLE>

<TABLE>
<CAPTION>
                                  Shares outstanding
Cumulative preferred stock of
 subsidiaries                            1997      1996      1997      1996
                                     --------  --------  --------  --------
<S>                                                 <C>       <C>       <C>       <C>
$100 Par value
 4.44% to 4.76%                       106,400   371,640   $10,640  $ 37,164
 6.00% to 6.99%                       108,690   375,020    10,869    37,502
$50 Par value
 4.50% to 6.95%                       256,000   730,000    12,800    36,500
$25 Par value
 6.84%                                192,160   600,000     4,804    15,000
                                     --------  --------  --------  --------
  Total cumulative preferred stock
   of subsidiaries (annual dividend
   requirement of $2,284 for 1997
   and $7,332 for 1996)               663,250 2,076,660   $39,113  $126,166
                                     -------- ---------  --------  --------
</TABLE>

<TABLE>
<CAPTION>
Long-term debt (Note H)               Maturity        Rate      1997      1996
                             -----------------         -----------------------     ----------
<S>                                                    <C>       <C>       <C>            <C>
Mortgage bonds - New England
 Power Company               1997 through 1999         6.040%-8.280%$   60,000     $   63,000
                             2000 through 2004         6.580%-8.330%    90,000         90,000
                             2015 through 2024         7.250%-8.530%   178,000        213,500
                             2018 through 2022    Variable   371,850   371,850
Mortgage bonds - All other
 NEES subsidiaries           1997 through 1999         5.700%-7.810%    48,000        110,500
                             2000 through 2004         6.240%-8.520%   153,500        153,500
                             2005 through 2014         6.110%-8.450%    94,000         94,000
                             2015 through 2026         7.050%-9.125%   254,200        229,200
Notes
Granite State Electric Company           1997 through 2025       7.370%-9.440%         15,000         15,000
Nantucket Electric Company   1997 through 2016         4.100%-8.500%    30,735         31,500
New England Energy Incorporated          1998 through 2002  Variable   122,000        149,000
Hydro-Transmission companies 2001 through 2015         8.820%-9.410%   136,490        148,010
Narragansett Energy Resources
 Company                                  2010      7.250%    28,640    30,560

Unamortized discounts and premiums, net                       (5,024)   (5,337)
                                                          --------------------
  Total long-term debt                                     1,577,391 1,694,283
                                                          --------------------
Long-term debt due in one year                               (89,910)  (79,705)
                                                          --------------------
                                                          $1,487,481$1,614,578
                                                          --------------------
</TABLE>

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

<PAGE>
New England Electric System and Subsidiaries
Notes to Consolidated Financial Statements

  Note A - Significant Accounting Policies

  1. Nature of operations
  New England Electric System (NEES) is a public utility holding
company headquartered in Westborough, Massachusetts. Its
subsidiaries are engaged in the transmission, distribution, sale,
and generation of electricity, and the marketing of energy
commodities and services. NEES' electricity delivery subsidiaries
serve 1.3 million customers in Massachusetts, Rhode Island, and
New Hampshire. Other business activities include independent
transmission projects and telecommunications project management.

  The NEES system provides electric service to distribution
customers through separate distribution subsidiaries,
Massachusetts Electric Company (Massachusetts Electric) and
Nantucket Electric Company (Nantucket Electric), which operate in
Massachusetts; The Narragansett Electric Company (Narragansett
Electric), which operates in Rhode Island; and Granite State
Electric Company (Granite State Electric), which operates in New
Hampshire. Each of the distribution subsidiaries purchased
electricity on behalf of its customers under wholesale all-
requirements contracts with NEES' generation and transmission
subsidiary, New England Power Company (NEP). See Note B for a
discussion of industry restructuring and Note C for a discussion
of NEP and Narragansett Electric's planned divestiture of their
nonnuclear generating business.

  2. Basis of consolidation and financial statement presentation
  The consolidated financial statements include the accounts of
NEES and all subsidiaries except New England Electric
Transmission Corporation, which is recorded under the equity
method. Presentation of this subsidiary on the equity basis is
not material to the consolidated financial statements. NEP has a
minority interest in four regional nuclear generating companies
(Yankees). Narragansett Energy Resources Company (NERC) has a 20
percent general partnership interest in the Ocean State Power
(OSP) generating facility. NEP and NERC account for these
ownership interests under the equity method. During 1997, NEES
increased its ownership from 50 percent to 100 percent of
AllEnergy Marketing Company, L.L.C. (AllEnergy), an energy
marketing enterprise.

  NEES owns 50.4 percent of the outstanding common stock of both
New England Hydro-Transmission Electric Company, Inc. and New
England Hydro-Transmission Corporation (Hydro-Transmission
companies). The consolidated financial statements include 100
percent of the assets, liabilities, and earnings of the Hydro-
Transmission companies. Minority interests, which represent the
minority stockholders' proportionate share of the equity and
income of the Hydro-Transmission companies, have been separately
disclosed on the NEES consolidated balance sheets and income
statements.


<PAGE>
  NEP is also a 12 percent and 10 percent joint owner,
respectively, of the Millstone 3 and Seabrook 1 nuclear
generating units, each 1,150 megawatts (MW). NEP's net
investments in Millstone 3 and Seabrook 1 at December 31, 1997,
included in "Net utility plant," were approximately $366 million
and $54 million, respectively. NEP's share of the related
expenses for these units is included in "Operating expenses." In
addition, in a 1995 rate agreement, a provision was made for the
accelerated recovery of NEP's investment in Millstone 3. This
accumulated accelerated amortization at December 31, 1997
amounted to approximately $17 million and was included as a
regulatory liability in "Other reserves and deferred credits"
(see Note A-5 and Note B).

  NEES, through its wholly owned indirect subsidiary, AllEnergy,
uses derivative instruments to manage exposure in fluctuations in
commodity prices. At this time, AllEnergy has only held exchange-
traded futures contracts to manage risks associated with natural
gas, propane, and heating oil price risks. Hedge criteria used
and accounting for hedge transactions are in accordance with
Statement of Financial Accounting Standards No. 80, Accounting
for Futures Contracts (FAS 80). FAS 80 states that in order to
qualify as a hedge, price movements in commodity derivatives must
be highly correlated with the underlying hedged commodity and
must reduce exposure to market fluctuations throughout the hedged
period. Any gain or loss on a derivative which qualifies as a
hedge under FAS 80 is deferred until recognized in the income
statement in the same period as the hedged item is recognized in
the income statement. As of December 31, 1997, all of AllEnergy's
existing futures contracts qualified as hedges.

  The accounts of NEES and its utility subsidiaries are
maintained in accordance with the Uniform System of Accounts
prescribed by regulatory bodies having jurisdiction. All
significant intercompany transactions between consolidated
subsidiaries have been eliminated.

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

  3. Electric sales revenue
  All of NEES' subsidiaries accrue revenues for electricity
delivered but not yet billed (unbilled revenues), with the
exception of Granite State Electric. Included in income is $8
million in 1995 which represents amortization of the initial
effect of recording unbilled revenues, in accordance with the
retail rate agreements. Accrued revenues are also recorded in
accordance with rate adjustment mechanisms which include
Massachusetts Electric's and Nantucket Electric's purchased power
cost adjustment (PPCA) mechanisms. Upon approval of the
Massachusetts Settlement in November 1997, the PPCA mechanisms
were eliminated as of July 31, 1996. Pending final approval of

<PAGE>
the settlement, Massachusetts Electric and Nantucket Electric had
accrued refund reserves of $9 million for the last five months of
1996 and an additional $9 million in the first nine months of
1997. Upon final approval of the settlement, these refund
reserves were reversed in the fourth quarter of 1997, thereby
increasing revenue.

  4. Allowance for funds used during construction (AFDC)
  The utility subsidiaries capitalize AFDC as part of
construction costs. AFDC represents the composite interest and
equity costs of capital funds used to finance that portion of
construction costs not yet eligible for inclusion in rate base.
AFDC is capitalized in "Utility plant" with offsetting noncash
credits to "Other income" and "Interest." This method is in
accordance with an established rate-making practice under which a
utility is permitted a return on, and the recovery of, prudently
incurred capital costs through their ultimate inclusion in rate
base and in the provision for depreciation. The composite AFDC
rates were 5.9 percent, 5.6 percent, and 7.3 percent, in 1997,
1996, and 1995, respectively.

  5. Depreciation and amortization
  The depreciation and amortization expense included in the
statements of consolidated income is composed of the following:

<TABLE>
<CAPTION>

Year ended December 31 (thousands of dollars)       1997             1996           1995
                                                --------         --------       --------
<S>                                                           <C>                    <C>            <C>
Depreciation                                    $172,010         $171,193       $159,510
Nuclear decommissioning costs (see Note D-5)       2,638            2,629          2,629
Amortization:
  Oil and gas properties (see Note A-6)           46,718           49,163         68,708
  Investment in Seabrook 1
   pursuant to rate settlement                         -           15,210         23,073
  Oil Conservation Adjustment (OCA)                    -                -          4,467
  Seabrook 2 property losses                         113            6,280          6,279
  Millstone 3 additional amortization,
   pursuant to rate settlement                    15,013            1,904              -
                                                --------         --------       --------
     Total depreciation and amortization
     expense                                    $236,492         $246,379       $264,666
                                                --------         --------       --------
</TABLE>

  Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average depreciable property was 3.1 percent in 1997, 3.2 percent
in 1996, and 3.3 percent in 1995. Revenues from the OCA were used
to accelerate the amortization of expenditures for coal
conversion facilities at NEP's Salem Harbor Station. In addition,
Seabrook 1 costs under the 1988 rate settlement were fully
amortized at December 31, 1996. Property losses associated with
NEP's investment in the canceled Seabrook 2 nuclear unit were
fully amortized by March 31, 1997. In 1996, New England Energy
Incorporated (NEEI), a wholly owned subsidiary of NEES, reduced
amortization expense of its oil and gas properties by $13 million
to correct amounts recorded in the years 1990 through 1996.

<PAGE>
  6. Oil and gas investments
  NEEI participated in a rate-regulated domestic oil and gas
exploration, development, and production program through a
partnership with a nonaffiliated oil company. Losses from this
program, calculated under the full cost method of accounting,
have been charged to NEP, and ultimately to distribution
customers, in accordance with Securities and Exchange Commission
(SEC) and Federal Energy Regulatory Commission (FERC) approvals.
Such losses were $11 million, $22 million, and $44 million in
1997, 1996, and 1995, respectively. In February 1998, after a
competitive bidding process, NEEI sold all of its remaining oil
and gas properties held as of December 31, 1997 to its partner
for $50 million. The loss on such disposition, approximately $120
million, before tax, has been charged to NEP. The settlements
provide for the recovery of the NEEI loss as part of NEP's
stranded costs. See Note B for a discussion of industry
restructuring and Note C for a discussion of NEP's planned
divestiture of its nonnuclear generating business.

  7. Cash
  NEES and its subsidiaries classify short-term investments with
an original maturity of 90 days or less as cash.

  8. Average common shares
  The following table summarizes the reconciling amounts between
basic and diluted earnings per share (EPS) computations, in
compliance with Statement of Financial Accounting Standards No.
128, Earnings per Share, which became effective during 1997, and
requires restatement for all prior-period EPS data presented.

<TABLE>
<CAPTION>

Year ended December 31                          1997         1996        1995
                                            --------     --------    --------
<S>                                                           <C>         <C>       <C>
Income after interest and
  minority interest (000's)                 $232,357     $215,399    $213,447
Less: preferred stock dividends and
  net gain/loss on reacquisition of
  preferred stock of subsidiaries (000's)   $ 12,319     $  6,463    $  8,690
Income available to common
  shareholders (000's)                      $220,038     $208,936    $204,757
Basic EPS                                   $   3.39     $   3.22    $   3.15
Diluted EPS                                 $   3.39     $   3.22    $   3.15
                                            --------     --------    --------
Average common shares outstanding for
  Basic EPS                               64,899,322   64,960,496  64,969,652
Effect of Dilutive Securities
Average potential common shares related
  to share-based compensation plans           52,863       25,640      16,045
                                          ----------   ----------  ----------
Average common shares outstanding for
  Diluted EPS                             64,952,185   64,986,136  64,985,697
                                          ----------   ----------  ----------
</TABLE>


<PAGE>
  9. New accounting standards
  In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. NEES is
currently evaluating the impact that these new accounting
standards will have on its future reporting requirements.

  Note B - Industry Restructuring

  As the result of legislation enacted in the states served by
the NEES companies, most customers served by the NEES companies
will have the ability to choose their power supplier during the
first quarter of 1998. When customers are allowed to choose their
power supplier, utilities face the risk that market prices may
not be sufficient to recover the costs of the commitments
incurred to supply customers under a regulated structure. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs." As described below, the NEES
companies have reached settlement agreements with parties
representing all of their distribution customers. In each case,
these settlements provide for recovery of stranded costs. See the
"Industry Restructuring" section of Financial Review for a more
in-depth discussion of current developments in this area.

The settlements generally provide for the following:
- introduction of choice of power supplier in Rhode Island,
  Massachusetts, and New Hampshire by January 1, 1998, March 1,
  1998, and July 1, 1998, respectively;

- a transition rate, or "standard offer generation service," for
  customers who do not choose an alternative power supplier,
  resulting in rate reductions of approximately 10 percent at
  the date of commencement of retail choice;

- termination of all-requirements contracts between NEP and
  NEES' distribution companies on terms that allow NEP to
  recover its stranded costs through a transition access charge,
  which the distribution companies will collect from customers;

- adjustments to stranded cost recovery to reflect the market
  value of fossil-fueled and hydroelectric generating assets,
  determined through divestiture of such assets.

  Under the various settlements, the recovery of NEP's stranded
costs is divided into several categories. Unrecovered costs
associated with generating plants and regulatory assets would be
recovered over 12 years and would earn a return on equity of 9.4
percent. The above-market component of purchased power contracts
and nuclear decommissioning costs would be recovered as incurred
over the life of those obligations, a period expected to extend

<PAGE>
beyond 12 years. Initially, the transition access charge would be
set at 2.8 cents per kilowatthour (kWh) and would be reduced upon
completion of the sale of NEP's generating business, as described
below. As the transition access charge declines, NEP would earn
incentives based on successful mitigation of its stranded costs.
These incentives would supplement NEP's return on equity. The
Massachusetts and Rhode Island settlements were conditionally
approved by the FERC in November 1997, subject to a compliance
filing to clarify the impact of the settlements on nonsettling
parties. The Massachusetts Settlement was also found by the
Massachusetts Department of Telecommunications and Energy to be
in substantial compliance with or consistent with the
Massachusetts restructuring statute. The New Hampshire settlement
is pending before the New Hampshire Public Utilities Commission
and the FERC.

  In August 1997, NEP and Narragansett Electric entered into an
agreement to sell substantially all of their nonnuclear
generating business to USGen New England, Inc. (USGen), an
indirect wholly owned subsidiary of PG&E Corporation (PG&E). The
net proceeds from the sale of its nonnuclear generating business
to USGen will be used to reduce the transition access charge from
2.8 cents per kWh to approximately 1.5 cents per kWh. In
addition, the FERC accepted the NEES companies' proposal in
conjunction with their divestiture filing that the recovery of
the remaining above-market nuclear generating plant investment
and regulatory assets be fully recovered by the end of the year
2000 (see Note C for a discussion of NEP and Narragansett
Electric's planned divestiture of their nonnuclear generating
business)

  Accounting implications
  Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates.

  In response to concerns expressed by the staff of the SEC, the
Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board took under consideration how FAS 71 should be
applied in light of recent changes within the regulated utility
industry. In July 1997, the EITF concluded that a utility whose
ongoing generation operations would not permit the application of
FAS 71, but had otherwise received approval to recover stranded
costs through regulated transmission and distribution rates,
would be permitted to continue to apply FAS 71 to the recovery of
the stranded costs.


<PAGE>
  The restructuring settlements and statutes each provide for
recovery of stranded costs of generating assets and oil and gas
related assets (including regulatory assets) not recoverable from
the proceeds of the divestiture of NEP's generating business. The
cost of these assets would be recovered as part of a cost-based
transition access charge imposed on all distribution customers.
Additionally, FERC Order No. 888 enables transmission companies
to recover their specific costs of providing transmission
service. Therefore, after the proposed divestiture, substantially
all of NEP's business, including the recovery of its stranded
costs, would remain under cost-based rate regulation. NEES
further believes the restructuring settlements and statutes will
enable the NEES distribution companies to recover through rates
their specific costs of providing ongoing distribution services.
NEES believes these factors and the EITF conclusion will allow
its principal utility subsidiaries to continue to apply FAS 71.
As a result of the FERC approval of the restructuring settlements
in November 1997, NEP was required to cease to apply FAS 71 to 20
percent of its ongoing nuclear operations, as described in Note
C, the impact of which is expected to be immaterial.

  Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations. In addition, write-downs of
plant assets 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 (FAS 121) could be
required, including a write-off of any gain or loss from the
divestiture of the generating business. At December 31, 1997, the
NEES companies had approximately $600 million in regulatory
assets in compliance with FAS 71, as detailed in the table below,
of which approximately $60 million relate to the transmission and
distribution business.


<PAGE>
<TABLE>
<CAPTION>
The components of regulatory assets are as follows:

At December 31 (thousands of dollars)               1997             1996
<S>                                                                   <C>            <C>
                                                --------         --------
Oil and gas properties:
  in excess of market value (see Note A-6)      $121,000         $149,100
                                                --------         --------
Regulatory assets included in current
  assets & liabilities:
 Accrued NEEI losses (see Note A-6)               11,419           21,648
 Rate adjustment mechanisms (see Note G)         (15,306)         (48,894)
                                                --------         --------
                                                  (3,887)         (27,246)
                                                --------         --------
Regulatory assets included in deferred charges
and other reserves and deferred credits:
 Accrued costs - Yankee nuclear plants
  (see Note D-5)                                 299,564          166,413
 Unamortized losses on reacquired debt            50,605           52,167
 Deferred FAS No. 106 costs (see Note E-2)         9,191           29,839
 Deferred FAS No. 109 costs (see Note F)          72,145           72,075
 Purchased power contract termination costs       15,662           19,578
 Deferred gas pipeline charges (see Note D-2)     52,570           59,733
 Deferred storm costs                              4,522            6,530
 Environmental response costs (see Note D-4)     (15,753)          18,265
 Accelerated amortization - Millstone 3          (16,917)          (1,904)
 Other                                             9,459            8,383
                                                --------         --------
                                                 481,048          431,079
                                                --------         --------
                                                $598,161         $552,933
                                                --------         --------
</TABLE>

  Note C - Divestiture of Generating Business

  As described above, in August 1997, NEP and Narragansett
Electric (collectively, the Sellers) reached an agreement to sell
their nonnuclear generating business to USGen. The nonnuclear
generating business includes three fossil-fueled and 15
hydroelectric generating stations, totaling approximately 4,000
MW of capacity, as well as NERC's partnership interest in OSP,
all of which has a book value of $1.1 billion. USGen will pay the
Sellers $1.59 billion in cash, of which $225 million will be
contingent upon the introduction of customer choice of power
supplier. Based on the enactment of the Massachusetts statute,
the NEES companies believe that the conditions for payment of the
full purchase price have been met. USGen will also reimburse the
NEES companies for $85 million of costs associated with early
retirement and special severance programs for employees affected
by industry restructuring. Since the early retirement program is
contingent upon the divestiture, its cost will not be accrued
until that time. USGen will assume responsibility for
environmental conditions at the Sellers' nonnuclear generating
stations. USGen will also assume the Sellers' obligations under
long-term fuel and fuel transportation contracts and certain
collective bargaining agreements.


<PAGE>
  In addition to the purchase of the nonnuclear generating
stations, USGen will purchase NEP's entitlement to approximately
1,100 MW of power procured under long-term contracts. NEP will
make a monthly fixed contribution towards the above-market cost
of the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.

  The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale on
various grounds, including allegations that, following the sale,
USGen would be able to exercise unlawful levels of market power.
On February 25, 1998, the FERC issued an order that rejected the
market power allegations, approved the sale, and conditionally
approved most supporting filings. While the timing of receipt of
final regulatory approvals is uncertain, receipt of all approvals
is unlikely before mid-1998. Closing is contingent upon all
regulatory approvals being obtained by February 1999.

  In order to meet the terms of NEP's mortgage indenture, NEP
will be required, prior to the consummation of the sale, to
either defease or call approximately $278 million of its mortgage
bonds. Any defeasance of bonds would be by deposit of cash
representing principal and interest to the maturity date, or
interest, principal, and general redemption premium to an earlier
redemption date. In addition, NEP will retire approximately $372
million of mortgage bonds securing the issuance of a like amount
of pollution control revenue bonds (PCRBs) by various public
agencies. However, NEP expects that substantially all of the
underlying PCRBs will remain outstanding as unsecured obligations
of NEP. In addition, the long-term debt of NERC will be retired
prior to the closing.

  As part of the divestiture plan, in February 1998, NEEI sold
its oil and gas properties for approximately $50 million. NEEI's
loss on the sale of approximately $120 million, before tax, has
been reimbursed by NEP. See Note H for information on NEEI debt
retirements.

  At the divestiture date, any gain or loss from the divestiture
of nonnuclear generating assets and oil and gas assets will be
recorded as a regulatory asset or liability to be recovered as
part of NEP's stranded costs, through the ongoing transition
access charge, consistent with the settlement agreements. NEP may
be required to record a liability for the monthly fixed
contribution towards the above-market cost of purchased power. In
such an event, NEP would also record a regulatory asset
consistent with the settlement agreements.


<PAGE>
  In addition, NEP will endeavor to sell, or otherwise transfer,
its minority interest in three nuclear power plants and a 60 MW
interest in a fossil-fueled generating station in Maine to
nonaffiliates. Until such time as the nuclear interests are
divested, NEP will share with customers 80 percent of the
revenues and operating costs related to the units, with
shareholders retaining the balance. In the event that NEP
determines that it has an impairment of its nuclear plant
balances under FAS 121, it will record any such impairment as a
regulatory asset.

  Note D - Commitments and Contingencies

  1. Plant expenditures
  The NEES subsidiaries' utility plant expenditures are
estimated to be $200 million in 1998. At December 31, 1997,
substantial commitments had been made relative to future planned
expenditures.

  2. Natural gas pipeline capacity
  In connection with serving NEP's gas-fueled electric
generation facilities, NEP has entered into several contracts for
natural gas pipeline capacity and gas supply. These agreements
require minimum fixed payments that are currently estimated to be
$59 million to $62 million per year from 1998 to 2002. Under
these agreements, remaining fixed payments from 2003 through 2014
total approximately $501 million.

  In connection with managing its fuel supply, NEP uses a
portion of this pipeline capacity to sell natural gas. Proceeds
from the sale of natural gas and pipeline capacity of $41
million, $50 million, and $71 million in 1997, 1996, and 1995,
respectively, have been passed on to customers through NEP's fuel
clause. These proceeds have been reflected as an offset to the
related fuel expense in "Fuel for generation" in NEP's statements
of income. Natural gas sales decreased in 1996 as a result of the
Manchester Street plant entering commercial operation in the
second half of 1995.

  See Note C for a discussion of NEP's planned divestiture of
its nonnuclear generating business.

  3. Long-term contracts for the purchase of electricity
  NEP purchases a portion of its electricity requirements
pursuant to long-term contracts with owners of various generating
units. These contracts expire in various years from 1998 to 2029.

  Certain of these contracts require NEP to make minimum fixed
payments, even when the supplier is unable to deliver power, to
cover NEP's proportionate share of the capital and fixed
operating costs of these generating units. The fixed portion of
payments under these contracts totaled $114 million in 1997, $127
million in 1996, and $150 million in 1995, excluding contracts
with Yankee Atomic, Connecticut Yankee, and Maine Yankee (see
Note D-5) for all periods presented. These contracts have minimum
fixed payment requirements of $110 million annually from 1998
through 2001, $120 million in 2002, and approximately $950

<PAGE>
million thereafter. Approximately 97 percent of the payments
under these contracts are to Vermont Yankee and OSP, entities in
which NEES subsidiaries hold ownership interests.

  NEP's other contracts, principally with nonutility generators,
require NEP to make payments only if power supply capacity and
energy are deliverable from such suppliers. NEP's payments under
these contracts amounted to $265 million in 1997, $230 million in
1996, and $245 million in 1995.

  See Note C for a discussion of NEP's planned divestiture of
its nonnuclear generating business.

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

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

  NEES and/or its subsidiaries have been named as potentially
responsible parties (PRPs) by either the United States
Environmental Protection Agency (EPA) or the Massachusetts
Department of Environmental Protection for 20 sites at which
hazardous waste is alleged to have been disposed. Private parties
have also contacted or initiated legal proceedings against NEES
and certain subsidiaries regarding hazardous waste cleanup. The
most prevalent types of hazardous waste sites with which NEES and
its subsidiaries have been associated are manufactured gas
locations. (Until the early 1970s, NEES was a combined electric
and gas holding company system.) NEES is aware of approximately
40 such manufactured gas locations, mostly located in
Massachusetts. The NEES companies have been identified as PRPs at
10 of these manufactured gas locations, which are included in the
20 PRP sites discussed above. NEES has reported the existence of
all manufactured gas locations of which it is aware to state
environmental regulatory agencies. NEES is engaged in various
phases of investigation and remediation work at approximately 20
of the manufactured gas locations. NEES and its subsidiaries are
currently aware of other possible hazardous waste sites, and may
in the future become aware of additional sites, that they may be
held responsible for remediating.


<PAGE>
  In 1993, the Massachusetts Department of Public Utilities
approved a settlement agreement regarding the rate recovery of
remediation costs of former manufactured gas sites and certain
other hazardous waste sites located in Massachusetts. Under that
agreement, qualified costs related to these sites are paid out of
a special fund established on Massachusetts Electric's books.
Massachusetts Electric made an initial $30 million contribution
to the fund. Rate-recoverable contributions of $3 million,
adjusted since 1993 for inflation, are added annually to the fund
along with interest and any recoveries from insurance carriers.
At December 31, 1997, the fund had a balance of $45 million. NEES
had a regulatory liability of $16 million on its books at the end
of 1997, all of which is included in the fund. This regulatory
liability reflects $15 million, plus interest, transferred from
existing reserves for refunds under a 1996 Massachusetts industry
restructuring settlement, which is more fully described in Note
B.

  Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult. There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by NEES or its
subsidiaries. The NEES companies have recovered amounts from
certain insurers, and, where appropriate, intend to seek recovery
from other insurers and from other PRPs, but it is uncertain
whether, and to what extent, such efforts will be successful. At
December 31, 1997, NEES had total reserves for environmental
response costs of $44 million. NEES believes that hazardous waste
liabilities for all sites of which it is aware, and which are not
covered by a rate agreement, are not material to its financial
position.

  In October 1996, the American Institute of Certified Public
Accountants issued new accounting rules for Environmental
Remediation Liabilities which became effective in 1997. These new
rules did not have a material effect on NEES' financial position
or results of operations.

  See Note C for a discussion of NEP's planned divestiture of
its nonnuclear generating business.


<PAGE>
  5. Nuclear units

  Nuclear Units Permanently Shut Down
  Three of the four regional nuclear generating companies in
which NEP has a minority interest own nuclear generating units
which have been permanently shut down. These three units are as
follows:

<TABLE>
<CAPTION>
                                                                                  Future Estimated
                                        NEP's Investment                                                    Billings to NEP
Unit                       %  $(millions)   Date Retired    $(millions)
----------------------------------------------------------------------------
<S>                      <C>                         <C>         <C>            <C>
Yankee Atomic             30                           7              February 1992             44
Connecticut Yankee                 15                 17              December 1996             92
Maine Yankee              20                          16 August 1997            164

</TABLE>

  In the case of each of these units, NEP has recorded an
estimate of the total future payment obligation as a liability
and an offsetting regulatory asset, reflecting estimated future
billings from the companies. In a 1993 decision, the FERC allowed
Yankee Atomic to recover its undepreciated investment in the
plant as well as unfunded nuclear decommissioning costs and other
costs. Connecticut Yankee and Maine Yankee have both filed
similar requests with the FERC. Several parties have intervened
in opposition to both filings. NEP's stranded cost settlements
allow NEP to recover all costs that the FERC allows the Yankee
companies to bill to NEP.

  In October 1997, the Citizen's Awareness Network and Nuclear
Information and Resource Service filed a petition with the
Nuclear Regulatory Commission (NRC) that would require formal NRC
approval of a decommissioning plan for the Connecticut Yankee and
Maine Yankee plants. In 1998, the petitioners indicated their
intention to file a request with the NRC designed to overturn a
current NRC rule on decommissioning. NEP cannot predict what
impact, if any, these activities will have on the cost of
decommissioning the plants.

  At Maine Yankee, the NRC has identified numerous apparent
violations of its regulations, which may result in the assessment
of significant civil penalties.

  In the 1970s, NEP and several other shareholders (Sponsors) of
Maine Yankee entered into 27 contracts (Secondary Purchase
Agreements) under which they sold portions of their entitlement
to Maine Yankee power output through 2002 to various entities,
primarily municipal and cooperative systems in New England
(Secondary Purchasers). Virtually all of the Secondary Purchasers
have ceased making payments under the Secondary Purchase
Agreements and have demanded arbitration, claiming that such
agreements excuse further payments upon plant shutdown. NEP has
notified the Secondary Purchasers that the shutdown does not
relieve them of their obligation to make payments under the
Secondary Purchase Agreements and that they are in default of

<PAGE>
such agreements. NEP has further asked the FERC to enforce NEP's
rights under the agreements. In the event that no further
payments are forthcoming from Secondary Purchasers, NEP, as a
primary obligor to Maine Yankee, would be required to pay an
additional $9 million of future shutdown costs. These costs are
not included in the $164 million estimate disclosed in the table
above. Shutdown costs are recoverable from customers under the
stranded cost settlements.

  A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.

  Operating Nuclear Units
  NEP has minority interests in three other nuclear generating
units, Vermont Yankee, Millstone 3, and Seabrook 1. In October
1996, the NRC issued letters to operators of nuclear power plants
requiring them to document that the plants are operated and
maintained within their design and licensing bases, and that any
deviations are reconciled in a timely manner. The Seabrook 1 and
Vermont Yankee nuclear power plants responded to the NRC letters
in February 1997. Millstone 3 is currently shut down and has been
placed on the NRC "Watch List," signifying that its safety
performance exhibits sufficient weakness to warrant increased NRC
attention. Millstone 3 may not restart without NRC approval.

  Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. NEP performs periodic economic viability reviews of
operating nuclear units in which it holds ownership interests.

  Millstone 3
  In April 1996, the NRC ordered Millstone 3, which has
experienced numerous technical and nontechnical problems, to
remain shut down pending verification that the unit's operations
are in accordance with NRC regulations and the unit's operating
license. Millstone 3 is operated by a subsidiary of Northeast
Utilities (NU). NEP is not an owner of the Millstone 1 and 2
nuclear generating units, which are also shut down under NRC
orders.

  A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective actions taken at the unit,
an NRC assessment concluding a safety conscious work environment
exists, public meetings, and a vote of the NRC Commissioners. NEP
cannot predict when Millstone 3 will be allowed by the NRC to
restart, but believes restart of the unit is not likely prior to
the summer of 1998.


<PAGE>
  Since April 1996, NEP has incurred an estimated $35 million in
incremental replacement power costs, which it has been recovering
from customers through its fuel clause. During the outage, NEP is
incurring incremental replacement power costs of approximately $2
million per month.

  Several criminal investigations related to Millstone 3 are
ongoing. In December 1997, the NRC assessed civil penalties
totaling $2.1 million for numerous violations at the three
Millstone units. NEP's share of this fine was less than $100,000.
The Connecticut Department of Environmental Protection and the
Connecticut Attorney General have filed suit against NU for
alleged wastewater discharge violations at the Millstone units,
which may result in the assessment of substantial civil
penalties.

  In August 1997, NEP filed suit against NU in Massachusetts
Superior Court for damages resulting from the tortious conduct of
NU relating to Millstone 3. NEP is seeking compensation for the
losses it has suffered, including the costs of lost power and
costs necessary to assure that Millstone 3 can safely return to
operation. NEP also seeks punitive damages. NU has filed for
dismissal of the suit and sought to consolidate it with suits
filed by other joint owners in Massachusetts Superior Court.

  NEP also sent a demand for arbitration to Connecticut Light &
Power Company and Western Massachusetts Electric Company, both
subsidiaries of NU, seeking damages resulting from their breach
of obligations under an agreement with NEP and others regarding
the operation and ownership of Millstone 3.

  Decommissioning Trust Funds
  Each nuclear unit in which NEP has an ownership interest has
established a decommissioning trust fund or escrow fund into
which payments are being made to meet the projected costs of
decommissioning. Listed below is information on each operating
nuclear plant in which NEP has an ownership interest.

  NEP is liable for its share of decommissioning costs for
Millstone 3, Seabrook 1, and all of the Yankees. Decommissioning
costs include not only estimated costs to decontaminate the units
as required by the NRC, but also costs to dismantle the
uncontaminated portion of the units. NEP records decommissioning
costs on its books consistent with its rate recovery. NEP is
recovering its share of projected decommissioning costs for
Millstone 3 and Seabrook 1 through depreciation expense. In
addition, NEP is paying its portion of projected decommissioning
costs for all of the Yankees through purchased power expense.
Such costs reflect estimates of total decommissioning costs
approved by the FERC.


<PAGE>
<TABLE>
<CAPTION>
                           NEP's share of (millions of dollars)
                                                  --------------------------------------------------
                  Nep's                  Estimated   Decommissioning
                Ownership     Net    Decommissioning        Fund       License
Unit          Interest (%)              Plant Assets           Cost (in 1997 $)     Balances*     Expiration
----          --------------------------------------    ----------  ----------
<S>                           <C>           <C>             <C>          <C>       <C>
Vermont Yankee      20         35            77            34           2012
Millstone 3         12        366            66            18**         2025
Seabrook 1***       10         54            47             9**         2026

<FN>
*  Certain additional amounts are anticipated to be available through tax deductions.

** Fund balances are included in "Other investments" on the balance sheets. Any
differences from market value are not material.

***              Proposed legislation in New Hampshire would make owners of Seabrook 1 proportional
guarantors for decommissioning costs in the event that an owner without a franchise
service territory fails to fund its share of decommissioning costs.
</FN>
</TABLE>

  There is no assurance that decommissioning costs actually
incurred by Vermont Yankee, Millstone 3, or Seabrook 1 will not
substantially exceed these amounts. For example, decommissioning
cost estimates assume the availability of permanent repositories
for both low-level and high-level nuclear waste; those
repositories do not currently exist. If any of the units were
shut down prior to the end of their operating licenses, which NEP
believes is likely, the funds collected for decommissioning to
that point would be insufficient. Under the settlement agreements
discussed in Note B, NEP will recover decommissioning costs
through transition access charges.

  The Nuclear Waste Policy Act of 1982 establishes that the
federal government (through the Department of Energy (DOE)) is
responsible for the disposal of spent nuclear fuel. The federal
government requires NEP to pay a fee based on its share of the
net generation from the Millstone 3 and Seabrook 1 nuclear units.
NEP is recovering this fee through its fuel clause. Similar costs
are incurred by the Vermont Yankee nuclear generating unit. These
costs are billed to NEP and also recovered from customers through
NEP's fuel clause. Ruling on a lawsuit brought against the DOE by
numerous utilities and state regulatory commissions, the Court of
Appeals for the District of Columbia (Court) held that the DOE is
obligated to begin disposing of utilities' spent nuclear fuel by
January 31, 1998. The DOE failed to meet this deadline. The
utilities, including the operators of the units in which NEP has
an obligation, are assessing their future options. In February
1998, Maine Yankee petitioned the Court to compel the DOE to
remove Maine Yankee's spent fuel from the plant site.

  Nuclear Insurance
  The Price-Anderson Act limits the amount of liability claims
that would have to be paid in the event of a single incident at a
nuclear plant to $8.9 billion (based upon 110 licensed reactors).
The maximum amount of commercially available insurance coverage

<PAGE>
to pay such claims is $200 million. The remaining $8.7 billion
would be provided by an assessment of up to $79.3 million per
incident levied on each of the participating nuclear units in the
United States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. The maximum assessment,
which was most recently adjusted in 1993, is adjusted for
inflation at least every five years. NEP's current interest in
the Yankees (excluding Yankee Atomic), Millstone 3, and Seabrook
1 would subject NEP to a $58.0 million maximum assessment per
incident. NEP's payment of any such assessment would be limited
to a maximum of $7.3 million per incident per year. As a result
of the permanent cessation of power operation of the Yankee
Atomic plant, Yankee Atomic has received from the NRC a partial
exemption from obligations under the Price-Anderson Act. However,
Yankee Atomic must continue to maintain $100 million of
commercially available nuclear insurance coverage. Connecticut
Yankee and Maine Yankee have filed with the NRC for similar
exemptions.

  Each of the nuclear units in which NEP has an ownership
interest also carries nuclear property insurance to cover the
costs of property damage, decontamination or premature
decommissioning, and workers' claims resulting from a nuclear
incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units
covered by this insurance occurring in a prior six-year period
exceed the accumulated funds available. NEP's maximum potential
exposure for these assessments, either directly, or indirectly
through purchased power payments to the Yankees, is approximately
$8 million per year.

  6. Town of Norwood dispute
  In April 1997, the Town of Norwood, Massachusetts filed a
lawsuit against NEP in the United States District Court for the
District of Massachusetts. NEP is a wholesale power supplier for
Norwood pursuant to rates approved by the FERC. Norwood alleges
that NEP's proposed divestiture of its power generation assets
would violate the terms of a 1983 power contract which settled an
antitrust lawsuit brought by Norwood against NEP. Norwood also
alleges that NEP's proposed divestiture plan and recovery of
stranded investment costs contravene federal antitrust laws.
Norwood seeks an injunction enjoining the divestiture and an
unspecified amount of treble damages (a specific claim for $450
million was withdrawn). Norwood's motion for a preliminary
injunction of the divestiture was denied on September 8, 1997. On
November 21, 1997, Norwood filed an amended complaint making new
allegations relating to the sale of NEP's generating assets and
naming as additional defendants, NEES, USGen and USGen's
affiliate, PG&E. NEP continues to believe that its divestiture
plan will promote competition in the wholesale power generation
market and that it has met and will continue to meet its
contractual commitments to Norwood. On January 9, 1998, the
defendants filed a motion to dismiss the lawsuit.


<PAGE>
  7. Hydro-Quebec arbitration
  In 1996, various New England utilities which are members of
the New England Power Pool, including NEP, submitted a dispute to
arbitration regarding their Firm Energy Purchased Power Contract
with Hydro-Quebec. In June 1997, Hydro-Quebec presented a damage
claim of approximately $37 million for past damages, of which
NEP's share would have been approximately $6 to $9 million. The
claims involved a dispute over the components of a pricing
formula and additional costs under the contract. With respect to
ongoing claims, NEP had been paying Hydro-Quebec the higher
amount (additional costs of approximately $3 million per year)
since July 1996 under protest and subject to refund. In October
1997, an arbitrator ruled in favor of the New England utilities
in all respects. NEP has made a demand for refund. Hydro-Quebec
has not yet refunded any monies and has appealed the decision. On
November 9, 1997, NEP and the other utilities began a second
arbitration to enforce the first decision. Refunds received from
Hydro-Quebec will be passed on to customers through NEP's fuel
clause.

  Note E - Employee Benefits

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


<PAGE>
Net pension cost for 1997, 1996, and 1995 included the following
components:

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)        1997            1996           1995
                                                 --------        --------       --------
<S>                                                           <C>                    <C>            <C>
Service cost - benefits earned during
  the period                                     $ 15,019        $ 14,918            $ 14,167
Plus (less):
 Interest cost on projected benefit obligation     52,497          51,461              54,821
 Return on plan assets at expected long-term
  rate                                            (55,606)        (52,085)            (49,691)
 Amortization                                       1,580           2,887               5,589
                                                 --------        --------            --------
  Net pension cost                               $ 13,490        $ 17,181            $ 24,886
                                                 --------        --------            --------
  Actual return on plan assets                   $130,000        $ 91,571            $130,979
                                                 --------        --------            --------
</TABLE>

<TABLE>
<CAPTION>
Year ended December 31                      1998             1997              1996           1995
                                           -----            -----             -----          -----
<S>                                          <C>              <C>               <C>            <C>
Assumptions used to determine
  pension cost:
 Discount rate                             6.75%            7.25%             7.25%          8.25%
 Average rate of increase in future
  compensation levels                      4.13%            4.13%             4.13%          4.63%
 Expected long-term rate of return
  on assets                                8.50%            8.50%             8.50%          8.75%
</TABLE>

  The decrease in 1996 costs reflects additional amounts
recorded in the fourth quarter of 1995 related to certain
supplemental benefit changes.


<PAGE>
  The following table sets forth the retirement plans' funded
status:

<TABLE>
<CAPTION>
At December 31 (millions of dollars)    1997                    1996
                        -----------------------------------------------------
                                 Regular Supplemental   Regular  Supplemental
                                  Plans      Plans        Plans      Plans
                                  -----      -----        -----      -----
<S>                                            <C>          <C>        <C>       <C>
Benefits earned
Actuarial present value
 of accumulated benefit liability:
  Vested                           $647       $ 51         $640       $ 47
  Nonvested                          18          2           19          1
                                   ----       ----         ----       ----
   Total                           $665       $ 53         $659       $ 48
                                   ----       ----         ----       ----
Reconciliation of funded status
Actuarial present value of
 projected benefit liability       $757       $ 62         $753       $ 54
Unrecognized prior service costs     (8)         -           (9)         -
FAS No. 87 transition liability
 not yet recognized (amortized)      (1)        (3)          (1)        (3)
Net gain (loss) not yet
 recognized (amortized)              61         (9)          40         (3)
Additional minimum liability
 recognized                           -          4            -          3
                                   ----       ----         ----       ----
                                    809         54          783         51
                                   ----       ----         ----       ----
Pension fund assets at fair value   834          -          812          -
FAS No. 87 transition asset
 not yet recognized (amortized)      (8)         -          (10)         -
                                   ----       ----         ----       ----
                                    826          -          802          -
                                   ----       ----         ----       ----
Accrued pension/(prepaid)
 payments recorded on books        $(17)      $ 54         $(19)      $ 51
                                   ----       ----         ----       ----
</TABLE>

    The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates from 1998 and 1997,
respectively, and the 1983 Group Annuity Mortality table.

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


<PAGE>
    In addition to its regular pension funds shown in the table
above, NEES and its subsidiaries have a separate trust fund,
commonly referred to as a Rabbi Trust, for certain supplemental
pensions and deferred compensation for key executives and
employees. The Rabbi Trust is currently invested in municipal
bonds, equities, and NEES shares, and was invested in short-term
investments and NEES shares in 1996. At December 31, 1997 and
1996, the Rabbi Trust held 148,875 and 102,957 NEES shares,
respectively, accounted for as treasury stock. At the end of 1997
and 1996, the difference between cost and the market value of
investments, other than NEES shares, in the Rabbi Trust was
approximately $4.8 million, after tax, and $0, respectively. The
market value of such external investments was $53 million and $45
million at December 31, 1997 and 1996, respectively.

    2. Postretirement benefit plans other than pensions (PBOPs)
    The NEES subsidiaries provide health care and life insurance
coverage to eligible retired employees. Eligibility is based on
certain age and length of service requirements and in some cases
retirees must contribute to the cost of their coverage.

The total cost of PBOPs for 1997, 1996, and 1995 included the
following components:

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)        1997      1996       1995
                                                 --------  --------   --------
<S>                                                             <C>        <C>       <C>
Service cost - benefits earned during
  the period                                     $  6,527  $  6,794   $  7,137
Plus (less):
 Interest cost on accumulated benefit
  obligation                                       24,249    24,667     29,377
 Return on plan assets at expected
  long-term rate                                  (16,397)  (12,958)    (9,742)
 Amortization                                      11,110    13,099     16,204
                                                 --------  --------   --------
   Net postretirement benefit cost               $ 25,489  $ 31,602   $ 42,976
                                                 --------  --------   --------
   Actual return on plan assets                  $ 38,210  $ 24,881   $ 29,054
                                                 --------  --------   --------
</TABLE>

<TABLE>
<CAPTION>
Year ended December 31                             1998   1997    1996    1995
                                                 ------ ------  ------  ------
<S>                                                        <C>     <C>     <C>       <C>
Assumptions used to determine
  postretirement benefit cost:
 Discount rate                                    6.75%  7.25%   7.25%   8.25%
 Expected long-term rate of return on assets      8.25%  8.25%   8.25%   8.50%
 Health care cost rate - 1995 to 1999             5.25%  8.00%   8.00%   8.50%
 Health care cost rate - 2000 to 2004             5.25%  6.25%   6.25%   8.50%
 Health care cost rate - 2005 and beyond          5.25%  5.25%   5.25%   6.25%
</TABLE>


<PAGE>
The following table sets forth benefits earned and the plans' funded status:

<TABLE>
<CAPTION>
At December 31 (millions of dollars)                           1997       1996
                                                             ------     ------
<S>                                                                        <C>       <C>
Accumulated postretirement benefit obligation:
 Retirees                                                     $ 216      $ 236
 Fully eligible active plan participants                         28         24
 Other active plan participants                                 104        109
                                                             ------     ------
   Total benefits earned                                        348        369
Unrecognized prior service costs                                 (1)        (1)
Unrecognized transition obligation                             (276)      (294)
Net gain not yet recognized                                     153        101
                                                             ------     ------
                                                                224        175
                                                             ------     ------
Plan assets at fair value                                       239        202
                                                             ------     ------
Prepaid postretirement benefit costs recorded on books        $  15      $  27
                                                             ------     ------
</TABLE>

  The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates in effect for 1998 and 1997,
respectively.

  The assumptions used in the health care cost trends have a
significant effect on the amounts reported. Increasing the
assumed rates by 1 percent in each year would increase the
accumulated postretirement benefit obligation as of December 31,
1997 by approximately $42 million and the net periodic cost for
1997 by approximately $5 million.

  The NEES subsidiaries fund the annual tax-deductible
contributions. Plan assets are invested in equity and debt
securities and cash equivalents.

  3. Stock-based compensation
  At December 31, 1997, NEES has three stock-based compensation
plans and measures its compensation cost for those plans using
the method of accounting prescribed by Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees,
and related interpretations. The compensation cost that has been
charged against income for these plans was $3.3 million, $3.7
million, and $1.6 million for 1997, 1996, and 1995, respectively.
If compensation cost for stock-based compensation had been
accounted for under Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based Compensation, the 1997 cost
figures shown above would have been slightly smaller.


<PAGE>
  Note F - Income Taxes

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

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)              1997          1996           1995
                                               --------         --------            --------
<S>                                                 <C>              <C>                 <C>
Income taxes charged to operations             $152,024         $139,199            $128,340
Income taxes charged to "Other income"           (7,268)          (3,018)                762
                                               --------         --------            --------
  Total income taxes                           $144,756         $136,181            $129,102
                                               --------         --------            --------
</TABLE>

  Total income taxes, as shown above, consist of the following components:

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)              1997          1996           1995
                                               --------         --------            --------
<S>                                                 <C>              <C>                 <C>
Current income taxes                           $175,934         $166,509            $105,046
Deferred income taxes                           (29,260)         (28,652)             25,578
Investment tax credits, net                      (1,918)          (1,676)             (1,522)
                                               --------         --------            --------
  Total income taxes                           $144,756         $136,181            $129,102
                                               --------         --------            --------
</TABLE>

  Total income taxes, as shown above, consist of federal and state components
as follows:

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)              1997          1996           1995
                                               --------         --------            --------
<S>                                                 <C>              <C>                 <C>
Federal income taxes                           $118,317         $111,573            $103,503
State income taxes                               26,439           24,608              25,599
                                               --------         --------            --------
  Total income taxes                           $144,756         $136,181            $129,102
                                               --------         --------            --------
</TABLE>

  Investment tax credits of subsidiaries are deferred and
amortized over the estimated lives of the property giving rise to
the credits. Although investment tax credits were generally
eliminated by the 1986 tax legislation, additional carryforward
amounts continue to be recognized.

  With regulatory approval, the subsidiaries have adopted
comprehensive interperiod tax allocation (normalization) for
temporary book/tax differences.


<PAGE>
  Total income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:

<TABLE>
<CAPTION>
Year ended December 31 (thousands of dollars)              1997           1996           1995
                                             --------            --------            --------
<S>                                                         <C>            <C>            <C>
Computed tax at statutory rate               $131,989            $123,053            $119,892
Increases (reductions) in tax resulting from:
 Reversal of deferred taxes recorded
  at a higher rate                             (2,216)             (2,175)             (3,306)
 Amortization of investment tax credits        (4,469)             (4,347)             (4,443)
 State income tax, net of federal income
  tax benefit                                  17,185              15,995              16,639
 All other differences                          2,267               3,655                 320
                                             --------            --------            --------
   Total income taxes                        $144,756            $136,181            $129,102
                                             --------            --------            --------
</TABLE>

The following table identifies the major components of total deferred income
taxes:

<TABLE>
<CAPTION>
At December 31 (millions of dollars)               1997           1996
                                                 ------         ------
<S>                                                                <C>            <C>
Deferred tax asset:
 Plant related                                   $   99         $  110
 Investment tax credits                              39             37
 All other                                          152            143
                                                 ------         ------
                                                    290            290
                                                 ------         ------
Deferred tax liability:
 Plant related                                     (821)          (811)
 Equity AFDC                                        (51)           (53)
 All other                                         (138)          (177)
                                                 ------         ------
                                                 (1,010)        (1,041)
                                                 ------         ------
 Net deferred tax liability                      $ (720)        $ (751)
                                                 ------         ------
</TABLE>

  There were no valuation allowances for deferred tax assets
deemed necessary.

  Federal income tax returns for NEES and its subsidiaries have
been examined and reported on by the Internal Revenue Service
through 1993.

  Note G - Short-Term Borrowings and Other Current Liabilities

  At December 31, 1997, NEES and its consolidated subsidiaries
had lines of credit and standby bond purchase facilities with
banks totaling $1.2 billion. These lines and facilities were used
at December 31, 1997 for liquidity support for $252 million of

<PAGE>
commercial paper borrowings and $372 million of NEP mortgage
bonds in tax-exempt commercial paper mode (see Note H). Fees are
paid on the lines and facilities in lieu of compensating
balances. The weighted average rate on outstanding short-term
borrowings was 5.66 percent at December 31, 1997. The fair value
of the NEES subsidiaries' short-term debt equals carrying value.

The components of other current liabilities are as follows:

<TABLE>
<CAPTION>
At December 31 (thousands of dollars)              1997           1996
                                               --------       --------
<S>                                                                <C>            <C>
Accrued wages and benefits                     $ 58,281       $ 37,872
Rate adjustment mechanisms                       27,152         50,614
Customer deposits                                11,059         10,595
Other                                            23,510         10,501
                                               --------       --------
                                               $120,002       $109,582
                                               --------       --------
</TABLE>

  Note H - Long-Term Debt

  Substantially all of the properties of NEP, Massachusetts
Electric, and Narragansett Electric are subject to the lien of
mortgage indentures under which mortgage bonds have been issued.

The aggregate payments to retire maturing long-term debt are as
follows:

<TABLE>
<CAPTION>
(thousands of dollars)              1998      1999      2000      2001    2002
                                 -------   -------  --------   ------- -------
<S>                                            <C>       <C>       <C>     <C>       <C>
Maturing long-term debt:
 NEP*                            $50,000   $10,000  $ 55,000   $     - $     -
 Other NEES subsidiaries          26,470    24,480    37,485     6,495  41,500
Mandatory prepayments:
 Hydro-Transmission companies     11,520    11,520    11,520    10,790  10,440
 NEEI**                                -    17,000    30,000    30,000  45,000
 NERC***                           1,920     2,280     2,280     2,280   2,280
                                 -------   -------  --------   ------- -------
  Total                          $89,910   $65,280  $136,285   $49,565 $99,220
                                 -------   -------  --------   ------- -------


*  See Note C for information on potential NEP bond defeasance.
** NEEI debt retired on February 5, 1998.
***                                $29 million of NERC debt will be retired in 1998, upon completion of the sale of the
                                   nonnuclear generating business to USGen.
</TABLE>

  The terms of $372 million of variable rate PCRBs
collateralized by NEP mortgage bonds at December 31, 1997 require
NEP to reacquire the bonds under certain limited circumstances.
At December 31, 1997, interest rates on NEP's variable rate bonds
ranged from 3.70 percent to 4.85 percent. Also, at December 31,

<PAGE>
1997, interest rates on NEEI's debt ranged from 6.11 percent to
6.17 percent.

  At December 31, 1997, the NEES subsidiaries' long-term debt
had a carrying value of approximately $1,577,000,000 and a fair
value of approximately $1,657,000,000. The fair value of debt
that reprices frequently at market rates approximates carrying
value. The fair market value of the NEES subsidiaries' long-term
debt was estimated based on the quoted prices for similar issues
or on the current rates offered to the NEES companies for debt of
the same remaining maturity.

  Note I - Preferred Stock Tender Offer

  On December 19, 1997, NEES purchased, pursuant to a tender
offer, preferred stock of its subsidiaries with an aggregate par
value of $87 million. These purchases resulted in an after-tax
charge to net income of approximately $5 million.

  Note J - Supplementary Quarterly Financial Information
(unaudited)

<TABLE>
<CAPTION>
1997 Quarter ended                 Mar. 31             June 30            Sept. 30             Dec. 31
                                  --------            --------            --------            --------
<S>                                              <C>                 <C>                           <C.            <C>
(thousands of dollars, except per share amounts)

Operating revenue                 $638,146            $577,625            $628,606            $658,214
Operating income                  $ 94,962            $ 66,583            $104,524            $100,792
Net income                        $ 61,820            $ 32,232            $ 67,746            $ 58,240
Net income per average common
 share, basic and diluted         $    .95            $    .50            $   1.04            $   .90*
                                  --------            --------            --------            --------
</TABLE>

<TABLE>
<CAPTION>
1996 Quarter ended                 Mar. 31             June 30            Sept. 30             Dec. 31
                                  --------            --------            --------             -------
<S>                                              <C>                 <C>                           <C.            <C>
(thousands of dollars, except per share amounts)

Operating revenue                 $586,220            $551,110            $616,857            $596,511
Operating income                  $ 94,955            $ 69,133            $ 97,384            $ 86,646
Net income                        $ 61,496            $ 35,001            $ 64,375            $ 48,064
Net income per average common
 share, basic and diluted         $    .95            $    .54            $    .99            $    .74
                                  --------            --------            --------             -------
<FN>
* See "Overview of Financial Results" and "Operating Revenue" sections of
Financial Review for a discussion of factors contributing to the fourth
quarter increase in net income over prior year.
</FN>
</TABLE>


<PAGE>
  Report of Management

  The management of New England Electric System is responsible
for the integrity of the consolidated financial statements
included in this Annual Report. The financial statements were
prepared in accordance with generally accepted accounting
principles using management's informed best estimates and
judgments where appropriate to fairly present the financial
condition of the NEES companies and their results of operations.
The information included elsewhere in this report is consistent
with the financial statements.

  The NEES companies maintain an accounting system and system of
internal controls which are designed to provide reasonable
assurance as to the reliability of the financial records, the
protection of assets, and the prevention of any material
misstatement of the financial statements. The NEES companies'
accounting controls have been designed to provide reasonable
assurance that errors or irregularities, which could be material
to the financial statements, are prevented or detected by
employees within a timely period as they perform their assigned
functions. The NEES companies' internal auditing staff
independently assesses the effectiveness of internal controls and
recommends improvements where appropriate.

  Coopers & Lybrand L.L.P., the NEES companies' independent
accountants, are engaged to audit and express their opinion on
the financial statements. Their audit includes a review of
internal controls to the extent required by generally accepted
auditing standards.

  The Audit Committee, composed solely of outside directors,
meets periodically with management, the internal auditor, and the
independent accountants to ensure that each is carrying out its
responsibilities and to discuss auditing, internal accounting
control, and financial reporting matters. Both the internal
auditor and the independent accountants have free access to the
Audit Committee, without management present, to discuss the
results of their audit work.

s/ Richard P. Sergel            s/ Michael E. Jesanis
Richard P. Sergel               Michael E. Jesanis
President and                   Senior Vice President
Chief Executive Officer         and Chief Financial Officer



<PAGE>
  Report of Independent Accountants

  To the Board of Directors and Shareholders of New England
Electric System:

  We have audited the accompanying consolidated balance sheets
and consolidated statements of capitalization of New England
Electric System and subsidiaries (the Company) as of December 31,
1997 and 1996 and the related consolidated statements of income,
retained earnings and cash flows for each of the three years in
the period ended December 31, 1997. These financial statements
are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.

  We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

  In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of the Company as of December 31, 1997 and
1996, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December
31, 1997, in conformity with generally accepted accounting
principles.

Boston, Massachusetts                        s/ Coopers & Lybrand L.L.P.
March 2, 1998


<PAGE>
Shareholder information

For shareholder information or assistance, write or call
Shareholder Services at:

New England Electric System
Shareholder Services
P.O. Box 770
Westborough, MA 01581

Toll-free number: 1-800-466-7215
Local number: (508) 389-4900
Fax: (508) 836-0276
E-mail: shrser@neesnet.com

Dividend reinvestment

Shareholders of New England Electric System common shares who
hold their shares in registered form are eligible to participate
in the Dividend Reinvestment and Common Share Purchase Plan. The
Plan provides participants the opportunity to reinvest their
dividends and send in optional cash payments to purchase
additional common shares. These shares will be newly issued
shares or shares purchased in the open market. The Company will
pay all brokerage commissions and service charges associated with
the Plan. For more information on the Plan, please contact
Shareholder Services at our toll-free number listed above.

Direct deposit of dividends

Shareholders who hold New England Electric System common shares
in their own name may request to have their dividends directly
deposited into their checking or savings account. This service is
provided without fees. If you participate in Direct Deposit, you
will receive a credit advice for your records. To sign up for
this service, please call Shareholder Services on our toll-free
number to request an authorization form.

Change of address

Please contact Shareholder Services on our toll-free number to
notify us of your address change.

Form 10-K

Copies of the Annual Report on Form 10-K to the Securities and
Exchange Commission for 1997 are available upon request at no
charge by writing to the address at left.

Annual meeting

The annual meeting of New England Electric System will be held at
Mechanics Hall in Worcester, MA on April 28, 1998 at 10:30 a.m.


<PAGE>
Stock exchange listings

New England Electric System common shares are listed on the New
York Stock Exchange and the Boston Stock Exchange under the
symbol NES.

Transfer agent

Certificates for transfer should be mailed to our transfer agent
at:
Bank of Boston, c/o Boston EquiServe
P.O. Box 8040, Boston, MA 02266-8040

Note

NEES intends to transfer its record keeping and stock transfer
functions to Bank of New York in 1998. A notice will be sent to
all shareholders when the conversion date is determined.

<TABLE>
<CAPTION>
New England Electric System common shares

                                1997                         1996
                                ----                         ----
                      Price Range ($)              Price Range ($)
                      --------------               --------------
                        High     Low    Dividend    High      Low    Dividend
                                      Declared $                    Declared $
----------------------------------------------------------------------------------------
<S>                      <C>      <C>      <C>       <C>      <C>       <C>
First Quarter        35.625    33.375     .590    40.625   36.125      .590
Second Quarter       37.125    33.250     .590    38.875   32.875      .590
Third Quarter        39.6875   36.250     .590    36.375   31.125      .590
Fourth Quarter       43.3125   37.250     .590    35.625   31.000      .590
</TABLE>

The total number of shareholders at December 31, 1997 was 47,978.


<PAGE>
[MAP OF SERVICE AREAS]

NEES Subsidiaries
As of March 1, 1998

Massachusetts Electric Company
25 Research Drive, Westborough, Massachusetts 01582

The Narragansett Electric Company
280 Melrose Street, Providence, Rhode Island 02901

Granite State Electric Company
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766

Nantucket Electric Company
25 Research Drive, Westborough, Massachusetts 01582

AllEnergy Marketing Company, L.L.C.
95 Sawyer Road, Waltham, Massachusetts 02154

Granite State Energy, Inc.
4 Park Street, Concord, New Hampshire 03301

NEES Energy, Inc.
25 Research Drive, Westborough, Massachusetts 01582

Narragansett Energy Resources Company
280 Melrose Street, Providence, Rhode Island 02901

New England Power Company
25 Research Drive, Westborough, Massachusetts 01582

NEES Communications, Inc.
25 Research Drive, Westborough, Massachusetts 01582

NEES Global Transmission, Inc.
25 Research Drive, Westborough, Massachusetts 01582

New England Electric Transmission Corporation
4 Park Street, Concord, New Hampshire 03301

New England Hydro-Transmission Corporation
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766

New England Hydro-Transmission Electric Company, Inc.
25 Research Drive, Westborough, Massachusetts 01582

New England Power Service Company
25 Research Drive, Westborough, Massachusetts 01582


<PAGE>
[PHOTO OF EXECUTIVE TEAM]

NEES Officers
As of March 1, 1998

Richard P. Sergel
President and Chief Executive Officer

Alfred D. Houston*
Executive Vice President

Cheryl A. LaFleur
Senior Vice President, General Counsel, and Secretary

Michael E. Jesanis
Senior Vice President and Chief Financial Officer

David C. Kennedy
Vice President

John G. Cochrane
Treasurer

Executive Officers
Of Major Subsidiaries

Lawrence E. Bailey
President of New England Power Company

William H. Heil
Chairman and Chief Executive Officer of
AllEnergy Marketing Company, L.L.C.

Robert L. McCabe
Chairman of the electricity delivery subsidiaries (Massachusetts
Electric Company, Nantucket Electric Company, The Narragansett
Electric Company, and Granite State Electric Company)

Lawrence J. Reilly
President and Chief Executive Officer of the electricity delivery
subsidiaries
Executive Team Photo

1.Lawrence J. Reilly
2.Robert L. McCabe
3.Richard P. Sergel
4.John W. Rowe (resigned as president and CEO effective 2/6/98)
5.Alfred D. Houston
6.Michael E. Jesanis
7.William H. Heil
8.Cheryl A. LaFleur
9.Lawrence E. Bailey

Not pictured
John G. Cochrane, David C. Kennedy


<PAGE>
* The NEES board of directors has announced its intention to
elect Mr. Houston NEES chairman following the April 1998 annual
meeting.

NEES Directors
As of March 1, 1998

Joan T. Bok
Chairman of the Board, New England Electric System, Westborough,
Massachusetts
- Corporate Responsibility Committee
- Executive Committee

William M. Bulger
President, University of Massachusetts, Boston, Massachusetts
- Audit Committee

Alfred D. Houston*
Executive Vice President, New England Electric System,
Westborough, Massachusetts
- Executive Committee

Paul L. Joskow
Chairman of the Department of Economics, Massachusetts Institute
of Technology, Cambridge, Massachusetts
- Audit Committee
- Executive Committee
- Nominating Committee

John M. Kucharski
Chairman, President, and Chief Executive Officer, EG&G, Inc.,
Wellesley, Massachusetts
- Compensation Committee

Edward H. Ladd
Chairman, Standish, Ayer & Wood, Inc., investment counselors,
Boston, Massachusetts
- Executive Committee
- Nominating Committee

Joshua A. McClure
Former President, American Custom Kitchens, Inc., Providence,
Rhode Island
- Corporate Responsibility Committee

George M. Sage
President and Treasurer, Bonanza Bus Lines, Inc., Providence,
Rhode Island
- Compensation Committee
- Executive Committee
- Nominating Committee

Richard P. Sergel
President and Chief Executive Officer, New England Electric
System, Westborough, Massachusetts
- Corporate Responsibility Committee
- Executive Committee

<PAGE>
Charles E. Soule
Retired President and Chief Executive Officer, Paul Revere
Insurance Group, Worcester, Massachusetts
- Audit Committee

Anne Wexler
Chairman, The Wexler Group, management consultants, Washington,
D.C.
- Compensation Committee
- Executive Committee
- Nominating Committee

James Q. Wilson
Professor Emeritus, University of California at Los Angeles
- Corporate Responsibility Committee

James R. Winoker
Chief Executive Officer, Belvoir Properties, Inc., Providence,
Rhode Island
- Audit Committee
- Corporate Responsibility Committee

The name "New England Electric System" means the trustee or
trustees for the time being (as trustee or trustees but not
personally) under an Agreement and Declaration of Trust dated
January 2, 1926, as amended, which is hereby referred to, and a
copy of which, as amended, has been filed with the Secretary of
the Commonwealth of Massachusetts. Any agreement, obligation, or
liability made, entered into, or incurred by or on behalf of New
England Electric System binds only its trust estate, and no
shareholder, director, trustee, officer, or agent thereof assumes
or shall be held to any liability therefor.

This report is not to be considered as an offer to sell or buy or
solicitation of an offer to sell or buy any security.

[PHOTO OF NEES DIRECTORS APPEARS AT BOTTOM OF INSIDE BACK COVER]
NEES directors shown in September 1997 photo are, left to right,
James R. Winoker, James Q. Wilson, George M. Sage, Anne Wexler,
Joshua A. McClure, John W. Rowe (resigned effective 2/6/98),
Edward H. Ladd, Joan T. Bok, Paul L. Joskow, William M. Bulger,
John M. Kucharski, and Charles E. Soule. (Current directors not
pictured are Alfred D. Houston and Richard P. Sergel.)

* See footnote of previous page.

<PAGE>
[NEES LOGO]

New England Electric System
25 Research Drive
Westborough, Massachusetts 01582
Telephone 508.389.2000
www.nees.com