Annual Report 2002

New England Power Company



















                                                                                           [National Grid logo]

New England Power Company
25 Research Drive
Westborough, Massachusetts 01582

Directors
(As of April 1, 2002)


L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission

John G. Cochrane
Vice President of the Company and Chief Financial Officer and Vice President of National Grid USA

Peter G. Flynn
President of the Company

Michael E. Jesanis
Vice President of the Company and Executive Vice President of National Grid USA

Robert G. Powderly
Vice President of National Grid USA

Lawrence J. Reilly
Vice President and General Counsel of the Company and Senior Vice President,
General Counsel, and Secretary of National
Grid USA

Terry L. Schwennesen
Vice President of the Company

Richard P. Sergel
President and Chief Executive Officer of
National Grid USA

Philip R. Sharp
Lecturer, Harvard University, John F. Kennedy School of Government



Officers
(As of April 1, 2002)




Peter G. Flynn
President of the Company

John G. Cochrane
Vice President of the Company and of an affiliate, President of certain affiliates,
Treasurer of certain affiliates, and
Vice President and Chief Financial Officer of National Grid USA

Michael E. Jesanis
Vice President of the Company and Executive Vice President of National Grid USA

Lawrence J. Reilly
Vice President and General Counsel of the Company and
Senior Vice President, General Counsel, and Secretary of National
Grid USA

Marc F. Mahoney
Vice President of the Company and of certain affiliates

James S. Robinson
Vice President and Treasurer of the Company and of certain affiliates

Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates

Herb Schrayshuen
Vice President of the Company and of certain affiliates

Terry L. Schwennesen
Vice President of the Company

Gregory A. Hale
Clerk of the Company and of certain affiliates, and Assistant Secretary
or Assistant Clerk of certain affiliates

Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates and Secretary or Clerk of certain affiliates

Geraldine M. Zipser
Assistant Clerk of the Company and of certain affiliates, and Secretary or Clerk of certain affiliates

Robert G. Seega
Assistant Treasurer of the Company and of certain affiliates

Jennifer K. Zschokke
Assistant Treasurer of the Company and Vice President and Treasurer of certain affiliates

Edward A. Capomacchio
Controller of the Company and of certain affiliates and Vice President of an affiliate



Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock
Bank of New York, New York, New York

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

Financial Review

Regulatory Environment and Accounting Implications
Prior to divesting  substantially all of its nonnuclear  generation  business in 1998, the Company was the wholesale supplier
of the electric energy requirements to its retail distribution  affiliates as well as unaffiliated  customers.  The Company’s
all-requirements  contracts with its affiliated distribution  companies,  as well as with some unaffiliated  customers,  were
generally  terminated  pursuant to  settlement  agreements  and tariff  provisions  in 1998.  However,  the Company  remained
obligated to provide  transition  power supply service to new customer load in Rhode Island at the standard offer price,  but
did not have a regulatory  agreement  that  necessarily  allowed  full  recovery of the costs of such  standard  offer power.
Consequently,  the  Company  was at risk for the  difference  between  the actual  cost of serving  this load and the revenue
received  from this  obligation.  For the year ended March 31,  2002,  the impact on the  Company’s  financial  position  was
immaterial.  Effective December 1, 2001, a third party assumed the responsibility for providing  transitional  standard offer
power service in Rhode Island, and the Company’s obligation terminated.

Under  settlement  agreements,  the Company is permitted to recover costs associated with its former  generating  investments
and related  contractual  commitments that were not recovered through the sale of those investments  (stranded costs).  These
costs  are  recovered  from the  Company’s  wholesale  customers  with whom it has  settlement  agreements  through  contract
termination  charges  (CTC) that the  affiliated  wholesale  customers  recover  through  delivery  charges  to  distribution
customers.  The recovery of the Company’s stranded costs (including Montaup Electric  Company’s  (Montaup),  a former Eastern
Utilities  Associates (EUA) subsidiary) is divided into several categories.  The Company’s  unrecovered costs associated with
generating  plants (nuclear and nonnuclear) and most regulatory  assets will be fully recovered through the CTC by the end of
2009 and earn a return on equity (ROE) averaging 9.7 percent.  The Company’s  obligation  related to the above-market cost of
purchased  power  contracts  and nuclear  decommissioning  costs are  recovered  through  the CTC as such costs are  actually
incurred.  As the CTC rate declines,  the Company,  under certain of the settlement  agreements,  earns  incentives  based on
successful  mitigation of its stranded costs.  These incentives  supplement the Company’s ROE. Until such time as the Company
divests its operating nuclear interests,  the Company will share with customers,  through the CTC, 80 percent of the revenues
and operating costs related to the units, with shareholders retaining the balance.

In conjunction with the divestiture,  the Company transferred to the buyer of its nonnuclear  generating business (the buyer)
its entitlement to power procured under several  long-term  contracts in exchange for fixed monthly  payments by the Company.
Similar to the Company,  Montaup also  transferred its purchased  power  obligations as part of the divestiture and in return
agreed to make fixed monthly  payments.  These fixed monthly payments by the Company,  inclusive of Montaup’s share,  average
approximately  $11 million per month through  December 2009 toward the above-market  cost of those  contracts.  The liability
relating to purchased power obligations,  which is also reflected in regulatory  assets,  represents the net present value of
these fixed monthly payments.  At March 31, 2002, the net present value is approximately $659 million.  For certain contracts
which have been  formally  assigned to the buyer,  the Company has made lump sum payments  equivalent to the present value of
the monthly fixed payment  obligations of those  contracts  (approximately  $453 million),  which were separate from the $659
million figure referred to above.

FERC Proceedings

In general,  the  regulatory  structure and  regulations  which relate to the  Company's  business are in a period of major
change and  uncertainty.  Decisions  being made by the Federal  Energy  Regulatory  Commission  (FERC) and the  Independent
System  Operator-New  England  (ISO New  England)  will affect how the Company  does  business and whether it can enter new
endeavors.  The Company is currently  unable to determine  whether  these  proceedings  will have a material  impact on its
financial position or results of operations.

The FERC has been reviewing the development of regional  transmission  organizations (RTOs). The FERC has indicated that it
wants RTOs to have large geographic scope. In July and August, 2001, the FERC ordered National Grid USA and other New England parties
and  participants of the New York  Independent  System Operator (ISO),  and the  Pennsylvania-New  Jersey-Maryland  (PJM) ISO to
participate in a mediation  process to develop a proposal for a larger RTO. The FERC has not yet ruled on the  mediation  report
issued in September  2001.  Pending the ruling on the  mediation report,  the  transmission  owners have been working  toward a hybrid
RTO structure in which an  independent  transmission company would manage the transmission grid for the RTO and an independent market
administrator  would manage power markets for the RTO. However, it is not clear what sort of RTO structure will ultimately result
from these  negotiations.  In fact, based on a January 29, 2002 filing by the New York and New England ISOs to form their own RTO,
even the geographic scope of the RTO in which the Company will participate is still an open question.

In late 2001 and early 2002, the FERC convened an advanced rulemaking  proceeding to enable transmission  owners, such as the
Company,  and  generators  to  establish  standardized   procedures  and  agreements  concerning  the  way  generators  would
interconnect  with the transmission  grid. On April 24, 2002, the FERC issued proposed rules very favorable to generators and
unfavorable,  and, the Company  believes,  at times  unworkable,  for  transmission  owners.  The Company has submitted  comments
seeking significant  changes in the proposed rules. The FERC is expected to issue final rules later this year.

In 2001, the FERC began an advanced  rulemaking  procedure to address Standard Market Design regarding the buying and selling
of power.  In a December  2001 order,  the FERC  requested  that all  industry  segments  try to agree on a single  standards
setting  organization that would establish  national standard business  practices for the wholesale  electric  industry.  The
FERC has also solicited  comments on a wide range of issues,  including:  transmission  pricing,  pricing for electric energy
and capacity,  transmission planning,  generation dispatch, RTO governance,  market monitoring, long term generation adequacy
(including  installed  capacity or “ICAP”),  and  resolution  of “seams” - or  conflicting  practices or charges that inhibit
inter-regional  energy  transactions.  All of these  either  directly or  indirectly  affect the  Company’s  business.  It is
anticipated that the FERC will launch a formal notice of proposed rulemaking proceeding this summer.

NEPOOL and ISO New England have a separate  standard  market  design  initiative  which is proceeding in parallel to the FERC
initiative.  It is expected  that either New England  Power Pool  (NEPOOL) or ISO New England will file a proposal to conform
the  procedures  by which  energy  is  bought  and sold in New  England  to those  of PJM  with  the  FERC  this  summer  for
implementation by December 2002 or early 2003.

To the extent the Company wishes to pursue  opportunities to manage or to be a member of an independent  transmission company
or an RTO, with the  opportunity to propose  financial  incentives to deliver  greater value for customers and  shareholders,
the FERC rulings in the standard market design proceeding and other proceedings may have an impact on the ability to do so.

In June 2001, the FERC issued an order relating to (NEPOOL’s proposed  congestion  management and  multi-settlement  systems.
In the June Order,  the FERC found that "energy  uplift" costs (which had been about $9 million per month for NEPOOL in 2000)
should be allocated on the basis of reliance on the energy markets  administered by the ISO New England.  This would have the
effect of relieving  parties that procure  power under  bilateral  contracts  (such as the Company) from paying energy uplift
charges.  However,  the NEPOOL  Participants  Committee and ISO New England  submitted a filing in July 2001 that the Company
believed did not comport with the FERC's order.  The Company  protested the filing,  and received a favorable  order from the
FERC on February 15, 2002.  Nevertheless,  the NEPOOL Participants  Committee and ISO New England submitted another filing on
March 18, 2002 that the Company  believes  does not comport with the FERC's  orders,  and the Company has again filed another
protest.

On September 27, 2001, the FERC initiated a notice of proposed  rulemaking  regarding  affiliate standards of conduct in both
the electric and gas industries.  In its proposed rules,  the FERC proposed a broad definition of “energy  affiliate”,  which
would include its affiliate  National Grid USA Service  Company,  Inc.  (Service  Company) as well as the Company’s  electric
distribution  company affiliates.  The proposed rules would impose significant  restrictions on the ability of the Company to
interact with such “energy affiliates.” If not modified, the proposed rules could require significant  reorganization
for the Company and possibly  duplication of support  functions that the Company  depends on the Service Company to provide.

As previously  reported,  there has been litigation  regarding the FERC order to increase the ICAP deficiency charge to $8.75
per  kilowatt-month  (kW-month)  instead of the rate proposed by ISO New England of $0.17 per kW-month.  In June 2001,  after
significant  litigation  and a remand from the US Court of Appeals for the First  Circuit,  ISO New England made a Compliance
Filing with the FERC  proposing a compromise  ICAP regime,  including an ICAP  deficiency  charge of $4.87 per  kW-month.  On
September 28, 2001, the FERC issued an order refusing to apply  retroactively  the $8.75 per kW-month  deficiency  charge for
the period  January to June 2000. On November 20, 2001,  the FERC issued an order on rehearing of the August order  requiring
ISO New England to establish a prospective  ICAP regime (i.e.,  one under which utility ICAP purchase  requirements are known
in advance) in lieu of a  retrospective  requirement  with a cure  period.  It is unclear  what system will  replace the ICAP
regime in the future.  The issue of the appropriate ICAP deficiency  charge for the period January to July 2000, is currently
back before the US Court of Appeals for the First  Circuit for  resolution.  The FERC is also now  addressing  complaints  by
power marketers about how ICAP should have been charged for the period January to July 2000. Both of these  proceedings  will
likely affect the Company’s ICAP exposure.

Overview of Financial Results
Net income for the twelve months ended March 31, 2002 increased  approximately  $18 million  compared with the same period in
2001. The increase is primarily due to the adoption of Statement of Financial  Accounting  Standards No. 142  “Accounting for
Goodwill  and Other  Intangible  Assets”  (FAS 142),  effective  April 1, 2001,  which  requires  the  cessation  of goodwill
amortization  (see Note A-8).  Also  contributing  to the  increase in  earnings  is a decrease  in  interest  expense due to
decreased interest rates on variable-rate long-term debt and the refinancing of short-term debt.

Net income for the twelve months ended March 31, 2001  decreased  approximately  $13 million  compared with the twelve months
ended  December 31, 1999.  The decrease was primarily due to goodwill  amortization  from the merger of the Company’s  parent
with National  Grid Group plc and with EUA,  increased  purchased  power costs,  increased  interest  expense,  and decreased
mitigation  incentives.  These increases were partially  offset by increased  income as a result of Montaup being merged into
the Company on May 1, 2000 and increased earnings from nuclear operations.

Net income for the three months ended March 31, 2000  decreased  approximately  $6 million  compared  with the same period in
1999 primarily due to the elimination of certain  liabilities  related to open access  transmission  tariffs of approximately
$5 million in the first quarter of 1999.



Operating Revenue
Operating  revenue for the twelve months ended March 31, 2002,  decreased  approximately  $96 million  compared with the same
period in 2001. The decrease is primarily  attributable to reduced  kilowatthour (kWh) sales due to the sale of the Millstone
3 nuclear  generating unit and the effect of a refueling  outage at the Vermont Yankee nuclear power plant during the quarter
ended June 30, 2001. The decrease is also related to reduced CTC revenue due to fully  reconciling  true-up  mechanisms  that
allow the Company to adjust revenues  proportionately  with correlating  expenses.  Partially offsetting these decreases were
increased  transmission  revenues.  The transmission charge is a formula rate that recovers the Company’s actual costs plus a
return on investment.

Operating  revenue for the twelve months ended March 31, 2001 increased  approximately  $60 million  compared with the twelve
months ended  December 31, 1999.  The increase was due to increased  sales and rates related to  obligations  to new customer
load in Rhode Island,  and increased  unit  contract  sales from  partially  owned nuclear units that  experienced  refueling
outages in 1999. These increases were also affected by the merger with Montaup,  effective May 1, 2000.  Partially offsetting
these increases were decreased CTC revenues.

Operating  revenue for the three months  ended March 31, 2000  decreased  approximately  $33 million  compared  with the same
period  in  1999,  largely  due  to CTC  revenue  of  approximately  $21  million  from  The  Narragansett  Electric  Company
(Narragansett  Electric) in 1999 related to its access charge  overcollections.  This payment reduced Narragansett Electric’s
future CTC obligations.  This additional revenue in 1999 had a corresponding  impact to the amortization of CTC, discussed in
“Operating  Expenses”  below.  The decrease was also due to the  elimination  of certain  liabilities  related to open access
transmission  tariffs of $5 million in 1999.  This decrease was partially  offset by the impact of increased  standard  offer
rates  effective  January 1, 2000 and  increased  kWh sales in the three months ended March 31, 2000  compared  with the same
period in 1999.

Operating Expenses
Operating  expenses for the twelve months ended March 31, 2002 decreased  approximately  $94 million,  compared with the same
period in 2001.

Fuel for generation  expense for the twelve months ended March 31, 2002,  decreased  approximately $9 million,  compared with
the same period in 2001, primarily due to the sale of Millstone 3 and decreased fuel expense at the Wyman 4 plant.

Purchased power expense for the  twelve-month  period ended March 31, 2002 decreased  approximately  $9 million compared with
the same period in 2001.  The decreased  cost is attributed to reduced open market power  purchases to supply  standard offer
service in Rhode Island.  Effective  December 1, 2001 a third party  assumed the  responsibility  for providing  transitional
standard offer power service in Rhode Island, and the Company’s  obligation  terminated.  The decrease is partially offset by
increased  costs  attributed to a refueling  outage at Vermont  Yankee during the quarter ended June 30, 2001,  the refund of
excess nuclear  insurance and tax credits to Maine Yankee and  Connecticut  Yankee during the quarter ended December 31, 2000
and the inclusion of Montaup’s  purchased  power costs  throughout the fiscal year ended March,  2002 in comparison to eleven
months in fiscal year 2001.

Nuclear  operation and maintenance  expenses for the twelve months ended March 31, 2002 decreased  approximately  $29 million
compared  with the same  period in 2001 as a result of the sale of  Millstone  3.  Other  operating  expenses  for the twelve
months ended March 31, 2002 increased $2 million  compared with the same period in 2001,  primarily due to increased  pension
costs, partially offset by a decrease in administrative expenses caused by the sale of Millstone 3.

Depreciation  and  amortization  expenses for the twelve  months  ended March 31, 2002  decreased  approximately  $48 million
compared with the same period in 2001. This decrease is due to reduced nuclear  depreciation and  decommissioning  expense as
a result  of the  sale of  Millstone  3 in March  2001,  and the full  recovery  of the  Company’s  CTC-related  fixed  costs
associated with its generating plants and regulatory assets (excluding Montaup’s fixed costs) at the end of 2000.

Operating  expenses for the twelve months ended March 31, 2001 increased  approximately  $51 million compared with the twelve
months ended December 31, 1999.

Fuel for generation  increased  approximately  $2 million for the twelve months ended March 31, 2001 compared with the twelve
months ended December 31, 1999 primarily related to charges at the Wyman 4 generating plant.

Purchased  power  expenses  increased  approximately  $62 million  for the same time  period.  This  increase  was  primarily
attributed  to the  inclusion of  Montaup’s  purchased  power costs  effective  May 1, 2000,  increased  fuel prices,  and an
increase in standard offer  purchases  related to obligations to supply new customer load in Rhode Island,  partially  offset
by decreased purchased power charges from the Yankee Nuclear Power Companies  (Yankees).  Charges from Maine Yankee decreased
due to a refund for the termination of excess nuclear  insurance  coverage.  Vermont Yankee purchased power charges decreased
due to the effect of a refueling  outage during the quarter ended  December 31, 1999.  In addition,  purchased  power charges
from the Yankee Atomic  nuclear power plant  decreased as a result of the  completion  of the  purchased  power  contract and
final billing in June 2000.

Nuclear  operation and  maintenance  expenses  increased  approximately  $7 million  primarily due to the merger of Montaup’s
ownership  percentage of Millstone 3 with the Company’s  effective as of the merger date, as well as the effects of increased
expenses related to refueling outages and other maintenance at the Millstone 3 and Seabrook 1 nuclear generating units.

Other  nonnuclear  operation and maintenance  expenses  decreased  approximately  $5 million  compared with the twelve months
ended December 31, 1999 primarily due to reduced  pension and  postretirement  healthcare  expenses and reduced  transmission
costs.  These decreases were partially  offset by the receipt of a transmission  wheeling refund that reduced expense in June
1999.

Depreciation  and  amortization  expenses  decreased  approximately  $24 million for the twelve  months  ended March 31, 2001
compared with the twelve months ended December 31, 1999.  This decrease was primarily  related to decreased CTC  amortization
as a result of the full recovery of the Company’s  CTC-related  costs  associated  with its generating  plants and regulatory
assets  (excluding  Montaup’s) at the end of 2000. This decrease was partially  offset by the Company’s  payments to increase
the Millstone 3  decommissioning  trust fund to the level  prescribed in the Release and Settlement  Agreement with Northeast
Utilities (NU) (see the “Millstone 3” disclosure in the “Nuclear  units”  section),  as well as the effect of the addition of
Montaup’s ownership percentage of Millstone 3 effective as of the merger date.

Operating  expenses for the three months ended March 31, 2000,  decreased  approximately  $27 million  compared with the same
period in 1999.

The increase in fuel and purchased power expense of approximately  $5 million  reflected  increased  purchased power expenses
for standard offer requirements and increased kWh purchased.

Other operating  expenses in the three months ended March 31, 2000 decreased  approximately $3 million compared with the same
period in 1999 due to the  reimbursement  of start-up  costs from 1999 of the ISO New England in 2000.  Maintenance  expenses
decreased  approximately  $1 million as a result of reduced  expenses  at the  partially  owned  Millstone  3 and  Seabrook 1
nuclear generating facilities.

Depreciation  and  amortization  expenses  in the three  months  ended  March 31, 2000  decreased  approximately  $23 million
compared  with the same  period in 1999.  This  decrease  was due to  additional  CTC  amortization  in 1999  related  to the
additional payment of approximately $21 million by Narragansett Electric to the Company, discussed above.




Other Income and Expense
Other  income-net  for the twelve  months ended March 31, 2002  increased  approximately  $13 million  compared with the same
period in 2001.  The increase is due primarily to the cessation of goodwill  amortization  as a result of the adoption of FAS
142 and an increase in allowance for equity funds used during  construction,  partially  offset by reduced  earnings from the
Yankees and decreased interest income from other investing activities.

Other  income-net  for the twelve months ended March 31, 2001  increased  approximately  $4 million  compared with the twelve
months ended  December 31, 1999  primarily  due to increased  earnings  from the Yankees,  partially  offset by a decrease in
allowance for equity funds used during construction.

The  amortization of goodwill during fiscal 2001 of  approximately  $18 million  resulted from the mergers with National Grid
and EUA.

Other  income- net for the three months ended March 31, 2000  increased  compared with the same period in 1999 as a result of
decreased  expenses  related to employee  incentive  plans from workforce  reductions  following the  divestiture,  partially
offset by merger related expenses in 2000.

Interest Expense
Interest  expense for the twelve  months  ended March 31, 2002  decreased  approximately  $7 million  compared  with the same
period in 2001 primarily due to decreased  interest rates on the Company’s  variable-rate  long-term debt and the refinancing
of short-term debt.

Interest  expense  increased  approximately  $8 million for the twelve  months ended March 31, 2001  compared with the twelve
months  ended  December 31, 1999  primarily  due to higher  interest  rates on variable  rate  long-term  debt and  increased
short-term debt borrowings, as well as interest related to Montaup’s CTC settlement.

Interest  expense for the three months ended March 31, 2000 increased  approximately $1 million compared with the same period
in 1999  primarily  due to  increased  interest  rates on  variable  rate  long-term  debt and  interest on  short-term  debt
borrowings not present in 1999.

Nuclear Units

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

--------------------------------------------- ---------------------------------- ----------------------- ------------------------
                                                                                                            Future Estimated
                                               The Company’s Investment as of                       Billings to the Company
                                                       3/31/02
Unit                                                 %           $(millions)               Date Retired        $(millions)
--------------------------------------------- ---------------- ----------------- ----------------------- ------------------------

Yankee Atomic                                      34.5              0.4                       Feb 1992               0
Connecticut Yankee                                 19.5               13                       Dec 1996              44
Maine Yankee                                       24.0               15                       Aug 1997             123

Yankee  Atomic  has  discontinued  further  billings  to  the  Company  subject  to a  final  reconciliation  of  costs  once
decommissioning  at the plant has been  completed.  For Maine  Yankee and  Connecticut  Yankee,  the Company  has  recorded a
liability and a regulatory asset reflecting the estimated future billings from the companies.

Under the provisions of the Company’s industry  restructuring  settlement agreements approved by state and federal regulators
in 1998, the Company  recovers all costs,  including  shutdown costs,  that the FERC allows these Yankee companies to bill to
the Company.


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.

Maine Yankee had previously hired Stone and Webster, Inc. (S and W), an engineering,  construction,  and consulting company, as the
principal  contractor to  decommission  the unit. In May 2000,  Maine Yankee  terminated its long-term  contract with S and W and
negotiated an  arrangement  with S and W to continue  work through June 2000.  In June 2000,  S and W filed for Chapter 11 bankruptcy
protection.  Subsequently,  Maine Yankee decided to self-manage the unit’s  decommissioning  process.  In June 2000,  Federal
Insurance Company (Federal) filed a complaint in S and W’s bankruptcy  proceedings,  subsequently removed to US District Court in
Maine,  which alleged that Maine Yankee  improperly  terminated its contract with S and W and that Federal should be excused from
a $39 million performance bond and a $12 million payment bond to Maine Yankee.

In December 2001,  Maine Yankee and Federal reached a settlement.  Pursuant to the settlement  agreement,  Federal paid Maine
Yankee $44 million in January 2002.  Maine Yankee  deposited the payment in its  decommissioning  trust fund.  With regard to
Maine Yankee’s  August 2000 damage claim against S and W in the bankruptcy  proceeding for $78.2 million (later  decreased to $21
million to reflect,  among other things,  the recovery of $44 million from Federal),  on May 30, 2002,  the bankruptcy  judge
held that Maine  Yankee had proved  damages of $20.8  million and  estimated  its claim at that amount.  However,  the amount
Maine Yankee  actually  recovers will depend on the magnitude of assets in the bankrupt  estate  available to pay  creditors’
claims.

At Maine  Yankee and Yankee  Atomic,  the  contractor  responsible  for the  movement  of spent fuel from wet  storage to dry
storage has incurred  delays.  Connecticut  Yankee has experienced  delays in its  decommissioning  process due to zoning and
other issues most of which are now resolved.

Due to rate  recovery  mechanisms,  the S and W claims and  decommissioning  delays are not  expected  to  materially  affect the
Company’s earnings.

Operating Nuclear Units
The Company has  minority  interests  in two  operating  nuclear  generating  units that the Company is engaged in efforts to
divest:  Vermont  Yankee and Seabrook 1. In addition,  the Company sold its 16.2 percent  interest in Millstone 3 to Dominion
Resources,  Inc.  (Dominion) on March 31, 2001. Until such time as the Company divests its operating  nuclear  interests,  80
percent of the revenues and  reasonable  operating  costs  related to the units will be  allocated to the  customers  through
CTCs,  with  shareholders  being  allocated  the balance.  Net proceeds  attributed to the  divestiture  of the units will be
allocated to customers through CTC.

Vermont Yankee
The following table summarizes the Company’s interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2002:

                                                        The Company’s Interest
                                                         (millions of dollars)
                    ------------------------------------------------------------------------------------------------

                                          Net                                                    Decommissioning
Equity Ownership        Equity           Plant             Estimated Decommissioning                  Fund               License
   Interest (%)        Investment        Assets                 Cost (in 2001$)                      Balance           Expiration
------------------- ----------------- ------------- ---------------------------------------- ----------------------- ----------------
       23.9               $12             $34                        $107                             $63                 2012

In  December  2001,  Vermont  Yankee  reached a  settlement  with four equity  owners,  other than the  Company,  agreeing to
repurchase the Vermont Yankee shares held by these minority  shareholders  for $230 per share. The repurchase was consummated
in January 2002 for approximately $5.4 million.  As a result of the repurchase,  the Company’s  ownership interest in Vermont
Yankee increased from 22.5 percent to 23.9 percent.

On August 15, 2001,  Vermont Yankee  announced  that it had reached an Agreement  (the  Agreement) to sell the Vermont Yankee
nuclear  power plant to Entergy  Corporation  (Entergy) for $180  million.  The Company’s  portion of the sale price would be
approximately  $43 million ($35 million for the plant and related  assets and $8 million for nuclear  fuel) based on its 23.9
percent  ownership  interest.  The plant’s  decommissioning  trust fund would be  transferred  to Entergy,  and Entergy would
assume  decommissioning  liability for the plant. As part of the transaction,  Vermont Yankee owners,  including the Company,
would  purchase  power from the plant through 2012.  Net proceeds from the sale would be credited to the Company’s  customers
through  the CTC.  The sale of the plant is  contingent  upon the  receipt of  regulatory  approvals  by the  Securities  and
Exchange  Commission,  under the 1935 Act, the FERC,  the Nuclear  Regulatory  Commission  (NRC),  the Vermont Public Service
Board (VPSB),  and other state  regulatory  commissions  with  jurisdiction  over other equity owners of Vermont Yankee.  The
FERC, the NRC and the VPSB have approved the sale. On June 21, 2002,  Entergy filed a motion seeking  reconsideration  by the
VPSB of a condition in its order approving the sale. The condition  rejected a provision in the Agreement  entitling  Entergy
to keep 50 percent of any property  remaining in the  decommissioning  trust fund upon  completion  of  decommissioning.  The
Agreement with Entergy terminates if the sale is not completed by July 31, 2002.

The  Company  previously  resold  11.8 MW of its  Vermont  Yankee  entitlement  to a number of  municipal  and  cooperative
utilities  (Secondary  Purchasers) located in Massachusetts  under a “Vermont Yankee Secondary  Purchaser  Agreement” which
had a 30-year  term  expiring on November  30,  2002.  On May 16,  2002,  the FERC  approved  an early  termination  of the
Secondary  Purchasers  contract effective February 28, 2002.  Pursuant to the settlement,  the Secondary  Purchasers agreed
not to oppose the plant sale in any regulatory proceeding.

The  Citizens of  Brattleboro,  and eight other towns in Vermont,  cast non binding  votes at town  meetings in March 2002 on
whether  Vermont Yankee should be shut down. In the nine towns that voted on the issue,  a narrow  majority chose to keep the
plant open.

Seabrook 1
The following table summarizes the Company’s interest in the Seabrook 1 nuclear generating unit as of March 31, 2002:

                                    The Company’s share of (millions of dollars)
                    ------------------------------------------------------------------------------

  The Company’s                                                          Decommissioning
  Ownership         Net                 Estimated Decommissioning                Fund              License
 Interest (%)      Plant Assets              Cost (in 2001$)                     Balance*          Expiration
------------------- -------------- ---------------------------------------- ---------------------- ---------------
        10             $17 **                        $55                             $19                2026

*    Certain additional amounts are anticipated to be available through tax deductions.
** Represents post-December 1995 spending including nuclear fuel.

On April 15, 2002,  eight of the 11 joint  owners of Seabrook,  including  the  Company,  announced  that they had reached an
agreement  to sell an 88.2  percent  interest in Seabrook to FPL Energy  Seabrook LLC (FPL  Seabrook),  a  subsidiary  of FPL
Group, for $836.6 million.  The Company’s portion of the gross sales proceeds would be approximately $93.5 million.  Pursuant
to the terms of the Company’s  restructuring  settlements,  98 percent of the Company’s proceeds,  net of expenses related to
the sale,  post-1995 capital additions and inventories,  will be returned to National Grid customers in Massachusetts,  Rhode
Island,  and New  Hampshire.  FPL  Seabrook  will assume  responsibility  for ultimate  decommissioning  of Seabrook and will
receive the Seabrook  decommissioning funds, including a top-off payment by the Company and other sellers.  Approvals for the
transaction  are needed from federal and state  regulatory  agencies,  including  public utility  commissions in the sellers’
states, the NRC, the New Hampshire Nuclear  Decommissioning  Financing  Committee  (NHNDFC),  the FERC, and the Department of
Justice or the Federal Trade Commission. The plant owners are targeting to complete the sale by the end of 2002.



Millstone 3
In November  1999,  the Company  entered into an  agreement  with  Northeast  Utilities  (NU) to settle  claims made by the
Company  regarding  the  operation  of  Millstone  3. Among other  things,  the  settlement  provided for NU to include the
Company’s 16.2 percent  interest in Millstone 3 in an auction of NU’s share of the unit.  Upon the closing of the sale, the
Company was to receive a fixed amount, regardless of the actual sale price.

In August 2000,  Dominion agreed to purchase the Millstone units,  including the Company’s  interest in Millstone 3, for $1.3
billion.  In March 2001, the sale was completed.  In accordance  with the prior  settlement  agreement,  the Company was paid
approximately  $27.9  million,  including  $25 million for the plant,  and the Company  paid  approximately  $5.8  million to
increase the decommissioning trust fund.

Regulatory  authorities  from Rhode  Island,  New  Hampshire  and  Massachusetts  have  expressed an intent to challenge  the
reasonableness  of the settlement  agreement as the Company would have received  approximately  $140 million of sale proceeds
without the  agreement.  The dispute  will be resolved by the FERC.  The Company  believes it has a strong  argument  that it
acted  prudently  since the amount  received under the settlement  agreement was the highest sale price for a nuclear unit at
the time the agreement was reached.

Plant Security Costs
In view of potential  terrorist  activity  following  the events of September 11, 2001,  security at nuclear  plants has been
enhanced in concert with NRC advisory  notices.  The increased cost to the Company for security was  approximately $1 million
for the fiscal year ended March 31, 2002. The Company expects  security costs to increase.  Due to rate recovery  mechanisms,
these costs will not materially affect the Company’s earnings.

Risk Management
The Company's major financial market risk exposure is changing  interest rates.  Changing interest rates will affect interest
paid on variable  rate debt.  At March 31,  2002 and 2001,  the  Company's  tax exempt  variable  rate  long-term  debt had a
carrying  value and fair value of  approximately  $410 million.  While the ultimate  maturity  dates of the  underlying  loan
agreements  range from 2015 through 2022,  this debt is issued in tax exempt  commercial  paper mode. The various  components
that comprise  this debt are issued for periods  ranging from one day to 270 days,  and are  remarketed  through  remarketing
agents at the conclusion of each period.  The weighted average variable  interest rate for the year ended March 31, 2002, was
approximately 2.52 percent.

As  discussed in the  “Regulatory  Environment”  section,  despite the 1998  termination  of the  Company’s  all-requirements
contract with its affiliated  distribution  companies,  the Company  remained  obligated to provide  transition  power supply
service to new customer  load in Rhode  Island at the standard  offer  price,  but did not have a regulatory  agreement  that
allowed full recovery of the costs of such standard  offer power.  Consequently,  the Company was at risk for the  difference
between the actual cost of serving  this load and the revenue  received  from this  obligation.  For the year ended March 31,
2002, the impact on the Company’s  financial  position was immaterial.  Effective December 1, 2001, a third party assumed the
responsibility  for  providing  transitional  standard  offer power service in Rhode  Island,  and the  Company’s  obligation
terminated.

Utility Plant Expenditures and Financing
Cash  expenditures  for the Company for utility plant totaled $47 million for the twelve months ended March 31, 2002 and were
primarily  transmission-related.  The funds  necessary  for  utility  plant  expenditures  during the period  were  primarily
provided  by  internal  funds.  Cash  expenditures  for fiscal  year 2003 are  estimated  to be  approximately  $34  million,
principally related to transmission  functions.  Internally  generated funds are expected to fully cover capital expenditures
in fiscal year 2003.

At March 31, 2002 and 2001, the Company had no short-term debt outstanding.  The Company has regulatory  approval to issue up
to $375 million of short-term debt.

At March 31, 2002 and 2001,  the Company had lines of credit and standby bond purchase  facilities  with banks  totaling $456
million which are available to provide  liquidity  support for $410 million of the  Company’s  long-term  bonds in tax-exempt
commercial  paper mode, and for other corporate  purposes.  There were no borrowings under these lines of credit at March 31,
2002.

The Company’s  capital  obligations  consist of amounts for purchased power,  long-term debt maturities and operating leases.
The purchased power commitments are other than those reflected in the liabilities  section of the balance sheet.  Payments by
fiscal year are as follows:

--------------------------------------- ---------------------------------------------------------------------------------------
Capital Requirements                                                    Payments Due by March 31,
(in thousands)                                  2003            2004          2005          2006            2007         2008+
--------------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
Purchased Power Commitments                   $72,620          $69,209        $58,629        $42,043      $46,024       $263,740
Long Term Debt Maturities                          -               -             -             -               -       410,285
Operating Leases                                 485             448           430           415             174             7
--------------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
------- ------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
        Total                                 $73,105          $69,657        $59,059        $42,458       $46,198       674,032
------- ------------------------------- ------------- --------------- ------------- ------------- --------------- -------------

 Merger with National Grid
On March 22,  2000,  the merger of New  England  Electric  System  (NEES) and  National  Grid Group plc  (National  Grid) was
completed,  with NEES  (renamed  National  Grid USA)  becoming a wholly  owned  subsidiary  of  National  Grid.  The  Company
maintained  its existing  name and remained a wholly owned  subsidiary  of National Grid USA. The merger was accounted for by
the purchase method,  the application of which,  including the recognition of goodwill,  was pushed down and reflected on the
financial statements of the National Grid USA subsidiaries,  including the Company.  Total goodwill amounted to $1.7 billion,
of which the Company was allocated  approximately $348 million.  This amount was determined  pursuant to a study conducted by
an independent third party.

The purchase  accounting  method  requires the revaluation of assets and  liabilities to their fair value.  This  revaluation
resulted in an adjustment to the Company’s  pension and  postretirement  benefit accounts in the amount of approximately  $61
million, with an offsetting net credit to a regulatory liability account.

Acquisition of EUA
The acquisition of EUA by National Grid USA was completed on April 19, 2000 for $642 million.  On May 1, 2000,  Montaup,  was
merged into the Company.

The  acquisition of EUA was accounted for by the purchase  method,  the  application of which,  including the  recognition of
goodwill,  has been pushed down and reflected on the financial  statements of the National Grid USA  subsidiaries,  including
the Company.  Total  goodwill  recognized  in this  transaction  was  approximately  $402  million,  of which the Company was
allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party.

The purchase  accounting  method  requires the revaluation of assets and  liabilities to their fair value.  This  revaluation
resulted in an adjustment to the Company’s  pension and  postretirement  benefit  accounts in the amount of  approximately $3
million, with an offsetting net credit to a regulatory liability account.

In  connection  with the mergers  referred  to above,  the Company  adjusted  its pension and PBOP  accounts in the amount of
approximately $64 million,  with an offsetting net credit to a regulatory liability account.  This adjustment  eliminated any
unrecognized net gain or loss,  unrecognized prior service cost, or unrecognized  transition  obligation of the Company.  The
regulatory liability is being amortized over the service period to pension and postretirement health care costs.


Critical Accounting Policies:
There are certain  critical  accounting  policies that are based on assumptions  and conditions  that if changed could have a
material  effect on the financial  condition,  results of operations and liquidity of the Company.  The following  accounting
policies  are  particularly  important to the  financial  condition  and results of  operations  of the  Company:  regulatory
accounting  and  goodwill  accounting.

Because electric utility rates have historically been based on a utility’s costs,  electric  utilities are subject to certain
accounting  standards that are not applicable to other business  enterprises in general.  The Company  applies the provisions
of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated  entities,  in
appropriate  circumstances,  to establish regulatory assets or liabilities,  and thereby defer the income statement impact of
certain  charges or revenues  because they are expected to be collected or refunded  through  future  customer  billings.  In
1997,  the Emerging  Issues Task Force of the FASB concluded  that a utility that had received  approval to recover  stranded
costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.

The Company has received  authorization  from the FERC to recover through CTCs substantially all of the costs associated with
its former generating business not recovered through the divestiture.  Additionally,  FERC Order No. 888 enables transmission
companies to recover their specific costs of providing  transmission service.  Therefore,  substantially all of the Company’s
business,  including the recovery of its stranded costs,  remains under  cost-based rate  regulation.  Because of the nuclear
cost-sharing  provisions  related to the  Company’s  CTC,  the Company  ceased  applying  FAS 71 in 1997 to 20 percent of its
ongoing nuclear operations, the impact of which is immaterial.

As a result of  applying  FAS 71, the  Company  has  recorded a  regulatory  asset for the costs  that are  recoverable  from
customers  through the CTC. At March 31, 2002, this amounted to  approximately  $1.5 billion,  including $1.0 billion related
to the  above-market  costs of purchased power  contracts,  $0.2 billion  related to accrued Yankee nuclear plant costs,  and
$0.3 billion related to other net CTC regulatory assets.

The Company applies the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible
Assets” (FAS 142).  In accordance with FAS 142, goodwill must be reviewed for impairment within six months of adoption
(“transitional goodwill impairment test”), and at least annually thereafter.  The Company utilized a discounted cash flow
approach incorporating its most recent business plan forecasts in the performance of the transitional goodwill impairment test and the
annual goodwill impairment test.  The result of the transitional and annual analyses determined that no adjustment to the goodwill
carrying value was required.

For  further  discussion  of Critical  Accounting  Policies  see “Note  A-Significant
Accounting Policies” and “Note B-Regulatory Environment and Accounting Implications”.

New Accounting Standards:
The Company adopted  Statement of Financial  Accounting  Standards (SFAS) No. 142,  “Goodwill and Other Intangible  Assets”
(FAS 142),  effective  April 1, 2001,  the  beginning of the 2002 fiscal year.  FAS 142 requires that goodwill no longer be
amortized on a ratable basis.  The following  table presents pro forma  information  for the year ended March 31, 2001, and
the three months ended March 31, 2000, to reflect the reversal of goodwill amortization in accordance with FAS 142:

                                                                                    Year Ended        Three Months Ended
                                                                                March 31, 2001            March 31, 2000

                                                                                                 (In thousands)
Net income, as reported                                                                $58,300                   $14,462
Reversal of goodwill amortization                                                       17,905                       366
Proforma net income                                                                    $76,205                   $14,828



In accordance with FAS 142,  goodwill must be reviewed for impairment within six months of adoption  (“transitional  goodwill
impairment test”), and at least annually thereafter.  The Company utilized a discounted cash flow approach  incorporating its
most recent business plan forecasts in the performance of the transitional  goodwill  impairment test and the annual goodwill
impairment test. The result of the transitional  and annual analyses  determined that no adjustment to the goodwill  carrying
value was required.

FAS 142 also requires that  recognizable  intangible  assets be amortized over their useful lives and tested for  impairment.
Intangible assets with indefinite  useful lives should be reviewed for impairment.  The Company has concluded a review of its
intangible assets and no adjustment was deemed necessary effective with the adoption of FAS 142.

In June 1998, the Financial  Accounting  Standards Board (FASB) issued SFAS No. 133,  “Accounting for Derivative  Instruments
and Hedging  Activities”.  In June 2000, the FASB issued SFAS No. 138,  “Accounting  for Certain  Derivative  Instruments and
Certain Hedging  Activities“.  These accounting  pronouncements  require that an entity recognize  derivative  instruments as
either assets or liabilities in the statement of financial  position and the measure of those  instruments at fair value. The
Company  adopted the  pronouncements  effective at the beginning of fiscal 2002. The standards  have not materially  affected
the Company’s financial position or results of operations.

In June 2001, the FASB issued SFAS No. 143,  “Accounting for Asset  Retirement  Obligations”  (FAS 143). FAS 143 provides the
accounting  requirements for retirement  obligations  associated with tangible  long-lived  assets.  FAS 143 is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted.  The Company is currently  evaluating the impact
of this standard on its financial position and results of operations.

In August 2001, the FASB issued SFAS No. 144,  “Accounting  for the  Impairment or Disposal of Long-Lived  Assets” (FAS 144).
FAS 144  supersedes  SFAS No. 121,  “Accounting  for the  Impairment of  Long-Lived  Assets and for  Long-Lived  Assets to be
Disposed  Of” (FAS 121) and the  accounting  and  reporting  provisions  of  Accounting  Principles  Board  Opinion  No.  30,
“Reporting  the Results of  Operations  – Reporting  the Effects of Disposal of a Business,  and  Extraordinary,  Unusual and
Infrequently  Occurring Events and Transactions”,  related to the disposal of a segment of a business.  FAS 144 establishes a
single  accounting  model for  long–lived  assets to be disposed of by sale and resolves  significant  implementation  issues
related to FAS 121.  FAS 144 is effective  for fiscal  years  beginning  after  December  15, 2001.  The Company is currently
evaluating the impact of this standard on its financial position and results of operations.

In April 2002, the FASB issued SFAS No. 145,  “Recision of FASB Statements No. 4, 44 and 64,  Amendment of FASB Statement No.
13, and Technical  Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from  Extinguishment of Debt,”
SFAS No.  44,  “Accounting  for  Intangible  Assets of Motor  Carriers,”  and SFAS No. 64,  “Extinguishments  of Debt Made to
Satisfy  Sinking-Fund  Requirements.”  The  Statement  amends SFAS No. 13,  “Accounting  for  Leases,” to  eliminate  certain
inconsistencies.  It also amends other existing authoritative  pronouncements to make various technical corrections,  clarify
meanings or describe their applicability under changed  circumstances.  Certain provisions of the standard are required to be
adopted for transactions  occurring after May 15, 2002; other provisions are required to be adopted for financial  statements
issued after May 15, 2002.  The Company is currently  evaluating  the impact of this standard on its  financial  position and
results of operations.



New England Power  Company,  (the Company) a wholly owned  subsidiary  of National Grid USA, is a  Massachusetts  corporation
qualified to do business in  Massachusetts,  New Hampshire,  Rhode Island,  Connecticut,  Maine, and Vermont.  The Company is
subject, for certain purposes,  to the jurisdiction of the regulatory  commissions of all these states (except  Connecticut),
the Securities and Exchange  Commission,  under the Public Utility Holding Company Act of 1935, the Federal Energy Regulatory
Commission,  and the Nuclear Regulatory  Commission.  The Company's business is primarily the transmission of electric energy
in wholesale  quantities to other  electric  utilities,  principally  its  distribution  affiliates  Granite  State  Electric
Company,  Massachusetts  Electric Company,  Nantucket Electric Company, and The Narragansett  Electric Company. The Company’s
transmission  facilities  are part of National  Grid USA’s  transmission  operations,  which are  represented  under the name
National Grid Transmission USA.


Report of Independent Accountants

To the Stockholders and Board of Directors of
New England Power Company:

In our opinion,  the accompanying  balance sheets and the related  statements of income,  of comprehensive income, of
retained earnings,  and of cash flows present fairly, in all material respects, the financial position of New England Power
Company at March 31, 2002 and 2001,  and the results of its operations and its cash flows for the years then ended in conformity
with  accounting principles  generally  accepted in the United States of America.  These financial  statements are the
responsibility of the Company's management;  our responsibility is to express an opinion on these financial  statements
based on our audits.  We conducted our audits of these  statements in accordance with auditing standards generally
accepted in the United States of America,  which  require  that we plan and perform  the audit to obtain  reasonable  assurance
about  whether the  financial statements are free of material misstatement.  An audit includes examining,  on a test basis, evidence
supporting the amounts and disclosures in the financial statements,  assessing the accounting  principles used and  significant
estimates made by management,  and evaluating the overall  financial  statement  presentation.  We believe that our audits provide a reasonable
basis for our opinion.

As  described in Note A-8, effective April 1, 2001, the Company changed its method of accounting for goodwill and other
intangible assets.





S:/PricewaterhouseCoopers LLP


Boston, Massachusetts
May 14, 2002, except for Note E-1,
as to which the date is June 21, 2002





Report of Independent Accountants

To the Stockholders and Board of Directors of
New England Power Company:

In our opinion,  the accompanying statements of income,  of comprehensive income, of retained earnings,  and of cash flows present fairly,
in all material respects, the results and operations of New England Power Company and its cash flows for the three-month period ended
March 31, 2000 and the year ended December 30, 1999, in conformity with accounting principles generally  accepted in the United States of
America.  These financial statements are the responsibility of the Company's management;  our responsibility is to express an opinion
on these financial statements based on our audits.  We conducted our audits of these  statements in accordance with auditing standards generally
accepted in the United States of America,  which  require that we plan and perform  the audit to obtain  reasonable  assurance
about  whether the  financial statements are free of material misstatement.  An audit includes examining,  on a test basis, evidence
supporting the amounts and disclosures in the financial statements,  assessing the accounting  principles used and  significant
estimates made by management,  and evaluating the overall financial statement  presentation.  We believe that our audits provide a reasonable
basis for our opinion.



S:/PricewaterhouseCoopers LLP


Boston, Massachusetts
May 14, 2002, except for Note E-1,
as to which the date is June 21, 2002


Statements of Income
================================================= ========================= ============================== ==================
                                                         Year Ended         Three Months Ended March 31,      Year Ended
                                                          March 31,                                          December 31,
                                                         2002         2001           2000            1999        1999
(In thousands)                                                                                (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Operating revenue, principally from                  $560,418     $656,272       $134,564        $167,177           $596,341
  affiliates
Operating expenses:
         Fuel for generation                            5,428       14,342          3,548           3,058             12,803
         Purchased electric energy:
               Contract termination and
                 nuclear unit shutdown
                 charges                              229,549      214,948         47,405          46,873            187,777
               Other                                   68,675       91,844         14,682          11,111             56,731
         Other operation                               56,769       69,624         15,760          19,210             70,936
         Maintenance                                   17,266       31,748          4,320           5,766             28,536
         Depreciation and amortization
            (Note A-4)                                 30,601       78,762         16,962          40,367            103,080
         Taxes, other than income taxes
            (Note K)                                   18,183       22,343          5,561           5,634             20,282
         Income taxes (Note G)                         47,593       44,946          9,641          13,100             37,633
-------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
               Total operating expenses               474,064      568,557        117,879         145,119            517,778
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Operating income                                       86,354       87,715         16,685          22,058             78,563
Other income(expense):
         Allowance for equity funds used
           during construction                          1,077          276          (393)             588              1,958
         Equity in income of nuclear
           power companies                              3,332        6,703            862             515              2,939
         Amortization of goodwill (Note A-8)                -     (17,905)          (366)               -                  -
         Other income, net                                791        3,559          1,850             434              2,087
-------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
               Operating and other income              91,554       80,348         18,638          23,595             85,547
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Interest:
         Interest on long-term debt                    11,434       17,834          3,749           3,143             14,052
         Other interest                                 3,509        4,883            853             240              1,003
         Allowance for borrowed funds
           used during construction                     (163)        (669)          (426)           (133)              (522)
-------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
               Total interest                          14,780       22,048          4,176           3,250             14,533
-------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Net income                                           $ 76,774     $ 58,300       $ 14,462        $ 20,345           $ 71,014
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------

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


Statements of Comprehensive Income
================================================= ========================= ============================== ==================
                                                         Year Ended         Three Months Ended March 31,      Year Ended
                                                          March 31,                                          December 31,
                                                         2002         2001           2000            1999        1999
(In thousands)                                                                                (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Net Income                                           $ 76,774     $ 58,300       $ 14,462        $ 20,345           $ 71,014
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Unrealized gain (loss) on securities, net of tax           35        (145)             17               1                 19
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Comprehensive income (Note A-9)                      $ 76,809     $ 58,155       $ 14,479        $ 20,346           $ 71,033
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------


Statements of Retained Earnings
================================================= ========================= ============================== ==================
                                                         Year Ended         Three Months Ended March 31,      Year Ended
                                                          March 31,                                          December 31,
                                                         2002         2001           2000            1999        1999
(In thousands)                                                                                (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Retained earnings at beginning of period             $ 60,110      $ 1,415       $ 27,287        $204,603          $ 204,603
Net income                                             76,774       58,300         14,462          20,345             71,014
Dividends declared on cumulative
  preferred stock                                        (86)         (91)           (24)            (24)               (94)
Dividends declared on common stock,
  -0-, $-0-, $6.66, $-0-, and $66.69, per
  share, respectively                                       -            -       (24,098)               -          (241,415)
Gain on redemption of preferred stock                       -           21              -               -                264
Repurchase of common stock                                  -            -              -         (7,085)            (7,085)
Purchase accounting adjustment                              -            -       (16,212)               -                  -
Acquisition adjustment                                      -          465              -               -                  -
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Retained earnings at end of period                   $136,798      $60,110         $1,415        $217,839            $27,287
------------------------------------------------- ------------ ------------ -------------- --------------- ------------------

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



Balance Sheets
======================================================================================= ==================== ====================
At March 31 (In thousands)                                                                       2002                 2001
======================================================================================= ==================== ====================
======================================================================================= ==================== ====================
Assets
Utility plant, at original cost                                                             $ 909,043             $846,935
       Less accumulated provisions for depreciation and amortization                          329,927              320,238
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ -------------------------------------------------------------------------------- -------------------- --------------------
                                                                                              579,116              526,697
       Construction work in progress                                                            7,466               34,946
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Net utility plant                                                                 586,582              561,643
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
Goodwill                                                                                      338,188              338,188
Investments:
       Nuclear power companies, at equity (Note D-1)                                           40,339               46,474
       Decommissioning trust funds (Note E-1)                                                  18,810               16,331
       Nonutility property and other investments                                               11,515               14,374
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Total investments                                                                  70,664               77,179
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
Current assets:
       Cash and temporary cash investments (including $99,300                                 103,467               22,360
         and $22,075 with affiliates)
       Accounts receivable, (less reserves of $153 and $153)
            Affiliated companies                                                               41,408               61,191
            Others                                                                             67,460               89,483
       Fuel, materials, and supplies, at average cost                                           6,215                6,289
       Prepaid and other current assets                                                         1,402                2,051
       Regulatory assets - purchased power obligations and accrued Yankee nuclear             172,556              174,441
         plant costs
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Total current assets                                                              392,508              355,815
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
Regulatory assets (Note B)                                                                  1,297,079            1,506,226
Deferred charges and other assets                                                              55,184               50,170
--------------------------------------------------------------------------------------- -------------------- --------------------
------ -------------------------------------------------------------------------------- -------------------- --------------------
                                                                                           $2,740,205           $2,889,221
------ -------------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------

Capitalization and Liabilities
Capitalization:
       Common stock, par value $20 per share,   Authorized - 6,449,896 shares
         Outstanding – 3,619,896 shares                                                      $ 72,398             $ 72,398
       Other paid-in capital                                                                  731,974              731,974
       Retained earnings                                                                      136,798               60,110
       Accumulated other comprehensive loss (Note A-9)                                           (110)                (145)
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Total common equity                                                               941,060              864,337
       Cumulative preferred stock, par value $100 per share (Note I)                            1,436                1,436
       Long-term debt                                                                         410,285              410,279
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Total capitalization                                                            1,352,781            1,276,052
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
Current liabilities:
       Accounts payable (including $14,059 and $25,287 to affiliates)                          47,358               66,017
       Accrued liabilities:
            Taxes                                                                              14,367               39,451
            Interest                                                                              773                1,489
            Purchased power obligations and accrued Yankee nuclear plant costs                172,556              174,441
            Other accrued expenses                                                              3,094                7,621
       Dividends payable                                                                           22                   22
------ -------------------------------------------------------------------------------- -------------------- --------------------
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
            Total current liabilities                                                         238,170              289,041
------ ---- --------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
Deferred federal and state income taxes                                                       257,302              272,304
Unamortized investment tax credits                                                              8,795                9,312
Accrued Yankee nuclear plant costs (Note E-1)                                                 141,869              156,477
Purchased power obligations                                                                   513,599              636,848
Other reserves and deferred credits                                                           227,689              249,187
Commitments and contingencies (Note E)
--------------------------------------------------------------------------------------- -------------------- --------------------
--------------------------------------------------------------------------------------- -------------------- --------------------
                                                                                           $2,740,205           $2,889,221
--------------------------------------------------------------------------------------- -------------------- --------------------

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


Statements of Cash Flows
================================================= ========================= ============================== ==================
                                                         Year Ended         Three Months Ended March 31,      Year Ended
                                                          March 31,                                          December 31,
                                                         2002         2001          2000             1999        1999
(In thousands)                                                                                (unaudited)
================================================= ============ ============ ============= ================ ==================
================================================= ============ ============ ============= ================ ==================
Operating activities:
Net income                                            $76,774      $58,300      $ 14,462         $ 20,345            $71,014
Adjustments to reconcile net income to net cash
  provided by operating activities:
       Depreciation and amortization                   86,383       85,123        18,799           42,170            108,789
     Amortization of goodwill                               -       17,905           366                -                  -
       Deferred income taxes and investment tax
         credits, net                                (16,072)     (11,480)       (2,908)            5,726             14,111
       Allowance for funds used during
         construction                                 (1,240)        (945)          (33)            (720)            (2,480)
       Buyout of purchased power contracts                  -            -             -                -            (3,472)
Changes in assets and liabilities, net of
  effects of acquisition:
             Decrease (increase) in accounts
               receivable, net                         16,806      (7,914)       (3,174)           37,890             22,706
             Decrease (increase) in fuel,
               materials, and supplies                     74        4,160         (874)              648              (251)
             Decrease in regulatory assets            145,949      152,533        60,044           82,801            166,730
             Decrease (increase) in prepaid and
               other current assets                       649       26,501        13,938            6,154           (17,746)
             Decrease in accounts payable            (18,659)        (813)      (11,628)         (81,950)           (99,148)
             Decrease in purchased power
               contract obligations                 (127,069)     (77,039)      (16,947)         (36,903)          (128,931)
             Increase (decrease) in other
               current liabilities                   (30,327)       30,822       (7,787)         (11,147)           (14,575)
             Increase (decrease) in other
               non-current liabilities               (34,171)    (147,847)        20,349          (5,661)             45,483
             Other, net                                   413       73,202      (49,869)         (40,946)           (87,277)
------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
             Net cash provided by operating           $99,510    $ 202,508      $ 34,738         $ 18,407            $74,953
               activities
------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
------------------------------------------------- ------------ ------------ ------------- ---------------- ------------------
Investing activities:
Proceeds from sale of generating assets               $25,000            -             -                -                  -
Plant expenditures, excluding allowance for
  funds used during construction                     (46,927)     (56,558)      (11,890)         (13,739)           (56,887)
Other investing activities                              3,610      (3,270)         (271)             (20)            (4,411)
------------------------------------------------- ------------ ------------ ------------- ---------------- ------------------
------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
             Net cash used in investing             $(18,317)   $ (59,828)     $(12,161)        $(13,759)         $ (61,298)
               activities
------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------

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


Statements of Cash Flows – (continued)

================================================= =========================== ============================= ===================
                                                          Year Ended          Three Months Ended March 31,      Year Ended
                                                           March 31,                                           December 31,
                                                         2002           2001          2000            1999         1999
(In thousands)                                                                                 (unaudited)
================================================= ============ ============== ============= =============== ===================
================================================= ============ ============== ============= =============== ===================
Financing activities:
Dividends paid on common stock                                                           $
                                                       $    -     $(256,463)             -          $    -           $ (9,050)
Dividends paid on preferred stock                        (86)           (93)             -            (24)               (118)
Changes in short-term debt                                  -       (38,500)             -               -              38,500
Long-term debt – issues                                     -         38,500             -               -                   -
Long-term debt – retirements                                -       (90,575)             -               -                   -
Repurchase of common shares                                 -              -             -        (18,056)            (18,056)
Preferred stock – retirements                               -          (110)             -               -                   -
------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
------------ ------------------------------------ ------------ -------------- ------------- --------------- -------------------
             Net cash provided by (used in)           $  (86)     $(347,241)             -       $(18,080)             $11,276
               financing activities
------------ ------------------------------------ ------------ -------------- ------------- --------------- -------------------
------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
Net increase (decrease) in cash and cash              $81,107     $(204,561)       $22,577       $(13,432)             $24,931
  equivalents
Cash and cash equivalents at beginning of period       22,360        226,921       204,344         179,413             179,413
------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
Cash and cash equivalents at end of period           $103,467       $ 22,360      $226,921        $165,981            $204,344
------------------------------------------------- ------------ -------------- ------------- --------------- -------------------


Supplementary Information:
Interest paid, less amounts capitalized               $10,734       $18,296        $ 5,322         $ 2,042            $11,849
Federal and state income taxes paid (refunded)        $90,810      $(3,233)         $ (15)        $ 11,321            $55,134
Dividends received from investments at equity         $ 3,812       $13,986        $ 1,129         $ 1,730            $ 5,243
------------------------------------------------- ------------ ------------- -------------- --------------- ------------------








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





New England Power Company

Notes to Financial Statements

Note A - Significant Accounting Policies

1.  Nature of Operations:
New England Power Company (the  Company),  a wholly owned  subsidiary  of National Grid USA, is a  Massachusetts  corporation
qualified to do business in  Massachusetts,  New Hampshire,  Rhode Island,  Connecticut,  Maine, and Vermont.  The Company is
subject, for certain purposes,  to the jurisdiction of the regulatory  commissions of these six states (except  Connecticut),
the Securities and Exchange  Commission  (SEC),  under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal
Energy Regulatory  Commission (FERC),  and the Nuclear  Regulatory  Commission (NRC). The Company's business is primarily the
transmission  of  electric  energy  in  wholesale  quantities  to other  electric  utilities,  principally  its  distribution
affiliates Granite State Electric Company,  Massachusetts Electric Company,  Nantucket Electric Company, and The Narragansett
Electric Company. The Company’s transmission  facilities are part of National Grid USA’s transmission  operations,  which are
represented  under the name National Grid  Transmission  USA. In addition,  the Company also owns a minority  interest in one
joint owned  nuclear  generating  unit and one fossil fuel  generating  unit,  as well as minority  equity  interests in four
nuclear generating companies (Yankees),  three of which own generating  facilities that are permanently shut down. The output
from these generating facilities is sold to third parties and used to serve the Company’s load obligation.

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

National  Grid USA and its  subsidiaries  changed  their  fiscal year in 2000 from a calendar  year  ending  December 31 to a
fiscal year ending March 31.  National  Grid USA and its  subsidiaries  made this change in order to align their fiscal years
with that of  National  Grid Group plc.  The  Company’s  first new full fiscal year began on April 1, 2000 and ended on March
31, 2001. The  accompanying  financial  information as of March 31, 2002 and 2001, and for the years ended March 31, 2002 and
2001,  reflects the new basis of accounting  established  for the Company’s  assets and  liabilities  in connection  with the
acquisition  of National Grid USA by National Grid on March 22, 2000.  The audited  results of operations for the three month
period ended March 31, 2000 includes an immaterial  amount of goodwill  amortization  for the ten day period from March 22 to
March 31, 2000. Due to the  immateriality  of this effect,  this  transitional  period has not been separated into the period
preceding and the period following the pushdown of goodwill.

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.  In addition,  certain  presentation  adjustments  have been made to
conform prior years with the 2002 presentation.

3.  Allowance for Funds Used During Construction (AFDC):
The Company  capitalizes  AFDC as part of  construction  costs.  AFDC  represents  an allowance for the cost of funds used to
finance  construction.  AFDC is  capitalized  in  “Utility  plant”  with  offsetting  noncash  credits to “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 8.1 percent for the year ended March 31, 2002,  3.2 percent for
the year ended March 31, 2001,  3.7 percent for the three month period ended March 31, 2000,  8.1 percent for the three month
period ended March 31, 1999, and 7.6 percent for the year ended December 31, 1999.



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

================================================= ========================= ============================== ==================
                                                         Year Ended         Three Months Ended March 31,      Year Ended
                                                          March 31,                                          December 31,
                                                         2002         2001           2000            1999        1999
(In thousands)                                                                                (unaudited)
Depreciation - transmission related                   $16,238      $15,055        $ 3,269         $ 3,440           $ 13,222
Depreciation - all other                                1,093        5,477           (15)             354              1,286
Nuclear decommissioning costs
  (Note E-1)                                            2,394        9,901            923             699              3,637
Amortization:
       Regulatory assets covered by contract
         termination charges (Note B)                  10,876       48,329         12,785          35,874             84,935
             Total depreciation and                  -------------------------------------------------------------------------
               amortization expense                  $ 30,601      $78,762        $16,962         $40,367           $103,080

Depreciation  is provided  annually on a  straight-line  basis.  The provision for  depreciation  as a percentage of weighted
average  depreciable  transmission  property was 2.3 percent for all periods  presented.  Amortization  of regulatory  assets
covered by contract termination charges (CTC) is in accordance with rate settlement agreements.

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

6.  Property, Plant, and Equipment:
The Company’s  integrated  system of  transmission  property  consists of  approximately  2,800 circuit miles of transmission
lines and 119 substations.

7.  Income Taxes:
Income taxes have been  computed  utilizing the asset and liability  approach that requires the  recognition  of deferred tax
assets and liabilities for the tax consequences of temporary  differences by applying enacted  statutory tax rates applicable
to future years to differences  between the financial  statement  carrying  amounts and the tax basis of existing  assets and
liabilities (see Note G).

8.  New Accounting Standards:
The Company adopted  Statement of Financial  Accounting  Standards (SFAS) No. 142,  “Goodwill and Other Intangible  Assets”
(FAS 142),  effective  April 1, 2001,  the  beginning of the 2002 fiscal year.  FAS 142 requires that goodwill no longer be
amortized on a ratable basis.  The following  table presents pro forma  information  for the year ended March 31, 2001, and
the three moths ended March 31, 2000, to reflect the reversal of goodwill amortization in accordance with FAS 142:

                                                                                        Year Ended         Three Months Ended
                                                                                    March 31, 2001             March 31, 2000

                                                                                                    (In thousands)
Net income, as reported                                                                    $58,300                    $14,462
Reversal of goodwill amortization                                                           17,905                        366
Proforma net income                                                                        $76,205                    $14,828




In accordance with FAS 142,  goodwill must be reviewed for impairment within six months of adoption  (“transitional  goodwill
impairment test”), and at least annually thereafter.  The Company utilized a discounted cash flow approach  incorporating its
most recent business plan forecasts in the performance of the transitional  goodwill  impairment test and the annual goodwill
impairment test. The result of the transitional  and annual analyses  determined that no adjustment to the goodwill  carrying
value was required.

FAS 142 also requires that  recognizable  intangible  assets be amortized over their useful lives and tested for  impairment.
Intangible assets with indefinite  useful lives should be reviewed for impairment.  The Company has concluded a review of its
intangible assets and no adjustment was deemed necessary effective with the adoption of FAS 142.

In June 1998, the Financial  Accounting  Standards Board (FASB) issued SFAS No. 133,  “Accounting for Derivative  Instruments
and Hedging  Activities“.  In June 2000, the FASB issued SFAS No. 138,  “Accounting  for Certain  Derivative  Instruments and
Certain Hedging  Activities”.  These accounting  pronouncements  require that an entity recognize  derivative  instruments as
either assets or liabilities in the statement of financial  position and the measure of those  instruments at fair value. The
Company  adopted the  pronouncements  effective at the beginning of fiscal 2002. The standards  have not materially  affected
the Company’s financial position or results of operations.

In June 2001, the FASB issued SFAS No. 143,  “Accounting for Asset  Retirement  Obligations”  (FAS 143). FAS 143 provides the
accounting  requirements for retirement  obligations  associated with tangible  long-lived  assets.  FAS 143 is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted.  The Company is currently  evaluating the impact
of this standard on its financial position and results of operations.

In August 2001, the FASB issued SFAS No. 144,  “Accounting  for the  Impairment or Disposal of Long-Lived  Assets” (FAS 144).
FAS 144  supersedes  SFAS No. 121,  “Accounting  for the  Impairment of  Long-Lived  Assets and for  Long-Lived  Assets to be
Disposed  Of” (FAS 121) and the  accounting  and  reporting  provisions  of  Accounting  Principles  Board  Opinion  No.  30,
“Reporting  the Results of  Operations  – Reporting  the Effects of Disposal of a Business,  and  Extraordinary,  Unusual and
Infrequently  Occurring Events and Transactions”,  related to the disposal of a segment of a business.  FAS 144 establishes a
single  accounting  model for  long–lived  assets to be disposed of by sale and resolves  significant  implementation  issues
related to FAS 121.  FAS 144 is effective  for fiscal  years  beginning  after  December  15, 2001.  The Company is currently
evaluating the impact of this standard on its financial position and results of operations.

In April 2002, the FASB issued SFAS No. 145,  “Recision of FASB Statements No. 4, 44 and 64,  Amendment of FASB Statement No.
13, and Technical  Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from  Extinguishment of Debt,”
SFAS No.  44,  “Accounting  for  Intangible  Assets of Motor  Carriers,”  and SFAS No. 64,  “Extinguishments  of Debt Made to
Satisfy  Sinking-Fund  Requirements.”  The  Statement  amends SFAS No. 13,  “Accounting  for  Leases,” to  eliminate  certain
inconsistencies.  It also amends other existing authoritative  pronouncements to make various technical corrections,  clarify
meanings or describe their applicability under changed  circumstances.  Certain provisions of the standard are required to be
adopted for transactions  occurring after May 15, 2002; other provisions are required to be adopted for financial  statements
issued after May 15, 2002.  The Company is currently  evaluating  the impact of this standard on its  financial  position and
results of operations.




9.  Comprehensive Income:
   Comprehensive  income consists of net income and other gains and losses  affecting  common equity that, under generally
accepted  accounting  principles,  are excluded  from net income.  Comprehensive  income is presented  net of tax. For the
fiscal  years  ended  March 31,  2002 and 2001,  and the three  month  periods  ended 2000 and 1999 and for the year ended
December 31, 1999, tax charge (benefit) related to comprehensive  income were approximately  $22,000,  ($94,000),  $11,000, $1,000
and $12,000, respectively.  For the Company, the components of accumulated other comprehensive (loss) consist of unrealized gains and
losses on marketable equity investments.

Note B – Regulatory Environment and Accounting Implications

Prior to divesting  substantially all of its nonnuclear  generation  business in 1998, the Company was the wholesale supplier
of the electric energy requirements to its retail distribution  affiliates as well as unaffiliated  customers.  The Company’s
all–requirements  contracts with its affiliated distribution  companies,  as well as with some unaffiliated  customers,  were
generally  terminated  pursuant to  settlement  agreements  and tariff  provisions  in 1998.  However,  the Company  remained
obligated to provide  transition  power supply service to new customer load in Rhode Island at the standard offer price,  but
did not have a regulatory  agreement  that  necessarily  allowed  full  recovery of the costs of such  standard  offer power.
Consequently,  the  Company  was at risk for the  difference  between  the actual  cost of serving  this load and the revenue
received  from this  obligation.  For the year ended March 31,  2002,  the impact on the  Company’s  financial  position  was
immaterial.  Effective December 1, 2001, a third party assumed the responsibility for providing  transitional  standard offer
power service in Rhode Island, and the Company’s obligation terminated.

Under  settlement  agreements,  the Company is permitted to recover costs associated with its former  generating  investments
and related  contractual  commitments that were not recovered through the sale of those investments  (stranded costs).  These
costs are  recovered  from the  Company’s  wholesale  customers  with which it has  settlement  agreements  through  contract
termination  charges  (CTC) which the  affiliated  wholesale  customers  recover  through  delivery  charges to  distribution
customers.  The recovery of the Company’s stranded costs (including Montaup Electric  Company’s  (Montaup),  a former Eastern
Utilities  Associates (EUA) subsidiary) is divided into several categories.  The Company’s  unrecovered costs associated with
generating  plants (nuclear and nonnuclear) and most regulatory  assets will be fully recovered through the CTC by the end of
2009 and earn a return on equity (ROE) averaging 9.7 percent.  The Company’s  obligation  related to the above-market cost of
purchased  power  contracts  and nuclear  decommissioning  costs are  recovered  through  the CTC as such costs are  actually
incurred.  As the CTC rate declines,  the Company,  under certain of the settlement  agreements,  earns  incentives  based on
successful  mitigation of its stranded costs.  These incentives  supplement the Company’s ROE. Until such time as the Company
divests its operating nuclear interests,  the Company will share with customers,  through the CTC, 80 percent of the revenues
and operating costs related to the units, with shareholders retaining the balance.

In conjunction with the divestiture,  the Company transferred to the buyer of its nonnuclear  generating business (the buyer)
its  entitlement to power procured under several  long-term  contracts in exchange for monthly fixed payments by the Company.
Similar to the Company,  Montaup also  transferred its purchased  power  obligations as part of the divestiture and in return
agreed to make fixed monthly  payments.  These fixed monthly payments by the Company,  inclusive of Montaup’s share,  average
approximately  $11 million per month through  December 2009 toward the above-market  cost of those  contracts.  The liability
relating to purchased power obligations,  which is also reflected in regulatory  assets,  represents the net present value of
these fixed monthly payments.  At March 31, 2002, the net present value is approximately $659 million.  For certain contracts
which have been  formally  assigned to the buyer,  the Company has made lump sum payments  equivalent to the present value of
the monthly fixed payment  obligations of those  contracts  (approximately  $453 million),  which were separate from the $659
million figure referred to above.




FERC Proceedings

In general,  the  regulatory  structure and  regulations  which relate to the  Company's  business are in a period of major
change and  uncertainty.  Decisions  being made by the Federal  Energy  Regulatory  Commission  (FERC) and the  Independent
System  Operator-New  England  (ISO New  England)  will affect how the Company  does  business and whether it can enter new
endeavors.  The Company is currently  unable to determine  whether  these  proceedings  will have a material  impact on its
financial position or results of operations.

The FERC has been reviewing the development of regional  transmission  organizations (RTOs). The FERC has indicated that it
wants RTOs to have large  geographic  scope.  In July and August,  2001,  the FERC ordered  National Grid USA and other New
England  parties  and  participants  of  the  New  York  Independent  System  Operator  (ISO),  and  the   Pennsylvania-New
Jersey-Maryland  (PJM) ISO to participate  in a mediation  process to develop a proposal for a larger RTO. The FERC has not
yet ruled on the mediation report issued in September 2001.  Pending the ruling on the mediation  report,  the transmission
owners have been  working  toward a hybrid RTO  structure in which an  independent  transmission  company  would manage the
transmission grid for the RTO and an independent market  administrator  would manage power markets for the RTO. However, it
is not clear what sort of RTO structure will ultimately  result from these  negotiations.  In fact,  based on a January 29,
2002 filing by the New York and New England ISOs to form their own RTO, even the  geographic  scope of the RTO in which the
Company will participate is still an open question.

In late 2001 and early 2002, the FERC convened an advanced rulemaking  proceeding to enable transmission  owners, such as the
Company,  and  generators  to  establish  standardized   procedures  and  agreements  concerning  the  way  generators  would
interconnect  with the transmission  grid. On April 24, 2002, the FERC issued proposed rules very favorable to generators and
unfavorable,  and, the Company  believes,  at times  unworkable,  for  transmission  owners.  The Company has submitted
comments seeking  significant  changes in the proposed rules. The FERC is expected to issue final rules later this
year.

In 2001, the FERC began an advanced  rulemaking  procedure to address Standard Market Design regarding the buying and selling
of power.  In a December  2001 order,  the FERC  requested  that all  industry  segments  try to agree on a single  standards
setting  organization that would establish  national standard business  practices for the wholesale  electric  industry.  The
FERC has also solicited  comments on a wide range of issues,  including:  transmission  pricing,  pricing for electric energy
and capacity,  transmission planning,  generation dispatch, RTO governance,  market monitoring, long term generation adequacy
(including  installed  capacity or “ICAP”),  and  resolution  of “seams” – or  conflicting  practices or charges that inhibit
inter-regional  energy  transactions.  All of these  either  directly or  indirectly  affect the  Company’s  business.  It is
anticipated that the FERC will launch a formal notice of proposed rulemaking proceeding this summer.

NEPOOL and ISO New England have a separate  standard  market  design  initiative  which is proceeding in parallel to the FERC
initiative.  It is expected  that either New England  Power Pool  (NEPOOL) or ISO New England will file a proposal to conform
the  procedures  by which  energy  is  bought  and sold in New  England  to those  of PJM  with  the  FERC  this  summer  for
implementation by December 2002 or early 2003.

To the extent the Company wishes to pursue  opportunities to manage or to be a member of an independent  transmission company
or an RTO, with the  opportunity to propose  financial  incentives to deliver  greater value for customers and  shareholders,
the FERC rulings in the standard market design proceeding and other proceedings may have an impact on the ability to do so.

In June 2001, the FERC issued an order relating to (NEPOOL’s proposed  congestion  management and  multi–settlement  systems.
In the June Order,  the FERC found that “energy  uplift” costs (which had been about $9 million per month for NEPOOL in 2000)
should be allocated on the basis of reliance on the energy markets  administered by the ISO New England.  This would have the
effect of relieving  parties that procure  power under  bilateral  contracts  (such as the Company) from paying energy uplift
charges.  However,  the NEPOOL  Participants  Committee and ISO New England  submitted a filing in July 2001 that the Company
believed did not comport with the FERC's order.  The Company  protested the filing,  and received a favorable  order from the
FERC on February 15, 2002.  Nevertheless,  the NEPOOL Participants  Committee and ISO New England submitted another filing on
March 18, 2002 that the Company  believes  does not comport with the FERC's  orders,  and the Company has again filed another
protest.

On September 27, 2001, the FERC initiated a notice of proposed  rulemaking  regarding  affiliate standards of conduct in both
the electric and gas industries.  In its proposed rules,  the FERC proposed a broad definition of “energy  affiliate”,  which
would include its affiliate  National Grid USA Service  Company,  Inc.  (Service  Company) as well as the Company’s  electric
distribution  company affiliates.  The proposed rules would impose significant  restrictions on the ability of the Company to
interact with such “energy  affiliates.” If not modified,  the proposed rules could require  significant  reorganization  for
the Company and possibly duplication of support functions that the Company depends on the Service Company to provide.

As previously  reported,  there has been litigation  regarding a FERC order to increase the ICAP  deficiency  charge to $8.75
per  kilowatt-month  (kW-month)  instead of the rate proposed by ISO New England of $0.17 per kW-month.  In June 2001,  after
significant  litigation  and a remand from the US Court of Appeals for the First  Circuit,  ISO New England made a Compliance
Filing with the FERC  proposing a compromise  ICAP regime,  including an ICAP  deficiency  charge of $4.87 per  kW-month.  On
September 28, 2001, the FERC issued an order refusing to apply  retroactively  the $8.75 per kW-month  deficiency  charge for
the period  January to June 2000. On November 20, 2001,  the FERC issued an order on rehearing of the August order  requiring
ISO New England to establish a prospective  ICAP regime (i.e.,  one under which utility ICAP purchase  requirements are known
in advance) in lieu of a  retrospective  requirement  with a cure  period.  It is unclear  what system will  replace the ICAP
regime in the future.  The issue of the appropriate ICAP deficiency  charge for the period January to July 2000, is currently
back before the US Court of Appeals for the First Circuit for  resolution.  FERC is also now  addressing  complaints by power
marketers  about how ICAP  should have been  charged  for the period  January to July 2000.  Both of these  proceedings  will
likely affect the Company’s ICAP exposure.

Because electric utility rates have historically been based on a utility's costs,  electric  utilities are subject to certain
accounting  standards that are not applicable to other business  enterprises in general.  The Company  applies the provisions
of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated  entities,  in
appropriate  circumstances,  to establish regulatory assets or liabilities,  and thereby defer the income statement impact of
certain  charges or revenues  because they are expected to be collected or refunded  through  future  customer  billings.  In
1997,  the Emerging  Issues Task Force of the FASB concluded  that a utility that had received  approval to recover  stranded
costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.

The Company has received  authorization  from the FERC to recover through CTCs substantially all of the costs associated with
its former generating business not recovered through the divestiture.  Additionally,  FERC Order No. 888 enables transmission
companies to recover their specific costs of providing  transmission service.  Therefore,  substantially all of the Company’s
business,  including the recovery of its stranded costs,  remains under  cost-based rate  regulation.  Because of the nuclear
cost-sharing  provisions  related to the  Company’s  CTC,  the Company  ceased  applying  FAS 71 in 1997 to 20 percent of its
ongoing nuclear operations, the impact of which is immaterial.

As a result of  applying  FAS 71, the  Company  has  recorded a  regulatory  asset for the costs  that are  recoverable  from
customers  through the CTC. At March 31, 2002, this amounted to  approximately  $1.5 billion,  including $1.0 billion related
to the  above-market  costs of purchased power  contracts,  $0.2 billion  related to accrued Yankee nuclear plant costs,  and
$0.3 billion related to other net CTC regulatory assets.

Note C – Mergers and Acquisitions

Merger with National Grid
On March 22,  2000,  the merger of New  England  Electric  System  (NEES) and  National  Grid Group plc  (National  Grid) was
completed,  with NEES  (renamed  National  Grid USA)  becoming a wholly  owned  subsidiary  of  National  Grid.  The  Company
maintained  its existing  name and remained a wholly owned  subsidiary  of National Grid USA. The merger was accounted for by
the purchase method,  the application of which,  including the recognition of goodwill,  was pushed down and reflected on the
financial statements of the National Grid USA subsidiaries,  including the Company.  Total goodwill amounted to $1.7 billion,
of which the Company was allocated  approximately $348 million.  This amount was determined  pursuant to a study conducted by
an independent third party.

The purchase  accounting  method  requires the revaluation of assets and  liabilities to their fair value.  This  revaluation
resulted in an adjustment to the Company’s  pension and  postretirement  benefit accounts in the amount of approximately  $61
million, with an offsetting net credit to a regulatory liability account.

Acquisition of EUA
The  acquisition  of EUA by National  Grid USA was  completed on April 19, 2000 for $642  million.  On May 1, 2000,  Montaup,
formerly a subsidiary of EUA, was merged into the Company.

The  acquisition of EUA was accounted for by the purchase  method,  the  application of which,  including the  recognition of
goodwill,  has been pushed down and reflected on the financial  statements of the National Grid USA  subsidiaries,  including
the Company.  Total  goodwill  recognized  in this  transaction  was  approximately  $402  million,  of which the Company was
allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party.

The purchase  accounting  method  requires the revaluation of assets and  liabilities to their fair value.  This  revaluation
resulted in an adjustment to the Company’s  pension and  postretirement  benefit accounts in the amount of approximately  $3
million, with an offsetting net credit to a regulatory liability account.

In connection  with the mergers referred to above,  the  Company  adjusted  its  pension  and PBOP  accounts in the amount of
approximately $64 million,  with an offsetting net credit to a regulatory liability account.  This adjustment  eliminated any
unrecognized net gain or loss,  unrecognized prior service cost, or unrecognized  transition  obligation of the Company.  The
regulatory liability is being amortized over the service period to pension and postretirement health care costs.





Note D – Accounting for Nuclear Power Companies

1. Yankee Nuclear Power Companies
The Company has minority  interests in four Yankee Nuclear Power  Companies.  These ownership  interests are accounted for on
the equity  method.  Three of the  Yankees  have been  permanently  shut down,  and one is  operating.  The Company has power
contracts  with  each of the  Yankees  that  require  the  Company  to pay an amount  equal to its  share of total  fixed and
operating costs (including  decommissioning  costs) of the plant plus a return on equity. The Company’s share of the expenses
of the Yankees is accounted for in “Purchased electric energy” on the income statement.

===================================== =================================== ================================= ==================
                                                  Year Ended                Three Months Ended March 31,       Year Ended
                                                   March 31,                                                  December 31,
                                                2002                2001             2000             1999        1999
(In thousands)                                                                                 (unaudited)
===================================== =============== =================== ================ ================ ==================
===================================== =============== =================== ================ ================ ==================
Operating revenue                          $ 284,663          $  291,628        $  81,225        $  89,244         $  377,039
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net income                                 $  14,711           $  29,589         $  5,310         $  5,138          $  13,890
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Company’s equity in net income             $   3,332            $  6,703          $   862          $   515           $  2,939
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net plant                                    143,182             160,701          167,317          166,062            172,100
Other assets                               1,812,032           1,893,733        2,520,887        2,798,948          2,631,750
Liabilities and debt                     (1,775,130)         (1,855,775)      (2,437,609)      (2,707,749)        (2,554,261)
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net assets                                 $ 180,084           $ 198,659        $ 250,595        $ 257,261          $ 249,589
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Company’s equity in net assets             $  40,339           $  46,474         $ 45,966        $  47,323          $  46,233
------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
----------------------------------------------------- ------------------- ---------------- ---------------- ------------------
Company's purchased electric energy:
       Vermont Yankee                        $33,031           $  31,899         $  7,761         $  7,874          $  37,551
       All other Yankees                     $24,420           $  21,616         $  9,324         $  9,370          $  37,765
------ ------------------------------ --------------- ------------------- ---------------- ---------------- ------------------

At March 31, 2002,  approximately  $8 million of  undistributed  earnings of the nuclear power companies were included in the
Company’s retained earnings.

2.  Seabrook 1 Nuclear Generating Unit
The Company has a minority  non-operating  ownership  interest in the Seabrook 1 Nuclear  Generating  Unit  (Seabrook 1). The
Company’s  share of expenses for Seabrook 1 is accounted for in “Other  operation” and  “Maintenance”  expenses on the income
statement.



Note E - Commitments and Contingencies

1. Nuclear Units
Nuclear Units Permanently Shut Down
Three of the Yankees in which the Company has a minority  interest own nuclear  generating  units that have been  permanently
shut down. These three units are as follows:

--------------------------------------------- ---------------------------------- ----------------------- ------------------------
                                                                                                            Future Estimated
                                               The Company’s Investment as of                            Billings to the Company
                                                           3/31/02
Unit                                                 %           $(millions)               Date Retired        $(millions)
--------------------------------------------- ---------------- ----------------- ----------------------- ------------------------
--------------------------------------------- ---------------- ----------------- ----------------------- --------------- --------
Yankee Atomic                                      34.5              0.4                       Feb 1992               0
Connecticut Yankee                                 19.5               13                       Dec 1996              44
Maine Yankee                                       24.0               15                       Aug 1997             123

Yankee  Atomic  has  discontinued  further  billings  to the  Company,  subject  to a  final  reconciliation  of  costs  once
decommissioning  at the plant has been  completed.  For Maine  Yankee and  Connecticut  Yankee,  the Company  has  recorded a
liability and a regulatory asset reflecting the estimated future billings from the companies.

Under the provisions of the Company’s industry  restructuring  settlement agreements approved by state and federal regulators
in 1998, the Company  recovers all costs,  including  shutdown costs,  that the FERC allows these Yankee companies to bill to
the Company.

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.

Maine Yankee had previously hired Stone and Webster, Inc. (S and W), an engineering,  construction,  and consulting company, as the
principal  contractor to  decommission  the unit. In May 2000,  Maine Yankee  terminated its long-term  contract with S and W and
negotiated an  arrangement  with S and W to continue  work through June 2000.  In June 2000,  S and W filed for Chapter 11 bankruptcy
protection.  Subsequently,  Maine Yankee decided to self-manage the unit’s  decommissioning  process.  In June 2000,  Federal
Insurance Company (Federal) filed a complaint in S and W’s bankruptcy  proceedings,  subsequently removed to US District Court in
Maine,  which alleged that Maine Yankee  improperly  terminated its contract with S and W and that Federal should be excused from
$39 million performance bond and $12 million payment bond to Maine Yankee.

In December 2001,  Maine Yankee and Federal reached a settlement.  Pursuant to the settlement  agreement,  Federal paid Maine
Yankee $44 million in January 2002.  Maine Yankee  deposited the payment in its  decommissioning  trust fund.  With regard to
Maine Yankee’s  August 2000 damage claim against S and W in the bankruptcy  proceeding for $78.2 million (later  decreased to $21
million to reflect,  among other things,  the recovery of $44 million from Federal),  on May 30, 2002,  the bankruptcy  judge
held that Maine  Yankee has proved  damages of $20.8  million and  estimated  its claim at that amount.  However,  the amount
Maine Yankee  actually  recovers  will depend on the  magnitude of assets in the bankrupt  estate  available to pay creditors
claims.

At Maine  Yankee and Yankee  Atomic,  the  contractor  responsible  for the  movement  of spent fuel from wet  storage to dry
storage has incurred  delays.  Connecticut  Yankee has experienced  delays in its  decommissioning  process due to zoning and
other issues, most of which are now resolved.

Due to rate  recovery  mechanisms,  the S and W claims and  decommissioning  delays are not  expected  to  materially  affect the
Company’s earnings.

Operating Nuclear Units

The Company has  minority  interests  in two  operating  nuclear  generating  units that the Company is engaged in efforts to
divest:  Vermont  Yankee and Seabrook 1. In addition,  the Company sold its 16.2 percent  interest in Millstone 3 to Dominion
Resources,  Inc.  (Dominion) on March 31, 2001. Until such time as the Company divests its operating  nuclear  interests,  80
percent of the revenues and  reasonable  operating  costs  related to the units will be  allocated to the  customers  through
CTCs,  with  shareholders  being  allocated  the balance.  Net proceeds  attributed to the  divestiture  of the units will be
allocated to customers through CTC.

Vermont Yankee
The following table summarizes the Company’s interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2002:

                                                        The Company’s Interest
                                                         (millions of dollars)
                    ------------------------------------------------------------------------------------------------
                    ----------------- ------------- ---------------------------------------- -----------------------
 Equity                                    Net                                                     Decommissioning
 Ownership             Equity            Plant              Estimated Decommissioning                 Fund              License
   Interest (%)        Investment        Assets                 Cost (in 2001$)                      Balance          Expiration
------------------- ----------------- ------------- ---------------------------------------- ----------------------- -------------
------------------- ----------------- ------------- ---------------------------------------- ----------------------- -------------
       23.9               $12             $34                        $107                             $63                2012

In  December  2001,  Vermont  Yankee  reached a  settlement  with four equity  owners,  other than the  Company,  agreeing to
repurchase the Vermont Yankee shares held by these minority  shareholders  for $230 per share. The repurchase was consummated
in January 2002 for approximately $5.4 million.  As a result, of the repurchase,  the Company’s ownership interest in Vermont
Yankee increased from 22.5 percent to 23.9 percent.

On August 15, 2001,  Vermont Yankee  announced  that it had reached an Agreement  (the  Agreement) to sell the Vermont Yankee
nuclear  power plant to Entergy  Corporation  (Entergy) for $180  million.  The Company’s  portion of the sale price would be
approximately  $43 million  ($35  million for the plant and  related  assets and $8 million for nuclear  fuel) based upon its
23.9 percent ownership interest.  The plant’s  decommissioning  trust fund would be transferred to Entergy, and Entergy would
assume  decommissioning  liability for the plant. As part of the transaction,  Vermont Yankee owners,  including the Company,
would  purchase  power from the plant through 2012.  Net proceeds from the sale would be credited to the Company’s  customers
through the CTC. The sale of the plant is  contingent  upon the receipt of  regulatory  approvals by the SEC,  under the 1935
Act, the FERC, the NRC, the Vermont Public Service Board (VPSB),  and other state regulatory  commissions  with  jurisdiction
over other  equity  owners of Vermont  Yankee.  The FERC,  the NRC and the VPSB have  approved  the sale.  On June 21,  2002,
Entergy filed a motion  seeking  reconsideration  by the VPSB of a condition in its order  approving the sale.  The condition
rejected a provision in the Agreement  entitling Entergy to keep 50 percent of any property remaining in the  decommissioning
trust fund upon  completion of  decommissioning.  The Agreement with Entergy  terminates if the sale is not completed by July
31, 2002.

The Company  previously sold 11.8 MW of its Vermont Yankee  entitlement to a number of municipal and cooperative  utilities
(Secondary  Purchasers)  located in  Massachusetts  under a “Vermont  Yankee  Secondary  Purchaser  Agreement”  which had a
30-year term  expiring on November 30, 2002.  On May 16, 2002,  the FERC  approved an early  termination  of the  Secondary
Purchasers  contract  effective  February 28, 2002.  Pursuant to the  settlement,  the Secondary  Purchasers  agreed not to
oppose the plant sale in any regulatory proceeding.

The  Citizens of  Brattleboro,  and eight other towns in Vermont,  cast non binding  votes at town  meetings in March 2002 on
whether  Vermont Yankee should be shut down. In the nine towns that voted on the issue,  a narrow  majority chose to keep the
plant open.

Seabrook 1
The following table summarizes the Company’s interest in the Seabrook 1 nuclear generating unit as of March 31, 2002:

                                    The Company’s share of (millions of dollars)
                    ------------------------------------------------------------------------------
                    -------------- ---------------------------------------- ----------------------
  The Company’s          Net              Estimated Decommissioning            Decommissioning         License
    Ownership                                                                       Fund
   Interest (%)      Plant Assets              Cost (in 2001$)                     Balance*          Expiration
------------------- -------------- ---------------------------------------- ---------------------- ----------------
------------------- -------------- ---------------------------------------- ---------------------- ----------------
        10             $17 **                        $55                             $19                2026

*    Certain additional amounts are anticipated to be available through tax deductions.
** Represents post-December 1995 spending including nuclear fuel.

On April 15, 2002,  eight of the 11 joint  owners of Seabrook,  including  the  Company,  announced  that they had reached an
agreement  to sell an 88.2  percent  interest in Seabrook to FPL Energy  Seabrook LLC (FPL  Seabrook),  a  subsidiary  of FPL
Group, for $836.6 million.  The Company’s portion of the gross sales proceeds would be approximately $93.5 million.  Pursuant
to the terms of the Company’s  restructuring  settlements,  98 percent of the Company’s proceeds,  net of expenses related to
the sale,  post-1995 capital additions and inventories,  will be returned to National Grid customers in Massachusetts,  Rhode
Island,  and New  Hampshire.  FPL  Seabrook  will assume  responsibility  for ultimate  decommissioning  of Seabrook and will
receive the Seabrook  decommissioning funds, including a top-off payment by the Company and other sellers.  Approvals for the
transaction  are needed from federal and state  regulatory  agencies,  including  public utility  commissions in the sellers’
states, the NRC, the New Hampshire Nuclear  Decommissioning  Financing  Committee  (NHNDFC),  the FERC, and the Department of
Justice or the Federal Trade Commission. The plant owners are targeting to complete the sale by the end of 2002.

Millstone 3
In November  1999,  the Company  entered into an  agreement  with  Northeast  Utilities  (NU) to settle  claims made by the
Company  regarding  the  operation  of  Millstone  3. Among other  things,  the  settlement  provided for NU to include the
Company’s 16.2 percent  interest in Millstone 3 in an auction of NU’s share of the unit.  Upon the closing of the sale, the
Company was to receive a fixed amount, regardless of the actual sale price.

In August 2000,  Dominion agreed to purchase the Millstone units,  including the Company’s  interest in Millstone 3, for $1.3
billion.  In March 2001, the sale was completed.  In accordance  with the prior  settlement  agreement,  the Company was paid
approximately  $27.9  million,  including  $25 million for the plant,  and the Company  paid  approximately  $5.8  million to
increase the decommissioning trust fund.

Regulatory  authorities  from Rhode  Island,  New  Hampshire  and  Massachusetts  have  expressed an intent to challenge  the
reasonableness  of the settlement  agreement as the Company would have received  approximately  $140 million of sale proceeds
without the  agreement.  The dispute  will be resolved by the FERC.  The Company  believes it has a strong  argument  that it
acted  prudently  since the amount  received under the settlement  agreement was the highest sale price for a nuclear unit at
the time the agreement was reached.

Nuclear Decommissioning
The Company is liable for its share of  decommissioning  costs for 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 units.
Such costs reflect estimates of total decommissioning  costs approved by the FERC. The Company records  decommissioning costs
on its books consistent with its rate recovery.  The Company is recovering its share of projected  decommissioning  costs for
Seabrook 1 through depreciation  expense. In addition,  the Company is paying its portion of projected  decommissioning costs
for  Connecticut  Yankee and Maine Yankee.  The Company has completed its  projected  decommissioning  obligation  for Yankee
Atomic, subject to a final reconciliation of decommissioning costs.

In New  Hampshire,  legislation  was enacted in 1998 that makes  owners of Seabrook 1, in which the Company owns a 10 percent
interest,  proportional  guarantors  for  decommissioning  costs in the  event  that an owner  without  a  franchise  service
territory fails to fund its share of decommissioning costs.  Currently,  there is a single owner of an approximate 15 percent
share of Seabrook 1 that is subject to the  legislation.  The impact of this  legislation  to the  Company is not  considered
material to its financial position or results of operation.

On July 6, 2001,  legislation  was enacted to modify New Hampshire’s  current  decommissioning  law. This new  legislation,
initiated and supported by Seabrook’s joint owners,  including the Company,  was designed to protect  customers from future
decommissioning  risks.  The legislation  reduces the standard for  non-radiological  decommissioning  at the site and will
allow the buyer of the plant to retain  any  decommissioning  funds in  excess of those  contributed  by  customers  of the
present owners.

The NHNDFC has authority to implement the new  decommissioning  law. Under the new law, the NHNDFC is charged with assuring
that the buyer of Seabrook will have adequate  funding to complete  decommissioning  in the event the plant is  prematurely
shutdown.

On November  5, 2001,  the NHNDFC  issued an order  substantially  approving a  settlement  establishing  proposed  terms for
funding  assurance.  The  terms  of the  settlement  included  a  cash  “top-off”  payment  to the  decommissioning  fund  of
approximately  $57 million at the time of the sale. In addition,  the buyer of the plant would be required to accelerate  its
annual  decommissioning  fund  contributions  through  2006 and provide a funding  assurance  package of  approximately  $125
million that would decline over time as additional annual contributions are made to the fund.

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 the Company to pay a fee based on its
share of the net  generation  from the Seabrook 1 nuclear  generating  unit.  Prior to 1998,  the Company  recovered this fee
through its fuel clause.  Under settlement  agreements,  substantially all of these costs are recovered through CTCs. Similar
costs are billed to the Company by Vermont Yankee and are also recovered  from customers  through CTCs. In 1997,  ruling on a
lawsuit brought against the DOE by numerous  utilities and state  regulatory  commissions,  the U.S. Court of Appeals for the
District of Columbia  held that the DOE was obligated to begin  disposing of  utilities’  spent nuclear fuel by January 1998.
The DOE failed to meet this deadline and is not expected to have a temporary or permanent  repository  for spent nuclear fuel
before 2010, at the earliest.  Many utilities,  including Yankee Atomic,  Connecticut  Yankee,  and Maine Yankee filed claims
for money damages in the U.S. Court of Federal Claims for the costs  associated  with the DOE’s failure to begin to take fuel
in 1998.  The court held that the DOE is liable for such failure in October 1998.  The Yankee  Companies have filed a further
action  against  the DOE to  determine  the level of  damages.  As an  interim  measure  until the DOE meets its  contractual
obligations  to dispose of their spent fuel,  those  companies are proceeding  with  construction  of independent  spent fuel
storage installations on the plant sites.

Each nuclear  unit in which the Company 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.  There is no  assurance  that
decommissioning  costs actually  incurred by Seabrook 1 or the Yankees will not substantially  exceed the estimated  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. The temporary low-level  repository located in Barnwell,
South Carolina may become  unavailable,  which could  increase the cost of  decommissioning  the Yankee  Atomic,  Connecticut
Yankee,  and Maine Yankee plants. If either of the operating units were shut down prior to the end of its operating  license,
the funds collected for decommissioning to that point would be insufficient.  Under settlement  agreements,  the Company will
recover decommissioning costs through CTCs.

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 $9.5  billion  (based upon 106  licensed  reactors).  The  maximum  amount of  commercially  available
insurance  coverage to pay such claims is $200 million.  The remaining  $9.3 billion would be provided by an assessment of up
to $88.1 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 1998, is adjusted for inflation at least every five years.  The Company’s  current interest in Vermont Yankee and
Seabrook 1 would subject the Company to a $29.8 million maximum  assessment per incident.  The Company’s  payment of any such
assessment  would be  limited  to a maximum  of $3.4  million  per  year.  As a result of the  permanent  cessation  of power
operation of the Yankee  Atomic,  Connecticut  Yankee,  and Maine Yankee  plants,  these units have  received from the NRC an
exemption from  participating in the secondary  financial  protection system under the  Price-Anderson  Act.  However,  these
plants must continue to maintain $100 million of commercially available nuclear liability insurance coverage.

Each of the nuclear  units in which the Company has either an ownership  or purchased  power  interest  also carries  nuclear
property insurance to cover the costs of property damage,  decontamination,  and premature  decommissioning  resulting from a
nuclear  incident.  These policies may require  additional  premium  assessments if losses  relating to nuclear  incidents at
units covered by this  insurance  occur in a prior  six-year  period.  The  Company’s  maximum  potential  exposure for these
assessments, either directly or indirectly, is approximately $6.0 million with respect to the current policy period.

2.  Plant Expenditures
The Company’s  utility plant  expenditures are estimated to be  approximately  $34 million for fiscal year 2003. At March 31,
2002, substantial commitments had been made relative to future planned expenditures.

3.  Hydro-Quebec Interconnection
Three  affiliates  of the Company  were created to  construct  and operate  transmission  facilities  to transmit  power from
Hydro-Quebec  to New England.  Under support  agreements  entered into at the time these  facilities  were  constructed,  the
Company agreed to guarantee a portion of the project debt. At March 31, 2002, the Company had  guaranteed  approximately  $20
million of project  debt,  including $4 million  originally  guaranteed by Montaup,  with terms  through 2015.  The Company’s
rights and obligations  under its support  agreements  were  transferred to the purchaser of its nonnuclear  generation.  The
Company remains an obligor under the support  agreements,  (excluding the Montaup  obligations)  until 2020. Costs associated
with these support agreements are recoverable through the Company’s transmission rates.

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.  The Company currently has in place an internal  environmental  audit program and an external waste
disposal vendor audit and  qualification  program  intended to enhance  compliance with existing  federal,  state,  and local
requirements regarding the handling of potentially hazardous products and by-products.

The Company has been named as a  potentially  responsible  party (PRP) by either the United States  Environmental  Protection
Agency or the Massachusetts  Department of Environmental  Protection for several sites at which hazardous waste is alleged to
have been  disposed.  Private  parties have also  contacted  or initiated  legal  proceedings  against the Company  regarding
hazardous  waste cleanup.  The Company is currently  aware of other  possible  hazardous  waste sites,  and may in the future
become  aware of  additional  sites,  that it may be held  responsible  for  remediating.  Some of these sites  relate to the
disposal of ash from fossil fuel generating plants formerly owned by the Company.

Predicting the potential costs to investigate and remediate  hazardous waste sites continues to be difficult.  There are also
significant  uncertainties as to the portion, if any, of the investigation and remediation costs of any particular  hazardous
waste site that may ultimately be borne by the Company.  The Company has recovered amounts from certain insurers,  and, where
appropriate,  intends to seek  recovery from other  insurers and from other PRPs,  but it is uncertain  whether,  and to what
extent, such efforts will be successful.  The Company is currently recovering certain  environmental  cleanup costs in rates.
The Company  believes that hazardous  waste  liabilities for all sites of which it is aware are not material to its financial
position.

5.   Town of Norwood Dispute
From 1983 until 1998,  the Company was the wholesale  power  supplier for the Town of Norwood,  Massachusetts  (Norwood).  In
April 1998,  Norwood began taking power from another  supplier.  Pursuant to a tariff  amendment  approved by the FERC in May
1998,  the Company has been  assessing  Norwood a contract  termination  charge.  Through  March 2002,  the charges  assessed
Norwood  amount to  approximately  $43  million,  all of which  remain  unpaid.  The  Company  filed a  collection  action in
Massachusetts  Superior Court (Superior Court).  The Superior Court deferred action until the various appeals described below
were decided.  On March 14, 2001, the Superior Court ordered Norwood to pay the Company  approximately  $27 million including
interest,  and  affirmed  Norwood’s  obligation  to make  monthly  contract  termination  charge  payments  to the Company of
approximately  $600,000,  plus interest.  Norwood appealed the order on April 11, 2001.  Pending the appeal,  Norwood entered
into a consent  order to  establish a  segregated  account for the benefit of the Company in the amount of $14 million and to
make regular additions to the account.

Separately,  Norwood filed suit in Federal  District Court  (District  Court) in April 1997 alleging that the  divestiture of
the  Company’s  nonnuclear  generation  business  (the  divestiture)  violated  the  terms of the  1983  power  contract  and
contravened  antitrust laws. The District Court dismissed the lawsuit.  On appeal,  the First Circuit Court of Appeals (First
Circuit)  also  consolidated  appeals  Norwood made from the FERC’s  orders  approving the  divestiture,  the wholesale  rate
settlement between the Company and its distribution  affiliates,  and the contract  termination  charge tariff amendment.  In
February 2000, the First Circuit  dismissed  Norwood’s  appeal from the FERC orders and dismissed its appeal from all but one
of Norwood’s  District Court claims,  which relates to alleged  generation market power.  Norwood filed several petitions for
review. Finally, in October 2000, the US Supreme Court refused Norwood’s petitions to review the First Circuit decisions.

In the District Court action,  in April 2000, the Company renewed its motion to dismiss  Norwood’s  remaining claim.  Norwood
amended its complaint to reassert a request for rescission of the divestiture,  which it had earlier  dropped.  The Company’s
motion to dismiss on the ground that it is not a proper party was denied in July 2001.  Still  pending is a motion to dismiss
the action on the ground of issue preclusion filed by co-defendant PG and E and joined in by the Company.




6. Contracts for the Purchase of Electric Power
The Company has contracts for the purchase of electric power.  The Company’s  commitments  for future fiscal  periods,  under
these long-term contracts as of March 31, 2002, is as follows (in thousands):  2003, $72,620;  2004, $69,209;  2005, $58,629;
2006, $42,043; 2007, $46,024; 2008 and thereafter, $263,740.

Note F - Employee Benefits

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

Net pension cost for the years ended March 31, 2002 and 2001 included the following components:

=============================================================================== =================================================
                                                                                                            Year Ended
                                                                                                              March 31,
(In thousands)                                                                                         2002                 2001
=============================================================================== ============================ ====================
=============================================================================== ============================ ====================
Service cost - benefits earned during the period                                                     $  809               $  482
Plus (less):
       Interest cost on projected benefit obligation                                                  8,729                8,381
       Return on plan assets at expected long-term rate                                            (12,789)             (12,440)
       Amortization of prior service cost                                                               195                    -
------ ----- ------------------------------------------------------------------ ---------------------------- --------------------
             Benefit income                                                                        $(3,056)             $(3,577)
------ ----- ------------------------------------------------------------------ ---------------------------- --------------------
------------------------------------------------------------------------------- ---------------------------- --------------------
Special termination benefits not included above                                                     $ 1,339        $           -
------------------------------------------------------------------------------- ---------------------------- --------------------




The funded status of the plan cannot be presented  separately for the Company as the Company  participates in the plan with
certain other National Grid USA subsidiaries  (Massachusetts  Electric Company, The Narragansett Electric Company,  Granite
State Electric Company,  Nantucket  Electric Company and National Grid USA Service Company,  Inc.). The following  provides
a reconciliation of benefit obligations and plan assets for the National Grid USA companies’ plan at March 31:

====================================================================== =========================== ==========================
(In millions)                                                                             2002                       2001
====================================================================== =========================== ==========================
====================================================================== =========================== ==========================
Change in benefit obligation:
Benefit obligation at beginning of period                                              $ 1,055                       $800
Service cost                                                                                14                         12
Interest cost                                                                               76                         72
Actuarial (gain)/loss                                                                      (8)                         47
Benefits paid                                                                             (76)                       (90)
Acquisitions                                                                                 -                        188
Special termination benefits                                                                13                          6
Plan amendments                                                                              -                         20
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Benefit obligation at end of period                                                      1,074                      1,055
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period                                         1,082                        991
Actual return on plan assets during year                                                    39                       (59)
Company contributions                                                                        8                          8
Benefits paid from plan assets                                                            (76)                       (90)
Acquisitions                                                                                 -                        232
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Fair value of plan assets at end of period                                               1,053                      1,082
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Funded status                                                                             (21)                         27
Unrecognized actuarial loss                                                                261                        206
Unrecognized prior service cost                                                             19                         20
---------------------------------------------------------------------- --------------------------- --------------------------
Net amount recognized                                                                     $259                       $253
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Amounts recognized in the statement of financial position consist
  of:
Prepaid benefit cost                                                                       346                        338
Accrued benefit liability                                                                 (90)                       (90)
Accumulated other comprehensive income                                                       3                          5
---------------------------------------------------------------------- --------------------------- --------------------------
---------------------------------------------------------------------- --------------------------- --------------------------
Net amount recognized                                                                     $259                       $253
---------------------------------------------------------------------- --------------------------- --------------------------

====================================================================== ======================================================
                                                                                                          March 31,
                                                                                             2002                       2001
====================================================================== =========================== ==========================
====================================================================== =========================== ==========================
Assumptions used to determine pension cost:
       Discount rate                                                                        7.50%                      7.50%
       Average rate of increase in future compensation level                                4.63%                      4.61%
       Expected long-term rate of return on assets                                          8.75%                      8.75%

Plan assets are composed primarily of equity and fixed income securities.



2.  Postretirement Benefit Plans Other than Pensions (PBOPs):
The Company  provides  health care and life  insurance  coverage to eligible  retired  employees.  Eligibility  is based on
certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

The Company's total cost of PBOPs for the years ended March 31, 2002 and 2001 included the following components:

=================================================================================== ==========================================
                                                                                                         Year Ended
                                                                                                           March 31,
(In thousands)                                                                                        2002               2001
=================================================================================== ======================= ==================
=================================================================================== ======================= ==================
Service cost - benefits earned during the period                                                     $ 225              $ 210
Plus (less):
       Interest cost on projected benefit obligation                                                 3,434              3,337
       Return on plan assets at expected long-term rate                                            (3,721)            (3,537)
       Amortization of net loss                                                                        120                  -
------ ----- ---------------------------------------------------------------------- ----------------------- ------------------
             Benefit cost                                                                            $  58              $  10
------ ----- ---------------------------------------------------------------------- ----------------------- ------------------
----------------------------------------------------------------------------------- ----------------------- ------------------
Special termination benefits not included above                                                      $  61              $   -
----------------------------------------------------------------------------------- ----------------------- ------------------



The following provides a reconciliation of benefit obligations and plan assets at March 31:

====================================================================== ========================= ============================
(In millions)                                                                           2002                         2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Change in benefit obligation:
Benefit obligation at beginning of period                                                $47                          $38
Interest cost                                                                              3                            3
Actuarial loss                                                                             7                            2
Benefits paid                                                                            (4)                          (4)
Acquisitions                                                                               -                            8
---------------------------------------------------------------------- ------------------------- ----------------------------
---------------------------------------------------------------------- ------------------------- ----------------------------
Benefit obligation at end of period                                                       53                           47
---------------------------------------------------------------------- ------------------------- ----------------------------
---------------------------------------------------------------------- ------------------------- ----------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period                                          41                           40
Actual return/(loss) on plan assets during year                                            1                          (1)
Company contributions                                                                      3                            2
Benefits paid from plan assets                                                           (4)                          (4)
Acquisitions                                                                               -                            4
---------------------------------------------------------------------- ------------------------- ----------------------------
---------------------------------------------------------------------- ------------------------- ----------------------------
Fair value of plan assets at end of period                                                41                           41
---------------------------------------------------------------------- ------------------------- ----------------------------
---------------------------------------------------------------------- ------------------------- ----------------------------
Funded status                                                                           (12)                          (6)
Unrecognized actuarial loss                                                               16                            7
---------------------------------------------------------------------- ------------------------- ----------------------------
Net amount recognized                                                                     $4                           $1
---------------------------------------------------------------------- ------------------------- ----------------------------

====================================================================== ======================================================
                                                                                                       March 31,
(In thousands)                                                                             2002                         2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Assumptions used to determine postretirement benefit cost:
       Discount rate                                                                      7.50%                        7.50%
       Expected long-term rate of return on assets                                        8.43%                        8.48%
       Health care cost rates:
             2001                                                                           N/A                        8.00%
             2002                                                                        10.00%                        6.50%
             2003                                                                         9.00%                        5.00%
             2004                                                                         8.00%                        5.00%
             2005                                                                         7.00%                        5.00%
             2006                                                                         6.00%                        5.00%
             2007+                                                                        5.00%                        5.00%

The assumptions  used in the health care cost trends have a significant  effect on the amounts  reported.  A one percentage
point change in the assumed rates would increase the accumulated  postretirement  benefit obligation (APBO) as of March 31,
2002 by  approximately  $6 million or decrease  the APBO by  approximately  $5 million,  and  increase or decrease  the net
periodic cost for fiscal year 2002 by approximately $400,000.

The Company generally funds the annual tax-deductible contributions.




3.  Voluntary Early Retirement
In January  2002, a limited  Voluntary  Early  Retirement  Offer (VERO) was extended to non-union  employees  who met certain
eligibility  requirements.  Eligible  employees  were in  targeted  functions  and would be age 55 with at least ten years of
pension  service by March 31, 2004.  This program is intended to reduce the National  Grid USA  workforce  through  voluntary
means.  The early  retirement  offer was accepted by 4 employees.  The Company recorded a charge to earnings of approximately
$2 million after tax, ($3 million,  before tax) to reflect  these costs.  This total  includes the  Company’s  portion of its
affiliated service company’s cost of the program.

Note G – Income Taxes

The Company and other  subsidiaries  participate  with  National  Grid General  Partnership,  a wholly owned  subsidiary of
National  Grid Group plc, in filing  consolidated  federal  income tax  returns.  The  Company’s  income tax  provision  is
calculated  on a separate  return  basis.  Federal  income tax returns  have been  examined and reported on by the Internal
Revenue Service through 1996.

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

================================================ ============================ ============================= ==================
                                                         Year Ended           Three Months Ended March 31,     Year Ended
                                                          March 31,                                           December 31,
                                                         2002           2001         2000             1999        1999
(In thousands)                                                                                 (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Income taxes charged to operations                    $47,593        $44,946       $9,641          $13,100            $37,633
Income taxes charged (credited) to
  "Other income"                                        1,694           (52)          (4)                -              1,985
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
-------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
         Total income taxes                           $49,287        $44,894       $9,637          $13,100            $39,618
-------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------

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

================================================ ============================ ============================= ==================
                                                         Year Ended           Three Months Ended March 31,     Year Ended
                                                          March 31,                                           December 31,
                                                         2002           2001         2000             1999        1999
(In thousands)                                                                                 (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Current income taxes                                  $65,359        $56,374      $12,545           $7,374           $ 25,507
Deferred income taxes                                (15,555)        (1,111)        (581)           10,732             25,921
Investment tax credits, net                             (517)       (10,369)      (2,327)          (5,006)           (11,810)
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
-------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
         Total income taxes                           $49,287        $44,894       $9,637          $13,100           $ 39,618
-------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------

Since 1998,  the Company has been  amortizing  previously  deferred  investment  tax credits  (ITC)  related to  generation
investments  over the CTC recovery  period.  Unamortized  ITC related to  generating  units  divested in 1998 and 2001 were
credited to other income  pursuant to federal tax law.  Previously  recognized ITC related to  transmission  facilities are
amortized over their estimated productive lives.




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

================================================ ============================ ============================= ==================
                                                         Year Ended           Three Months Ended March 31,     Year Ended
                                                          March 31,                                           December 31,
                                                         2002           2001         2000             1999        1999
(In thousands)                                                                                 (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Federal income taxes                                  $41,018       $ 38,350       $8,035          $10,975           $ 33,746
State income taxes                                      8,269          6,544        1,602            2,125              5,872
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------
        Total income taxes                            $49,287       $ 44,894      $ 9,637          $13,100           $ 39,618
------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------

With regulatory approval from the FERC, the Company has adopted  comprehensive  interperiod tax allocation  (normalization)
for temporary book/tax differences.

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

================================================ ============================ ============================= ==================
                                                         Year Ended           Three Months Ended March 31,     Year Ended
                                                          March 31,                                           December 31,
                                                         2002           2001         2000             1999        1999
(In thousands)                                                                                 (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Computed tax at statutory rate                       $ 44,121        $36,118      $ 8,435          $11,706            $38,721
Increases (reductions) in tax resulting
  from:
        Amortization of investment tax
          credits                                       (336)        (7,762)      (1,513)          (3,254)            (7,677)
        State income taxes, net of
          federal income tax benefit                    5,375          4,254        1,042            1,381              3,817
        Rate recovery of deficiency in
          deferred tax reserves                         1,007          4,339        1,617            3,508              8,207
        Amortization of goodwill                            -          6,267            -                -                  -
        Prior year tax adjustment                           -            773            -                -            (2,028)
        Millstone 3 sale                                    -          1,787            -                -                  -
        All other differences                           (880)          (882)           56            (241)            (1,422)
------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
Total income taxes                                   $ 49,287        $44,894      $ 9,637          $13,100            $39,618
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------

The Company  adopted SFAS No. 109,  “Accounting  for Income Taxes”,  which requires  recognition of deferred income taxes for
temporary  differences  that are reported in different  years for financial  reporting  and tax purposes  using the liability
method.  Under the liability  method,  deferred tax  liabilities  or assets are computed  using the tax rates that will be in
effect  when  temporary  differences  reverse.  Generally,  for  regulated  companies,  the  change  in tax  rates may not be
immediately recognized in operating results because of rate-making treatment and provisions in the Tax Reform Act of 1986.




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

====================================================================== ========================= ============================
At March 31 (In millions)                                                               2002                         2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Deferred tax asset:
        Plant related                                                                   $ 67                          $67
        Investment tax credits                                                             3                            4
        All other                                                                         37                           30
------- -------------------------------------------------------------- ------------------------- ----------------------------
------- -------------------------------------------------------------- ------------------------- ----------------------------
                                                                                         107                          101
------- -------------------------------------------------------------- ------------------------- ----------------------------
---------------------------------------------------------------------- ------------------------- ----------------------------
Deferred tax liability:
        Plant related                                                                  (211)                        (211)
        All other, principally regulatory assets                                       (153)                        (162)
------- -------------------------------------------------------------- ------------------------- ----------------------------
------- -------------------------------------------------------------- ------------------------- ----------------------------
                                                                                       (364)                        (373)
------- -------------------------------------------------------------- ------------------------- ----------------------------
------- ------ ------------------------------------------------------- ------------------------- ----------------------------
               Net deferred tax liability                                            $ (257)                       $(272)
------- ------ ------------------------------------------------------- ------------------------- ----------------------------

There were no valuation allowances for deferred tax assets deemed necessary at March 31, 2002 and 2001, respectively.

Note H - Short-term Borrowings

At March 31, 2002, and 2001, the Company had no short-term debt  outstanding.  The Company has regulatory  approval to issue
up to $375 million of short-term debt. National Grid USA and certain  subsidiaries,  including the Company,  with regulatory
approval,  operate a money pool to more  effectively  utilize cash  resources and to reduce outside  short-term  borrowings.
Short-term  borrowing  needs are met first by  available  funds of the money  pool  participants.  Borrowing  companies  pay
interest at a rate designed to  approximate  the cost of outside  short-term  borrowings.  Companies that invest in the pool
share the interest  earned on a basis  proportionate  to their average  monthly  investment in the money pool.  Funds may be
withdrawn from or repaid to the pool at any time without prior notice.

At March 31, 2002 and 2001,  the Company had lines of credit and standby bond purchase  facilities  with banks totaling $456
million which are available to provide  liquidity  support for $410 million of the Company’s  long-term  bonds in tax-exempt
commercial paper mode, and for other corporate  purposes.  There were no borrowings under these lines of credit at March 31,
2002. Fees are paid on the lines and facilities in lieu of compensating balances.




Note I - Cumulative Preferred Stock

A summary of  cumulative  preferred  stock at March 31, 2002 and 2001,  is as follows (in  thousands  of dollars  except for
share data):

-------------------------- ---------------------------- ---------------------------------- ---------------------------- ----------
                              Shares Outstanding                    Amount                    Dividends Declared        Call
                                                                                                                        Price
-------------------------- ---------------------------- ---------------------------------- ---------------------------- ----------
-------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
                                2002           2001              2002             2001           2002          2001
-------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
-------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
  $100 par value 6.00%        14,361         14,361            $1,436           $1,436            $86           $91        (a)
                Series

(a) Noncallable.

The annual dividend requirement for cumulative preferred stock was approximately $86,000 for 2002 and 2001.

There are no mandatory redemption provisions on the Company’s cumulative preferred stock.
Note J - Long-term Debt

A summary of long-term debt is as follows:

At March 31 (In thousands)
======================== ====================== ================================= ====================== ====================
Series                   Rate %                 Maturity                                        2002                 2001
======================== ====================== ================================= ====================== ====================
================================================================================= ====================== ====================
Pollution Control Revenue Bonds:
CDA (a)                  Variable               October 15, 2015                            $ 38,500             $ 38,500
MIFA 1 (b)               Variable               March 1, 2018                                 79,250               79,250
BFA 1 (c)                Variable               November 1, 2020                             135,850              135,850
BFA 2 (c)                Variable               November 1, 2020                              50,600               50,600
MIFA 2 (b)               Variable               October 1, 2022                              106,150              106,150
Unamortized discounts                                                                           (65)                 (71)
----------------------------------------------- --------------------------------- ---------------------- --------------------
----------------------------------------------- --------------------------------- ---------------------- --------------------
Total long-term debt                                                                        $410,285             $410,279
----------------------------------------------- --------------------------------- ---------------------- --------------------

(a)    CDA = Connecticut Development Authority
(b)    MIFA = Massachusetts Industrial Finance Authority
(c)    BFA = Business Finance Authority of the State of New Hampshire

At March 31, 2002, interest rates on the Company's variable rate long-term bonds ranged from 1.15 percent to 1.75 percent.

At March 31, 2002, the Company's long-term debt had a carrying value and fair value of approximately  $410,000,000.  The fair
value of debt that reprices frequently at market rates approximates carrying value.




Note K - Supplementary Income Statement Information

Advertising  expenses,  expenditures  for research and  development,  and rents were not material and there were no royalties
paid in the years ended March 31, 2002 or 2001,  the three  months ended March 31, 2000 or 1999,  or the year ended  December
31, 1999. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:

================================================ ============================ ============================= ==================
                                                         Year Ended           Three Months Ended March 31,     Year Ended
                                                          March 31,                                           December 31,
                                                         2002           2001         2000             1999        1999
(In thousands)                                                                                 (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Municipal property taxes                             $ 16,045        $19,334       $4,718           $4,618            $17,640
Federal and state payroll and other taxes               2,138          3,009          843            1,016              2,642
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
                                                     $ 18,183        $22,343       $5,561           $5,634            $20,282
------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------

Transactions  between the Company and other  affiliated  companies for sales of electric  energy and other sales  amounted to
approximately $354,396,000,  $385,982,000,  $90,934,000,  $120,700,000,  and $338,295,000, for the year ended March 31, 2002,
the year ended March 31, 2001,  the three months  ended March 31, 2000,  the three months ended March 31, 1999,  and the year
ended December 31, 1999, respectively.

National Grid USA Service Company,  Inc., an affiliated  service company  operating  pursuant to the provisions of Section 13
of the 1935 Act,  furnished  services  to the Company at the cost of such  services.  These  costs  amounted to  $43,487,000,
$43,271,000,   $11,514,000,   $10,088,000,  and  $43,584,000,   including  capitalized  construction  costs  of  $15,178,000,
$19,117,000,  $4,597,000,  $3,415,000, and $17,229,000,  in the year ended March 31, 2002, the year ended March 31, 2001, the
three  months  ended  March 31,  2000,  the three  months  ended  March 31,  1999,  and the year  ended  December  31,  1999,
respectively.

Selected Quarterly Financial Information (Unaudited)
========================================== ===================== ===================== ===================== =====================
(In thousands)                               Quarter Ended         Quarter Ended         Quarter Ended         Quarter Ended
                                             June 30, 2001        Sept. 30, 2001         Dec. 31, 2001        March 31, 2002
========================================== ===================== ===================== ===================== =====================
========================================== ===================== ===================== ===================== =====================
Operating revenue                                   $145,016              $147,151              $136,065              $132,186
Operating income                                     $22,834               $25,062               $20,221               $18,237
Net income                                           $20,371               $22,573               $17,852               $15,978

========================================== ===================== ===================== ===================== =====================
                                             Quarter Ended         Quarter Ended         Quarter Ended         Quarter Ended
(In thousands)                               June 30, 2000        Sept. 30, 2000         Dec. 31, 2000        March 31, 2001
========================================== ===================== ===================== ===================== =====================
========================================== ===================== ===================== ===================== =====================
Operating revenue                                   $156,190              $175,390              $156,396              $168,296
Operating income                                     $15,908               $25,232               $22,040               $24,535
Net income                                           $14,223               $16,460               $14,780               $12,837

Per share data is not relevant  because the  Company's  common  stock is wholly  owned by National  Grid USA, a wholly owned
subsidiary of National Grid Group plc.


New England Power Company

Selected Financial Information
============================================== ======================== ========================== =================================
                                                     Year Ended         Three Months Ended March
                                                      March 31,                    31,                 Year Ended December 31,
                                                      2002        2001       2000            1999        1999       1998    1997
(In millions)                                                                         (unaudited)
============================================== ============ =========== ========== =============== =========== ========== ==========
============================================== ============ =========== ========== =============== =========== ========== ==========
Operating revenue                                    $ 560       $ 656      $ 135           $ 167       $ 596     $1,218     $1,678
Net income                                            $ 77        $ 58       $ 14            $ 20        $ 71      $ 123       $145
Total assets                                        $2,740      $2,889     $2,630          $2,282      $2,303     $2,415     $2,763
Capitalization:
       Common equity                                 $ 941       $ 865      $ 657           $ 523       $ 332      $ 521       $913
       Cumulative preferred stock                        2           1          1               1           2          1         40
       Long-term debt                                  410         410        372             372         372        372        648
------ --------------------------------------- ------------ ----------- ---------- --------------- ----------- ---------- ----------
------ -- ------------------------------------ ------------ ----------- ---------- --------------- ----------- ---------- ----------
          Total capitalization                      $1,353      $1,276     $1,030           $ 896       $ 706      $ 894     $1,601
Preferred dividends declared                          $  -        $  -       $  -            $  -        $  -       $  1       $  2
Common dividends declared                             $  -        $  -       $ 24            $  -       $ 241      $ 131       $135
---------------------------------------------- ------------ ----------- ---------- --------------- ----------- ---------- ----------