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 June 30, 2001

	OR

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

	Commission File Number 1-6564


	(LOGO)  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 June 30, 2001.



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

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

					Three Months
					-------------------
				2001		2000
				-------		-------
						

Operating revenue, principally from affiliates		$145,016	$156,190
					------------	------------

Operating expenses:
	Fuel for generation		1,056	3,586
	Purchased electric energy:
	  Contract termination and nuclear unit shutdown charges		58,455	59,604
	  Other			21,294	15,516
	Other operation		13,835	14,650
	Maintenance		3,917	4,824
	Depreciation and amortization		7,726	20,767
 	Taxes, other than income taxes		4,740	5,803
	Income taxes		11,159	11,195
					------------	------------
			Total operating expenses		122,182	135,945
					------------	------------
Operating income		22,834	20,245

Other income:
	Allowance for equity funds used during construction		635	(2)
	Equity in income of nuclear power companies		929	868
	Amortization of goodwill (Note F)		-	(4,337)
	Other income (expense), net		62	2,348
					------------	------------
			Operating and other income		24,460	19,122
					------------	------------

Interest:
	Interest on long-term debt		3,835	3,986
	Other interest		365	1,241
	Allowance for borrowed funds used during construction		(111)	(328)
					------------	------------
			Total interest		4,089	4,899
					------------	------------

Net income (Note F)		$ 20,371	$ 14,223
					=======	=======


Statements of Retained Earnings
(In thousands)


Retained earnings at beginning of period		$ 60,110	$    1,415
Net income		20,371	14,223
Dividends declared on cumulative preferred stock		(22)	(23)
Acquisition adjustment		-	462
					------------	-------------
Retained earnings at end of period (Note F)		$ 80,459	$  16,077
					=======	=======

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)
	June 30,	March 31,
		ASSETS		2001	2001
	-----------	------	------
			

Utility plant, at original cost	$  884,365	$  846,935
	Less accumulated provisions for depreciation and amortization	324,123	320,238
					--------------	---------------
					560,242	526,697
Construction work in progress	4,943	34,946
					--------------	---------------
				Net utility plant	565,185	561,643
					--------------	---------------
Goodwill, net of amortization (Note F)	338,188	338,188

Investments:
	Nuclear power companies, at equity	45,722	46,474
	Decommissioning trust funds	16,872	16,331
	Nonutility property and other investments	14,472	14,374
					--------------	---------------
				Total investments	77,066	77,179
					--------------	---------------
Current assets:
	Cash and temporary cash investments (including $92,850
	  and $22,075 with affiliates)	92,922	22,360
	Accounts receivable:
		Affiliated companies	65,824	61,191
		Others	56,693	89,483
	Fuel, materials, and supplies, at average cost	6,766	6,289
	Prepaid and other current assets	1,120	2,051
	Regulatory assets-purchased power obligations and accrued Yankee
		nuclear plant costs	159,229	158,578
					--------------	---------------
				Total current assets	382,554	339,952
					--------------	---------------
Regulatory assets	1,455,830	1,522,089
Deferred charges and other assets	50,480	50,170
					--------------	---------------
					$2,869,303	$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 	80,459	60,110
	Unrealized gain (loss) on securities, net	(87)	(145)
					--------------	---------------
				Total common equity	884,744	864,337
	Cumulative preferred stock, par value $100 per share	1,436	1,436
	Long-term debt 	410,281	410,279
					--------------	---------------
				Total capitalization	1,296,461	1,276,052
					--------------	---------------
Current liabilities:
	Accounts payable (including $23,690 and $25,287 to affiliates)	61,723	66,017
	Accrued liabilities:
		Taxes	54,814	39,451
		Interest	2,793	1,489
		Purchased power obligations and accrued Yankee nuclear plant costs	159,229	158,578
		Other accrued expenses	8,067	7,621
	Dividends payable	22	22
					--------------	---------------
				Total current liabilities	286,648	273,178
					--------------	---------------
Deferred federal and state income taxes	264,921	272,304
Unamortized investment tax credits	9,183	9,312
Accrued Yankee nuclear plant costs	165,564	172,340
Purchased power obligations	598,470	636,848
Other reserves and deferred credits	248,056	249,187
					--------------	---------------
					$2,869,303	$2,889,221
					========	========
The accompanying notes are an integral part of these financial statements.





NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Quarters Ended June 30
(In thousands)
(Unaudited)

	2001		2000
	-------		-------
		(In thousands)
					
Operating activities:
		Net income	$  20,371	$  14,223
		Adjustments to reconcile net income to net cash
			provided by operating activities:
		Depreciation and amortization	21,844	32,335
		Amortization of goodwill	-	4,337
		Deferred income taxes and investment tax credits, net	(6,602)	11,224
		Allowance for funds used during construction	(746)	(326)
		Changes in assets and liabilities, net of effects of acquisition:
				Decrease (increase) in accounts receivable, net	3,157	(2,378)
				Decrease (increase) in fuel, materials, and supplies	(477)	(26)
				Decrease (increase) in regulatory assets	47,963	35,382
				Decrease (increase) in prepaid and other current assets	931	(25,743)
				Increase (decrease) in accounts payable	(4,294)	864
				Increase (decrease) in purchased power contract obligations	(37,746)	(68,794)
				Increase (decrease) in other current liabilities	17,113	(4,400)
				Increase (decrease) in other non-current liabilities	(7,888)	(13,852)
				Other, net	464	250
						-------------	-------------
					Net cash provided by (used in) operating activities	$   54,090	$  (16,904)
						-------------	-------------

Investing activities:
		Plant expenditures, excluding allowance
			for funds used during construction	$   (8,460)	$  (11,951)
		Proceeds from divestiture of generating assets	25,000	-
		Other investing activities	(46)	(2,462)
						-------------	-------------
					Net cash provided by (used in) investing activities	$   16,494	$  (14,413)
						-------------	-------------

Financing activities:
		Dividends paid on common stock	$            -	$(256,463)
		Dividends paid on preferred stock	(22)	(23)
		Changes in short-term debt	-	158,050
		Long-term debt - retirements	-	(90,575)
						-------------	-------------
					Net cash provided by (used in) financing activities	$        (22)	$(189,011)
						-------------	-------------

Net increase (decrease) in cash and cash equivalents	$   70,562	$(220,328)

Cash and cash equivalents at beginning of period	22,360	226,921
						-------------	-------------
Cash and cash equivalents at end of period	$   92,922	$     6,593
						========	========

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
- ----------------------

Yankee Nuclear Power Companies

			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.

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 in the Notes to Financial Statements in the
Company's 2001 Annual Report.

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 operating costs related to the units will be allocated to
customers through contract termination charges (CTC), with
shareholders being allocated the balance.


Vermont Yankee

	In November 1999, the Vermont Yankee Nuclear Power Corporation
entered into an agreement with AmerGen Energy Company (AmerGen), a
joint venture between PECO Energy and British Energy, to sell the
assets of Vermont Yankee. Several other parties, including Entergy
Corporation (Entergy), indicated to the Vermont Public Service
Board (VPSB) that they were prepared to make an offer for Vermont
Yankee.

	On February 14, 2001, the VPSB rejected Vermont Yankee's sale
agreement with AmerGen and formally terminated the AmerGen
proceeding on March 15, 2001. The VPSB also required Entergy to
post a $26 million bond payable in the event that Entergy withdraws
its offer. In addition, the VPSB stated that if the Entergy bond
were redeemed, the proceeds would go exclusively to Vermont
customers. The Vermont Yankee Board of Directors is presently
considering its options with respect to that part of the order.

	On March 15, 2001, Vermont Yankee terminated its agreement
with AmerGen. After considering its options, Vermont Yankee decided
to proceed with a formal auction of the plant. The auction was
officially launched on April 16, 2001. The Company expects the
winning bidder of the plant will be named shortly. Any 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 Nuclear Regulatory
Commission, the VPSB, and other state regulatory commissions with
jurisdiction over other equity owners of Vermont Yankee.

	For further background on the previous sale agreement, see the
"Vermont Yankee" section of Note D 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 Utilities,
will administer an auction of the plant with the assistance of an
asset sale specialist. The NHPUC is currently interviewing
potential asset sale specialist candidates and is expected to
select an asset sale specialist by the end of August.

	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, seeks 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 utility 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 July 9, 2001, a settlement was filed with the NHNDFC
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. The NHNDFC conducted hearings regarding the
settlement and is expected to issue a draft decision in late
August. A final decision is expected in early September.

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 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. The amounts received pursuant to
the sale will, after reimbursement of the Company's transaction
costs and net investment in Millstone 3, be credited to customers.

	In November 2000, the Rhode Island Attorney General and the
Rhode Island Division of Public Utilities and Carriers filed a
protest at the FERC contending that the payment the Company would
receive 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 June 2001, the charges
assessed Norwood amount to approximately $32 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 has also entered 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 remains obligated to provide
transition power supply service to new customer load in Rhode
Island at the standard offer price, but does not have a regulatory
agreement that necessarily allows full recovery of the costs of
such standard offer power. Consequently, the Company is at risk for
the difference between the actual cost of serving this load and the
revenue received from this obligation. The standard offer rate is
currently 3.8 cents per kilowatthour (kWh). The standard offer rate
is also subject to a rolling twelve-month fuel index adjustment
factor, which increased the rate by an additional 2.563 cents per
kWh beginning in June 2001. The Company meets this obligation
through a combination of generation from some of its remaining
generation sources, as well as by periodically procuring power at
market prices. Over time, the Company cannot predict whether the
resulting revenues will be sufficient to cover the costs of
procuring such power.

	For information regarding pending appeals and remands of a
FERC order to increase the Installed Capacity (ICAP) deficiency
charge which could affect the Company's future power supply costs,
see Note C in the Notes to Financial Statements in the Company's
2001 Annual Report.

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 June 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 the cessation of goodwill amortization and that
goodwill be reviewed for impairment annually, or on an interim
basis if events or changes in circumstances indicate the fair value
of the Company is below its carrying value.

	The Company will conduct a "transitional goodwill impairment
test" in conjunction with the adoption of FAS 142 no later than the
end of the second quarter of fiscal 2002. The Company will also
perform an annual goodwill impairment test by March 31, 2002. The
Company does not expect the impairment tests to require adjustments
that will have a material impact on its financial position or
results of operations.

	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 June 30, 2000 to reflect the reversal of goodwill
amortization in accordance with FAS 142:


		Quarter Ended
		June 30, 2000
	(In thousands)
	
	Net income, as reported	$	14,223
	Reversal of goodwill amortization		4,337
			-------
	Restated net income	$	18,560
	=======
	

	In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (FAS 133). In June
2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" (FAS 138).
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.

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. 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, 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 the 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.

Earnings
- --------

		Net income for the quarter ended June 30, 2001 increased
approximately $6 million compared with the same period 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.)
Earnings were also affected by increased income due to the May 1,
2000 merger with Montaup Electric Company (Montaup), and decreased
interest expense, partially offset by a reduction in other income.



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

		Operating revenue for the quarter ended June 30, 2001
decreased approximately $11 million compared with the same period
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
during the quarter ended June 30, 2001 at the Vermont Yankee
nuclear power plant (Vermont Yankee). 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 ended June 30, 2001
decreased approximately $14 million compared with the same period
in 2000.

		Fuel for generation decreased approximately $3 million
primarily due to the sale of Millstone 3.

		Purchased power expense increased approximately $5 million
compared with the same period in 2000. The increase is largely
attributed to the costs of a refueling outage at Vermont Yankee.
Also contributing to the increase are costs of standard offer
purchases related to obligations to supply new customer load in
Rhode Island, and the inclusion of Montaup's purchased power costs
effective May 1, 2000. These costs are partially offset by
decreased charges from the Yankee Atomic nuclear power plant due to
the completion of the purchased power contract and final billing in
June 2000.

		Nuclear operation and maintenance expenses decreased
approximately $4 million as a result of the sale of Millstone 3.
Other operating expenses 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 ended
June 30, 2001 decreased approximately $13 million compared with the
same period 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 costs associated with its generating plants and
regulatory assets (excluding Montaup's) at the end of 2000.

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

		Other income and expense-net for the quarter ended June 30,
2001 increased approximately $3 million compared with the same
period in 2000. The increase reflects the cessation of goodwill
amortization as a result of the adoption of FAS 142, increased
allowance for equity funds used during construction, and decreased
interest income from other investing activities.

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

		Interest expense decreased approximately $1 million for the
quarter ended June 30, 2001 compared with the same period in 2000
primarily due to reduced short-term borrowings.

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

	Cash expenditures for the Company for utility plant totaled
approximately $8 million for the quarter ended June 30, 2001 and
were primarily transmission-related. The funds necessary for
utility plant expenditures during the period were primarily
provided by internally generated funds.

	At June 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, 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 June 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 June 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 June 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 three
months ended June 30, 2001, was approximately 3.32 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),
is incorporated herein and made a part hereof.


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

On April 18, 2001, the Annual Meeting of Shareholders was
held.

By unanimous vote of the 3,619,896 shares present of
3,634,257 total shares having general voting rights:

The number of directors for the ensuing year was fixed at
eight.



The following were elected as directors:

L. Joseph Callan
Peter G. Flynn
Michael E. Jesanis
Robert G. Powderly
Lawrence J. Reilly
Terry L. Schwennesen
Richard P. Sergel
Philip R. Sharp

John G. Cochrane was elected as Treasurer and Gregory A.
Hale was elected as Clerk.

PricewaterhouseCoopers was selected as Auditor for the year
2001.

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

None.


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 June 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:  August 13, 2001


NEW ENGLAND POWER COMPANY
Notes to Unaudited Financial Statements




21

NEW ENGLAND POWER COMPANY


NEW ENGLAND POWER COMPANY