SECURITIES AND EXCHANGE COMMISSION
	Washington, D.C.   20549

	FORM 10-Q

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

	For the quarterly period ended September 30, 2001

	OR

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

	Commission File Number 1-6564


	  NEW ENGLAND POWER COMPANY

	(Exact name of registrant as specified in charter)


MASSACHUSETTS	04-1663070
(State or other	(I.R.S. Employer
jurisdiction of	Identification No.)
incorporation or
organization)

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

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.

	Yes (X)      No ( )

Common stock, par value $20 per share, authorized and outstanding:  3,619,896
shares at September 30, 2001.


PART I FINANCIAL INFORMATION
Item 1. Financial Statements
- --------------------------------------

NEW ENGLAND POWER COMPANY
Statements of Income
Periods Ended September 30
(In thousands)
(Unaudited)

		Quarter				Six Months
		----------				--------------
	2001		2000		2001		2000
	-------		-------		-------		-------

							
Operating revenue, principally from affiliates	$147,151	$175,390	$ 292,167	$331,580
				------------	------------	------------	------------

Operating expenses:
	Fuel for generation	1,699	4,296	2,755	7,882
	Purchased electric energy:
		 Contract termination and nuclear
		  unit shutdown charges	56,584	55,812	115,039	111,520
	  Other		19,476	22,224	40,770	41,636
	Other operation	12,764	17,856	26,599	32,506
	Maintenance	5,691	5,862	9,608	10,686
	Depreciation and amortization	7,637	22,480	15,363	43,247
 	Taxes, other than income taxes	4,637	5,894	9,377	11,697
	Income taxes	13,601	15,734	24,760	26,929
				------------	------------	------------	------------
			Total operating expenses	122,089	150,158	244,271	286,103
				------------	------------	------------	------------
Operating income	25,062	25,232	47,896	45,477

Other income and (expense):
	Allowance for equity funds used
	 during construction	120	-	755	(2)
	Equity in income of nuclear power companies	836	1,949	1,765	2,817
	Amortization of goodwill (Note F)	-	(4,446)	-	(8,783)
	Other income (expense), net	656	(124)	718	2,224
				------------	------------	------------	------------
			Operating and other income	26,674	22,611	51,134	41,733
				------------	------------	------------	------------

Interest:
	Interest on long-term debt	3,164	4,456	6,999	8,442
	Other interest	956	1,899	1,321	3,140
	Allowance for borrowed funds used during construction 	(19)	(204)	(130)	(532)
				------------	------------	------------	------------
			Total interest	4,101	6,151	8,190	11,050
				------------	------------	------------	------------

Net income (Note F)	$  22,573	$ 16,460	$  42,944	$  30,683
				=======	=======	=======	=======


Statements of Retained Earnings
(In thousands)


Retained earnings at beginning of period	$  80,459	$ 16,077	$  60,110	$    1,415
Net income	22,573	16,460	42,944	30,683
Dividends declared on cumulative preferred stock	(21)	(24)	(43)	(47)
Gain on redemption of preferred stock	-	17	-	17
Acquisition adjustment	-	-	-	462
				------------	------------	------------	------------
Retained earnings at end of period 	$103,011	$ 32,530	$103,011	$  32,530
				=======	=======	=======	=======

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

Per share data is not relevant because the Company's common stock is wholly
owned by National Grid USA.



NEW ENGLAND POWER COMPANY
Balance Sheets
(In thousands)
(Unaudited)
	September 30,	March
31,
		ASSETS		2001	2001
	------------	------
	------
			
Utility plant, at original cost	$   891,523	$  846,935
	Less accumulated provisions for depreciation and amortization	327,745	320,238
					---------------	---------------
					563,778	526,697
Construction work in progress	7,130	34,946
					---------------	---------------
				Net utility plant	570,908	561,643
					---------------	---------------
Goodwill, net of amortization  (Note F)	338,188	338,188

Investments:
	Nuclear power companies, at equity	43,182	46,474
	Decommissioning trust funds	17,496	16,331
	Nonutility property and other investments	14,032	14,374
					---------------	---------------
				Total investments	74,710	77,179
					---------------	---------------
Current assets:
	Cash and temporary cash investments (including $112,325
	  and $22,075 with affiliates)	122,479	22,360
	Accounts receivable:
		Affiliated companies	56,350	61,191
		Others	69,342	89,483
	Fuel, materials, and supplies, at average cost	6,535	6,289
	Prepaid and other current assets	1,943	2,051
	Regulatory assets-purchased power obligations and accrued Yankee
	  nuclear plant costs	159,880	158,578
					---------------	---------------
				Total current assets	416,529	339,952
					---------------	---------------
Regulatory assets	1,414,351	1,522,089
Deferred charges and other assets	51,129	50,170
					---------------	---------------
					$2,865,815	$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 	103,011	60,110
	Unrealized gain (loss) on securities, net	(219)	(145)
					---------------	---------------
				Total common equity	907,164	864,337
	Cumulative preferred stock, par value $100 per share	1,436	1,436
	Long-term debt 	410,282	410,279
					---------------	---------------
				Total capitalization	1,318,882	1,276,052
					---------------	---------------
Current liabilities:
	Accounts payable (including $21,582 and $25,287 to affiliates)	62,798	66,017
	Accrued liabilities:
		Taxes	67,634	39,451
		Interest	1,810	1,489
		Purchased power obligations and accrued Yankee nuclear plant costs	159,880	158,578
		Other accrued expenses	6,815	7,621
	Dividends payable	22	22
					---------------	---------------
				Total current liabilities	298,959	273,178
					---------------	---------------
Deferred federal and state income taxes	255,950	272,304
Unamortized investment tax credits	9,054	9,312
Accrued Yankee nuclear plant costs	160,621	172,340
Purchased power obligations	585,239	636,848
Other reserves and deferred credits	237,110	249,187
					---------------	---------------
					$2,865,815	$2,889,221
					=========	=========
The accompanying notes are an integral part of these financial statements.



NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Six Months Ended September 30
(In thousands)
 (Unaudited)

	2001		2000
	-------		-------
			
Operating Activities:
		Net income	$  42,944	$  30,683
		Adjustments to reconcile net income to net cash
			provided by operating activities:
		Depreciation and amortization (including amortization of above market
			purchased power contracts)	43,765	47,646
		Amortization of goodwill (Note F)	-	8,783
		Deferred income taxes and investment tax credits, net	(15,041)	(1,815)
		Allowance for funds used during construction	(885)	(530)
	Changes in assets and liabilities, net of effects of merger:
		Decrease (increase) in accounts receivable, net	(18)	(18,735)
			Decrease (increase) in fuel, materials, and supplies	(246)	602
			Decrease (increase) in regulatory assets	71,519	142,232
			Decrease (increase) in prepaid and other current assets	108	2,441
			Increase (decrease) in accounts payable	(3,219)	9,319
			Increase (decrease) in purchased power contract obligations	(50,345)	(96,633)
			Increase (decrease) in other current liabilities	27,698	(6,070)
			Increase (decrease) in other non-current liabilities	(23,758)	(16,328)
		Other, net	2,528	(29,740)
					------------	-------------
				Net cash provided by operating activities	$  95,050	$  71,855
					------------	-------------

Investing Activities:
		Plant expenditures, excluding allowance for
			funds used during construction	$(19,742)	$  (22,121)
		Proceeds from divestiture of generating assets	25,000	-
		Other investing activities	(146)	(6,594)
					------------	-------------
				Net cash provided by (used in) investing activities	$   5,112	$  (28,715)
					------------	-------------
Financing Activities:
		Dividends paid on common stock	$          -	$(256,463)
		Dividends paid on preferred stock	(43)	(47)
		Changes in short-term debt	-	125,000
		Long-term debt - retirements	-	(90,575)
		Redemption of preferred stock, net of discount	-	(79)
					------------	-------------
				Net cash used in financing activities	$       (43)	$(222,164)
					------------	-------------

Net increase (decrease) in cash and cash equivalents	$100,119	$(179,024)

Cash and cash equivalents at beginning of period	22,360	226,921
					------------	-------------
Cash and cash equivalents at end of period	$122,479	$   47,897
					=======	========

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


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

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

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

	The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
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.

	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 believes that hazardous
waste liabilities for all sites of which it is aware are not
material to its financial position.


Note B - Nuclear Units
- ----------------------

		The company has minority interests in four Yankee Nuclear Power
Companies (Yankees). 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. In addition,
the Company has a minority non-operating ownership interest in the
Seabrook 1 Nuclear generating unit. The Company's share of expenses
for Seabrook 1 is accounted for in "Operation and maintenance"
expense on the income statement.

		In view of potential terrorist activity following the events
of September 11, 2001, security at nuclear plants has been enhanced
in concert with Nuclear Regulatory Commission (NRC) advisory
notices. The Company is unable to determine at this time whether
additional security at the plants will result in material cost
increases.

Nuclear Units Permanently Shut Down

	Yankee Atomic, Connecticut Yankee, and Maine Yankee have
permanently ceased operations. Yankee Atomic has discontinued
further billings to the Company, subject to a final reconciliation
of costs once decommissioning at the plant has been completed. The
Company's remaining investment in Yankee Atomic will be repurchased
no later than June 2002. In the case of 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 Federal Energy Regulatory Commission (FERC) allows the
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.

	For information concerning disputes with Stone & Webster, Inc.
regarding a now terminated contract to decommission the Maine
Yankee unit, see Note D-2 in the Notes to Financial Statements in
the Company's 2001 Annual Report.

	On September 27, 2001, the Maine Yankee Board of Directors
approved an initial redemption of 75,200 shares (pro rata among the
owners) of its common stock at $132.84 per share, in lieu of
dividends, with a redemption date of September 30, 2001. On October
1, 2001, the Company received approximately $2.4 million for the
redemption of 18,048 shares.

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 customers through contract termination charges (CTC),
with shareholders being allocated the balance.

Vermont Yankee

	On August 15, 2001, Vermont Yankee announced that it had
reached an agreement to sell the Vermont Yankee nuclear power plant
to Entergy Corporation (Entergy) for $180 million. The Company has
a 22.5 percent ownership interest in Vermont Yankee. The Company's
portion of the sale price would be $40.5 million ($32.6 million for
the plant and related assets and $7.9 million for nuclear fuel).
The plant's decommissioning trust fund will be transferred to
Entergy and Entergy will assume decommissioning liability for the
plant. As part of the transaction, Vermont Yankee owners, including
the Company, will purchase power from the plant through 2012. Net
proceeds from the sale will 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 Public Utility Holding Company Act of 1935,
the FERC, the NRC, the Vermont Public Service Board (VPSB), and
other state regulatory commissions with jurisdiction over other
equity owners of Vermont Yankee. Vermont Yankee expects to close
the sale no later than June 2002.

	The announced sale to Entergy followed termination of an
earlier agreement for the sale of the plant to AmerGen Energy
Company following rejection of the earlier agreements by the VPSB.
For further background on the previous sale agreement, see the
"Vermont Yankee" section of Note D-2 in the Notes to Financial
Statements in the Company's 2001 Annual Report.

Seabrook 1

	In December 2000 and April 2001, respectively, Northeast
Utilities (NU) and the Company filed Seabrook divestiture plans
before the New Hampshire Public Utilities Commission (NHPUC). Under
the terms of the Public Service Company of New Hampshire
Restructuring Settlement and enabling legislation, the NHPUC, in
conjunction with the Connecticut Department of Public Utility
Control (CDPUC), will administer an auction of the plant. On
September 28, 2001, the NHPUC and CDPUC jointly announced that JP
Morgan had been retained as the exclusive financial advisor to
manage the sale. The Company expects that the purchaser of the
plant will be selected in the spring of 2002.

	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, is designed to protect customers from future
decommissioning risks. The legislation also enhances the potential
sale price of Seabrook by reducing the standard for non-
radiological decommissioning at the site, and by allowing the buyer
of the plant to retain any decommissioning funds in excess of those
contributed by customers of the present owners.

	The Company and the other Seabrook joint owners participated
in the New Hampshire Nuclear Decommissioning Finance Committee
(NHNDFC) proceeding implementing the new decommissioning
legislation. The NHNDFC is responsible for establishing the level
of annual contributions that the joint owners make to the Seabrook
decommissioning fund. Under the new legislation, the NHNDFC is
charged with assuring that the buyer of Seabrook will have adequate
funding to decommission the plant in the event of a premature
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 include 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.

Millstone 3

	In November 1999, the Company entered into an agreement with
NU and certain of NU's subsidiaries to settle claims made by the
Company relative to the operation of Millstone 3. Among other
things, the settlement provided for NU to include the Company's
share of Millstone 3 in an auction of NU's share of the unit. Upon
the closing of the sale, NU would pay the Company a fixed amount
regardless of the actual sale price.

	In August 2000, Dominion agreed to purchase the Millstone
units, including the Company's 16.2 percent interest in Millstone
3, for $1.3 billion. On March 31, 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. In addition, the Company paid approximately $5.8 million to
increase the decommissioning trust fund to the level prescribed in
its settlement agreement with NU.

	In November 2000, the Rhode Island Attorney General and the
Rhode Island Division of Public Utilities and Carriers filed a
protest at the FERC. The protest contended the payment the Company
received in March 2001 from the sale of Millstone 3, as established
by its agreement with NU, was insufficient. In January 2001, the
FERC found that Rhode Island's objection was beyond the scope of
the proceeding and approved the sale. The Company cannot predict
whether the Rhode Island regulators will reassert their claims in
connection with the recovery of stranded costs, or the financial
consequences if they do reassert their claims.


Note C - 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 CTC. Through September 2001, the
charges assessed Norwood amount to approximately $36 million, all
of which remain unpaid. The Company filed a collection action in
Massachusetts Superior Court (Superior Court). The Superior Court
deferred action until various other appeals were decided. (For a
full discussion of the events leading up to the Superior Court's
decision, see Note D-6, "Town of Norwood Dispute" in the Notes to
Financial Statements in the Company's 2001 Annual Report.) On March
14, 2001, the Superior Court ordered Norwood to pay the Company $27
million including interest. Norwood was ordered to pay the judgment
in monthly installments of $600,000. 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.

Note D - Standard Offer Service and ICAP Deficiency Charge
- ----------------------------------------------------------

	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 six months ended
September 30, 2001, the Company's gain from this obligation was
approximately $1 million. 	Effective December 1, 2001, a third party
will assume the responsibility for providing transitional standard
offer power service in Rhode Island and the Company's obligation
will terminate.

	As reported in the Company's 2001 Annual Report, there has
been litigation regarding a FERC order to increase the Installed
Capacity (ICAP) deficiency charge to $8.75 per kilowatt-month (kW-
month) instead of the rate proposed by the New England Independent
System Operator (ISO New England) of $0.17 per kW-month. For
background information on this issue, see Note C in the Notes to
Financial Statements in the Company's 2001 Annual Report.

Since the events previously reported, there has been further
regulatory activity related to the ICAP issue. In June 2001, 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. Numerous parties filed over the next month
supporting and protesting the ICAP Compliance Filing. (The Company
supported the ICAP Compliance Filing.) In July and August, various
parties appealed to the First Circuit Court of Appeals aspects of
earlier FERC ICAP orders favorable to the Company and other ICAP
purchasers. On August 28, 2001, the FERC issued an order accepting
ISO New England's June Compliance Filing, with some modifications,
and on September 28, 2001, issued two more orders favorable to ISO
New England's compromise ICAP regime. Motions for rehearing and
clarification of these orders (including a complaint in a separate
docket) were filed in September and October. On October 19, 2001,
one party filed a request that the FERC apply the new $4.87 per kW-
month ICAP deficiency charge retroactively to the period January
through June 2000, which could cause a significant retroactive
increase in ICAP deficiency payments by the Company and other ICAP
purchasers. The Company is unable at this time to determine whether
these proceedings will have a material impact on earnings.

Note E - Regulatory Asset Recovery
- ----------------------------------

	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
Statement of Financial Accounting Standards (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 Financial Accounting Standards Board (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 September 30, 2001, this amounted to
approximately $1.6 billion, including $1.1 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 F - New Accounting Standards
- ---------------------------------

	The Company adopted SFAS No. 142, "Accounting for Goodwill and
Other Intangible Assets" (FAS 142), effective April 1, 2001. FAS
142 requires that goodwill no longer be amortized and that it must
be reviewed for impairment within six months of adoption
("transitional goodwill impairment test"), and annually thereafter.

	The transitional goodwill impairment test compares the
goodwill carrying value to its fair value. If the carrying value
exceeds its fair value, goodwill is reduced to fair value by a
goodwill impairment adjustment that must be completed by the end of
the year of initial adoption.

	In accordance with FAS 142, the Company utilized a discounted
cash flow approach incorporating its most recent business plan
forecasts in the performance of the transitional test for goodwill
impairment. The result of this analysis 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 at March 31, 2001, and no adjustment was deemed
necessary effective with the adoption of FAS 142. The following
table presents pro forma information for the quarter ended and six
months ended September 30, 2000, to reflect the reversal of
goodwill amortization in accordance with FAS 142:



		September 30, 2000
		(In thousands)

			Quarter	         Six Months
		Ended		      Ended

		
	Net income, as reported	$16,460			$30,683
	Reversal of goodwill
	 amortization	4,446			  8,783
		-------			-------
	Restated net income	$20,906		$39,466
	=======	=======
	

	In June 1998, the 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 July 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 unable to determine the impact of this
statement on its financial position or results of operations.

Note G
- ------

	In the opinion of the Company, these financial statements
reflect all adjustments (which include normal recurring
adjustments) necessary for a fair statement of the results of its
operations for the periods presented and should be considered in
conjunction with the notes to the financial statements in the
Company's Annual Report for the period ended March 31, 2001.
Certain prior period amounts on the financial statements have been
reclassified to conform with the current presentation.


Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
- -----------------------------------------------------------------

	This section contains management's assessment of New England
Power Company's (the Company) financial condition and the principal
factors having an impact on the results of operations. This
discussion should be read in conjunction with the Company's
financial statements and footnotes and the Annual Report on Form
10-K for the period ended March 31, 2001.

	The Company is a wholly owned subsidiary of National Grid USA.

FERC Proceedings
- ----------------

On June 13, 2001, the Federal Energy Regulatory Commission
(FERC) issued a comprehensive order addressing several rehearing
requests and compliance filings that had resulted from an earlier
FERC order relating to New England Power Pool's (NEPOOL) proposed
congestion management and multi-settlement systems. In the June 13
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
Independent System Operator-New England (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 on July 13, 2001 that the Company
believes does not comport with the FERC's order. The Company has
filed a protest to the NEPOOL and ISO New England filing.

With respect to transmission facilities, the June 13 Order
reaffirmed the FERC's earlier order in which it held that
transmission owners (TOs) should not have a "decisional" role in
transmission planning; and that ISO New England is the sole entity
that should have decisional responsibility for planning. The FERC
also ordered that transmission projects that are in the regional
plan approved by ISO New England should be subject to competitive
request for proposals for construction. Any qualified party
(including individual TOs like the Company) would be eligible to
compete to build transmission projects in any utility's service
area. The FERC directed ISO New England to develop an allocation
methodology for the cost of transmission upgrades, or adopt the
default cost allocation methodology employed by the Pennsylvania-
New Jersey-Maryland Interconnection (PJM). The FERC also ruled that
a greater percentage of generator-related upgrade costs should be
rolled into the transmission tariff and paid by transmission load
customers, rather than being paid directly by the generator.

National Grid USA presented to the FERC in January 2001 a
joint proposal, with ISO New England and other utilities in New
England, for a regional transmission organization (RTO) in New
England. The RTO would consist of an ISO with responsibility for
administering a competitive wholesale market in electricity and an
Independent Transmission Company offering transmission services and
undertaking transmission network development and the provision of
connections for new generation. The proposal was designed to
respond to the FERC's objective set out in "Order 2000" of
separating transmission operations from market participation, and
would give the Independent Transmission Company, of which National
Grid USA would be a member, the opportunity to propose financial
incentives to deliver greater value for customers and shareholders.

	On July 11 and 12, 2001, the FERC issued a series of orders
relating to RTO proceedings around the country, including New
England. The FERC denied the joint proposal made by National Grid
USA, ISO New England, and the other participating New England TOs
in January, finding that the proposed scope of the RTO was too
small. The FERC ordered National Grid USA and the other New England
parties to join a 45-day FERC-led mediation process commencing in
July, and involving participants of the proposed New York, PJM, and
PJM-West RTOs. The purpose of the mediation is to develop a
proposal for a "Northeast" RTO to cover a larger region than
offered by the proposals that had been submitted. Although it
rejected the proposed New England RTO, the FERC nevertheless
supported the concept that a transmission company that is
independent of market participants may have an active role in
transmission planning, and may qualify to earn incentive rates for
transmission.

	On September 17, 2001, the FERC administrative law judge
presiding over the mediation issued a report outlining a business
plan and schedule of milestones for the parties to discuss how the
RTO should be structured and should operate. On November 7, 2001,
the FERC issued general guidelines concerning RTO market design,
and the FERC may act on specific RTO proposals as early as December
2001.

Earnings
- --------

		Net income for the quarter and six months ended September 30,
2001 increased approximately $6 million and $12 million,
respectively, compared with the same periods in 2000. 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 F.) 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 refinancing of short-term debt.

Operating Revenue
- -----------------

		Operating revenue for the quarter and six months ended
September 30, 2001 decreased approximately $28 million and $39
million, respectively, compared with the same periods in 2000. The
decrease in revenue is primarily attributable to reduced
kilowatthour (kWh) sales as a result of the sale of the Company's
interest in the Millstone 3 nuclear generating facility (Millstone
3) in March 2001 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 contract
termination charge (CTC) revenue due to fully reconciling true-up
mechanisms that allow the Company to adjust revenues
proportionately with correlating expenses.

		Partially offsetting these decreases are increased kWh sales
related to obligations to new customer load in Rhode Island, and
increased transmission revenues. The transmission charge is a
formula rate that recovers the Company's actual costs plus a return
on actual investment.



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

		Operating expenses for the quarter and six months ended
September 30, 2001 decreased approximately $28 million and $42
million, respectively, compared with the same periods in 2000.

		Fuel for generation expense for the quarter and six months
ended September 30, 2001 decreased approximately $3 million and $5
million, respectively, primarily due to the sale of Millstone 3.

	Purchased power expense increased approximately $3 million for
the six months ended September 30, 2001 compared with the same
period in 2000, despite a $2 million decrease in expense for the
quarter then ended as compared to the prior year. The increase for
the year to date period is attributed to the costs of a refueling
outage at Vermont Yankee during the quarter ended June 30, 2001 and
the inclusion of Montaup Electric Company's (Montaup) purchased
power costs effective May 1, 2000. Also contributing is the
increased cost of purchased power to supply standard offer
customers in Rhode Island for the six month period, offset by a
decrease in purchased power expense for the quarter due to lower
fuel prices. 	Effective December 1, 2001, a third party will assume
the responsibility for providing transitional standard offer power
service in Rhode Island and the Company's obligation will
terminate. All these costs are partially offset by decreased
charges from the three Yankee nuclear units which have been
permanently shut down.

		Nuclear operation and maintenance expenses for the quarter and
six months ended September 30, 2001 decreased approximately $5
million and $9 million, respectively, as a result of the sale of
Millstone 3. Other operating expenses for the six months ended
September 30, 2001 increased approximately $2 million compared with
the same period in 2000, primarily due to increased pension and
postretirement healthcare expenses.

		Depreciation and amortization expenses for the quarter and six
months ended September 30, 2001 decreased approximately $15 million
and $28 million, respectively, compared with the same periods in
2000. 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.

Other Income and Expense-net
- ----------------------------

		Other income and expense-net for the quarter and six months
ended September 30, 2001 increased approximately $4 million and $7
million, respectively, compared with the same periods in 2000. The
increase is due primarily to the cessation of goodwill amortization
as a result of the adoption of FAS 142.

Interest Expense
- ----------------

		Interest expense for the quarter and six months ended
September 30, 2001 decreased approximately $2 million and $3
million, respectively, compared with the same periods in 2000
primarily due to decreased interest rates on the Company's variable
rate long-term debt and the refinancing of short-term debt.

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

	Cash expenditures for utility plant totaled approximately $12
million and $20 million for the quarter and six months ended
September 30, 2001, respectively, and were primarily transmission-
related. The funds necessary for utility plant expenditures during
the period were primarily provided by internally generated funds.

	At September 30, 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, 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 September 30, 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 September 30, 2001. Fees are paid on
the lines and facilities in lieu of compensating balances.

Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -----------------------------------------------------------------

	New England Power Company's (the Company) major financial
market risk exposure is changing interest rates. Changing interest
rates will affect interest paid on variable rate debt. At September
30, 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 six
months ended September 30, 2001, was approximately 3.05 percent.

	For a full discussion of the Company's risk associated with
standard offer service and the Installed Capacity deficiency
charge, refer to Note D in the Notes to Unaudited Financial
Statements.

PART II. OTHER INFORMATION

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

Information concerning several Federal Energy Regulatory
Commission proceedings, discussed in this report in the FERC
Proceedings section of Management's Discussion and Analysis of
Financial Condition and Results of Operations (Part I, Item II)
and in Note D of Notes to Unaudited Financial Statements, is
incorporated herein and made a part hereof.

As previously reported, the Company had reached a
settlement in principal on March 31, 2001, with NSTAR, formerly
known as Boston Edison Company (BECO), resolving issues
surrounding a $3 million refund to Montaup ordered by the FERC in
January 2000.  The refund related to Montaup's purchased power
agreement with BECO for 11 percent of the output from the Pilgrim
plant.  BECO appealed the FERC order to the First Circuit Court
of Appeals which, in turn, remanded it to FERC for further
proceedings.  All conditions to the settlement have been met.
Under the terms of the settlement agreement, the Company returned
to BECO 75 percent of the refund amount, plus interest through
March 31, 2001.  The refunded amount will be recovered by the
Company from customers through the contract termination charge.


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

The Company filed a report on Form 8-K dated August 15, 2001
containing Items 5 and 7.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report on Form 10-Q
for the quarter ended September 30, 2001 to be signed on its
behalf by the undersigned thereunto duly authorized.

NEW ENGLAND POWER COMPANY


						S/John G. Cochrane

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

Date: November 13, 2001



NEW ENGLAND POWER COMPANY
Notes To Unaudited Financial Statements


18

NEW ENGLAND POWER COMPANY

NEW ENGLAND POWER COMPANY

NEW ENGLAND POWER COMPANY