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, 2003

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

For the transition period from __________ to __________

Commission	Registrant, State of Incorporation	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.

2-26651	New England Power Company	04-1663070
	(a Massachusetts corporation)
	25 Research Drive
	Westborough, Massachusetts 01582
	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 [ ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [ X ]

The number of shares outstanding of each of the issuer’s classes of common stock, as of August 1, 2003, were as follows:

Registrant	Title	Shares Outstanding

New England Power Company	Common Stock, $20.00 par value	3,619,896
	(all held by National Grid
	USA)

NEW ENGLAND POWER COMPANY

FORM 10-Q - For the Quarter Ended June 30, 2003




PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

		Statements of Operations and Retained Earnings and Comprehensive Income

		Balance Sheets

		Statements of Cash Flows

		Notes to Unaudited Financial Statements


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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Item 4.	Controls and Procedures

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings

Item 4	Submission of Matters to a vote of Security Holders

Item 6.	Exhibits and Reports on Form 8-K

Signature

Exhibit Index

PART I FINANCIAL INFORMATION
Item 1. Financial Statements

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

	Three Months
(In thousands)	2003	2002
Operating revenue, principally from affiliates	$114,445	$143,488
Operating expenses:
Fuel for generation	490	382
Purchased electric energy:
Contract termination and nuclear unit shutdown charges	35,589	43,679
Other	2,224	16,474
Other operation	12,426	14,823
Maintenance	2,244	7,372
Depreciation and amortization
Purchased power and nuclear fuel amortization	16,633	13,854
Other	9,297	7,640
Taxes, other than income taxes	4,438	4,821
Income taxes	12,169	12,552
Total operating expenses	95,510	121,597
Operating income	18,935	21,891
Other income:
Equity in income of nuclear power companies	498	689
Other income, net	1,080	7
Operating and other income	20,513	22,587
Interest:
Interest on long-term debt	1,616	1,942
Other interest	188	247
Total interest	1,804	2,189
Net income	$ 18,709	$ 20,398

Statements of Retained Earnings
(In thousands)
(Unaudited)

Retained earnings at beginning of period	$214,154	$136,798
Net income	18,709	20,398
Dividends declared on cumulative preferred stock	(20)	(22)
Retained earnings at end of period	$232,843	$157,174

Statements of Comprehensive Income
(In thousands)
(Unaudited)

Net Income	$ 18,709	$ 20,398
Unrealized gain (loss) on securities, net of tax	165	(117)
Comprehensive income	$ 18,874	$ 20,281

Per share data is not relevant because the Company’s common stock is wholly owned by National Grid USA.
The accompanying notes are an integral part of these financial statements.

NEW ENGLAND POWER COMPANY
Balance Sheets

(In thousands)			(Unaudited) June 30, 2003	March 31, 2003
Assets
Utility plant, at original cost			$ 850,659	$ 842,823
	Less accumulated provisions for depreciation and amortization		249,105	245,908
			601,554	596,915
	Construction work in progress		12,804	12,639
			614,358	609,554
Goodwill			338,188	338,188
Investments:
	Nuclear power companies, at equity (Note C)		34,899	36,749
	Nonutility property and other investments		11,215	10,922
			46,114	47,671
Current assets:
	Cash and cash equivalents (including $260,250 and $244,150 with affiliates)		260,475	247,678
	Accounts receivable:
		Affiliated companies	49,161	53,112
		Others	89,540	83,657
	Fuel, materials, and supplies, at average cost		3,007	1,796
	Prepaid and other current assets		129	141
	Regulatory assets – purchased power obligations and accrued Yankee nuclear plant costs		150,407	147,200
			552,719	533,584
Regulatory assets (Note B)			1,323,536	1,377,123
Deferred charges and other assets			13,358	14,697
	Total assets		$2,888,273	$2,920,817

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

NEW ENGLAND POWER COMPANY
Balance Sheets

(In thousands)			(Unaudited) June 30, 2003	March 31, 2003
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		232,843	214,154
	Accumulated other comprehensive loss		(65)	(230)
		Total common equity	1,037,150	1,018,296
	Cumulative preferred stock, par value $100 per share		1,295	1,295
	Long-term debt		410,293	410,291
		Total capitalization	1,448,738	1,429,882
Current liabilities:
	Accounts payable (including $31,969 and $22,798 to affiliates)		57,741	71,402
	Accrued liabilities:
		Taxes	71,597	65,311
		Interest	500	357
		Purchased power obligations and accrued Yankee nuclear plant costs	150,407	147,200
		Other accrued expenses	1,990	4,506
	Dividends payable		19	19
		Total current liabilities	282,254	288,795
Deferred federal and state income taxes			260,031	258,492
Unamortized investment tax credits			8,216	8,326
Accrued Yankee nuclear plant costs			201,224	212,899
Purchased power obligations			384,181	399,699
Other reserves and deferred credits			303,629	322,724
Commitments and contingencies (Note C)
Total capitalization and liabilities			$2,888,273	$2,920,817

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

NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Periods Ended June 30
(Unaudited)

	Three Months
(In thousands)	2003	2002
Operating activities:
Net income	$ 18,709	$ 20,398
Adjustments to reconcile net income to net cash provided by operating activities:
Purchased power contract buyout and nuclear fuel amortization	16,633	13,854
Other depreciation and amortization	9,297	7,640
Deferred income taxes and investment tax credits, net	2,317	2,932
Allowance for funds used during construction	(237)	(81)
Changes in assets and liabilities:
Increase in accounts receivable, net	(1,932)	(22,703)
Decrease in regulatory assets	27,515	3,192
Increase in prepaid and other current assets	(1,199)	(490)
Increase (decrease) in accounts payable	(13,661)	1,929
Decrease in purchased power contract obligations	(12,311)	(8,053)
Increase in other current liabilities	3,913	7,810
Increase (decrease) in other non-current liabilities	(30,770)	(12,047)
Other, net	3,513	1,238
Net cash provided by operating activities	$ 21,787	$ 15,619
Investing activities:
Plant expenditures	$ (9,262)	$ (6,942)
Other investing activities	292	(450)
Net cash used in investing activities	$ (8,970)	$ (7,392)
Financing activities:
Dividends paid on preferred stock	$ (20)	$ (22)
Net cash used in financing activities	$ (20)	$ (22)
Net increase in cash and cash equivalents	$ 12,797	$ 8,205
Cash and cash equivalents at beginning of period	247,678	103,467
Cash and cash equivalents at end of period	$260,475	$111,672
Supplemental disclosures of cash flow information:
Interest paid	$ 1,484	$ 1,456
Federal and state income taxes paid	$ 3,002	$ 2,891
Dividends received from investments at equity	$ 2,352	$ 1,238

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

NEW ENGLAND POWER COMPANY
Notes to Unaudited Financial Statements

NOTE A - SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: New England Power Company (“the Company”), in the opinion of management, has included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of its operations for the interim periods presented. These financial statements for the fiscal year ended March 31, 2004 are subject to adjustment at the end of the year when they will be audited by independent accountants. These financial statements and notes thereto should be read in conjunction with the notes to the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.

New Accounting Standards: In May 2003 the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“FAS 150”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. FAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company does not expect the adoption of this statement to have a material impact on its results of operations, financial position, or cash flows.

Reclassifications: Certain amounts from prior years have been reclassified in the accompanying financial statements to conform to the current year presentation.

NOTE B – RATE AND REGULATORY ISSUES AND ACCOUNTING IMPLICATIONS

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.

The Company has received authorization from the Federal Energy Regulatory Commission (“FERC”) to recover through contract termination charges (“CTC”) substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC 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.

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 CTC which the affiliated former wholesale customers recover through delivery charges to distribution customers. The recovery of the Company’s stranded costs 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.

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, 2003 and March 31, 2003 this amounted to approximately $1.2 billion and $1.3 billion, respectively, including $0.8 billion and $0.8 billion, respectively, related to the above-market costs of purchased power contracts, $0.2 billion and $0.3 billion, respectively, related to accrued Yankee nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net CTC regulatory assets.

In conjunction with the divestiture of its generating business, the Company transferred its entitlement to power procured under several long-term contracts (“the Contracts”) to US Gen New England Inc.(“USGen”), Constellation Power Source, Inc. and Transcanada Power Marketing Ltd. (the “Buyers”). The Buyers agreed to fulfill the Company’s performance and payment obligations under the Contracts. At the same time the Company agreed to pay the Buyers a fixed amount for the above-market cost of the Contracts. These fixed monthly payments by the Company average approximately $9 million per month through December 2009 toward the above-market cost of those contracts. The net present value of these fixed monthly payments is recorded as a liability with an equal balance recorded in regulatory assets representing the future collection of the liability from rate payers. At June 30, 2003 and March 31, 2003 the net present value of the liability for the fixed monthly payment is approximately $491 million and $507 million, respectively.

On July 8, 2003, PG&E National Energy Group (USGen’s parent company) and USGen separately filed for bankruptcy protection. In the event that the bankruptcy court relieves USGen from meeting its obligations under the purchased power transfer agreement (the “Transfer Agreement”), the Company would resume the performance and payment obligations under the Contracts. At that point the Company would remove a $441 million liability and a corresponding regulatory asset from its balance sheet. To date USGen continues to perform under the Transfer Agreement. Resumption of the performance payment obligations in the case of a default by USGen would not materially affect the results of operations, as the Company would continue to pass the above-market cost of the Contracts to customers through CTC.

NOTE C – COMMITMENTS AND CONTINGENCIES

Yankee Nuclear Power Companies: The Company has minority interests in four nuclear generating companies (“Yankees”). These ownership interests are accounted for on the equity method. Three of the Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations, and one sold its nuclear generating unit in July 2002. The Company has power contracts with each of the decommissioning Yankees that require the Company to pay an amount equal to its share of total fixed and operating 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.

The Company has recorded a liability and a regulatory asset reflecting the estimated future decommissioning costs from the decommissioning Yankees. These estimates include the projected costs of decontaminating and dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. Estimated total decommissioning costs are recovered in rates regulated by the FERC. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. (For a more detailed discussion of Yankee decommissioning costs, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data, of the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.) Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTC.

Decommissioning Collections: Each of the Yankees has established a trust fund, or escrow fund, into which its owners make payments to meet the projected costs of decommissioning. In order to collect the costs of decommissioning the Yankees are required to file rate cases periodically with FERC. The rate cases present the Yankees’ estimates of future decommissioning costs for FERC approval. Maine Yankee and Connecticut Yankee are required to make rate filings with the FERC regarding their costs within the next 14 months. Yankee Atomic ceased decommissioning collections in June 2000. Subsequently, it filed for a rate increase which the FERC allowed to become effective June 5, 2003, subject to refund, and it has resumed making decommissioning collections. A settlement of the Yankee Atomic rate case has been reached, subject to FERC approval. (For a more detailed discussion of decommissioning collections, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data, of the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.)

DOE Dispute: The Nuclear Waste Policy Act of 1982 (“the Act”) establishes that the federal government, through the Department of Energy (“DOE”), is responsible for the disposal of spent nuclear fuel. Under the Act, the DOE has failed to meet its obligations to commence disposal of spent nuclear fuel by January 1998. Several lawsuits have been brought in the federal Court of Claims against the DOE by the decommissioning Yankees and numerous other utilities and state regulatory commissions due to the compliance failure. Recently, three federal Court of Claims judges issued rulings rejecting the principle portions of the DOE’s motions for summary judgment and, in effect, ordering that the case proceed to trial. (For a more detailed discussion of the DOE dispute, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data, of the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.) As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have proceeded with construction of independent spent fuel storage installations located at the plant sites.

Bechtel Dispute: On June 13, 2003, Connecticut Yankee terminated its firm fixed price contract with Bechtel Power Corporation, its decommissioning operations contractor, alleging various defaults of Bechtel’s obligations, subject to the right to cure them. Bechtel then filed a lawsuit in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other claims seeking compensatory and punitive damages. Connecticut Yankee intends to counterclaim against Bechtel and to defend against Bechtel’s claims vigorously. Connecticut Yankee intends to also pursue its rights under the $36 million performance bond supplied by Bechtel’s surety, if necessary. Bechtel failed to cure its alleged defaults and the contract termination became effective on July 14, 2003. Following the contract termination, Connecticut Yankee commenced self-performance of the decommissioning work. These developments may delay the progress of decommissioning the Connecticut Yankee power plant and may increase the Company’s costs associated with it. The Company does not believe that Connecticut Yankee’s dispute with Bechtel will have a material impact on the Company’s results of operations or financial position.

Divested Nuclear Unit: Vermont Yankee Nuclear Power Corporation: The Company has a 23.9 percent equity investment in the Vermont Yankee Nuclear Power Corporation (“Vermont Yankee”). Vermont Yankee formerly owned Vermont Yankee Nuclear Generating station (the Station). In July 2002, Vermont Yankee completed the sale of the Station to Entergy Vermont Yankee LLC. (For a more detailed discussion of the sale of the Station, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data, of the Company’s Annual Report on Form 10-K for the year ended March 31, 2003.) The Company’s portion of the proceeds from the sale of the Station will be received through a series of dividend payments and stock buybacks. The majority of the Company’s net proceeds from the sale will be credited to its customers through CTC.

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 U. S. 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.

Town of Norwood Dispute: From 1983 until 1998, the Company was the wholesale power supplier for the Town of Norwood (“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 30, 2003, the charges assessed Norwood amount to approximately $64 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (“Superior Court”). In March 2001, the Superior Court ordered Norwood to pay the Company approximately $27 million including interest, and affirmed Norwood’s obligation to make monthly CTC payments to the Company of approximately $600,000, plus interest. Norwood appealed the order in April 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 approximately $14 million and to make regular additions to the account. As reported by Norwood, the amount in the escrow account was approximately $25 million as of April 30, 2003. Oral arguments on Norwood's appeal took place in March 2003 and the parties are awaiting a decision.

In December 2002, Norwood filed a complaint with the FERC, challenging the CTC on multiple grounds. In an order dated July 2, 2003, the FERC granted the Company’s motion to dismiss those portions of Norwood’s complaint that were previously litigated before FERC and the federal district court, and set down for hearing Norwood's challenge to the factors that are used to calculate the CTC rate. In so doing, the FERC set a refund effective date of February 21, 2003, which would empower FERC to direct the Company to refund CTC payments that were billed to and paid by Norwood after that date, in the event that Norwood’s challenge is successful. However, to date, Norwood has not paid any CTC bills rendered by the Company since their commencement in May 1998.

Millstone Unit 3: In November 1999, the Company entered into an agreement with Northeast Utilities (“NU”) to settle certain claims. Among other things, the agreement provided for NU to include the Company’s 16.2 percent ownership interest in Millstone Unit 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 March 2001, the Millstone units were sold, including the Company’s interest in Millstone 3, for $1.3 billion. In accordance with the settlement agreement, the Company was paid approximately $27.9 million, from which the Company paid approximately $5.8 million to increase the decommissioning trust fund.

Regulatory authorities from Rhode Island, New Hampshire, and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that the Company would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. The Company believes it has a strong argument that it acted prudently, as the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

NOTE D - SEGMENTS

The Company's reportable segments are electric transmission and electric other. The Company is engaged principally in the business of electric power transmission. Certain information regarding the Company's segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation on such common property have been allocated to the segments based on labor or plant using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash and unamortized debt expense.

	Quarter ended June 30,
(In millions)	2003			2002
	Electric Transmission	Electric Other	Total	Electric Transmission	Electric Other	Total
Operating Revenues	$42	$72	$114	$42	$101	$143
Operating Income before Income taxes	20	11	31	20	14	34
Depreciation and Amortization	5	4	9	5	3	8
Amortization of Stranded Costs	-	17	17	-	13	13

	Total Assets at:
(In millions)	June 30, 2003	March 31, 2003
Electric Transmission	$1,139	$1,076
Electric Other	1,444	1,551
Corporate Assets	305	294
Total	$2,888	$2,921

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING INFORMATION

This report and other presentations made by New England Power Company (the “Company”) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes” or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a) the impact of further electric and gas industry restructuring;

(b) federal and state regulatory developments and changes in law, which may have a substantial adverse impact on revenues or on the value of the Company’s assets;

(c) federal regulatory developments concerning regional transmission organizations;

(d) changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position and reported earnings;

(e) failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations”, as amended.

FERC Proceedings: The Federal Energy Regulatory Commission (“FERC”) is contemplating major changes to the regulatory structure that governs the Company’s business. Several proposals are under consideration, any of which may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form, or whether they will have a material impact on the Company’s financial position or results of operations.

Generator Interconnections: On July 24, 2003, FERC issued final rules seeking to standardize the procedures and contractual arrangements for new generators with capacities over 20MW to interconnect to the transmission grid. While the Company is still assessing the full impact of these rules and whether to pursue legal or administrative challenges to them, some aspects of the rules may have a materially adverse impact on the Company. In particular, the rules appear to require the implementation of pro forma agreements for generator interconnections without clearly delineating the rights and obligations of the Company relative to an independent system operator (“ISO”) or a regional transmission organization (“RTO”) and relative to neighboring control areas that might be affected by the interconnection. In addition, FERC issued a formal notice of proposed rulemaking (“NOPR”) for special rules governing the interconnection of generators with capacities under 20MW.

Regional Transmission Organizations: Transmission owners, including the Company, have been working with stakeholders in New England to develop a proposal for a New England–only RTO or an ISOthat, except possibly for geographic scope, complies with FERC’s Order 2000 minimum characteristics and functions. Such a proposal is expected to be filed in October 2003.

Standard Market Design: In July 2002, the FERC issued a NOPR on standard market design (“SMD”). The proposed rules address transmission pricing and planning, the role of merchant transmission, and other issues that would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC’s response to the comments that it received in this proceeding. FERC states that it intends to issue a rule requiring that every public utility join an independent entity (either an RTO or an ISO) that would be responsible for transmission service, tariff design, system operations, and markets within a region. States would have a significant role in regional transmission planning, tariff design, and ensuring resource adequacy. Transmission owners that are market participants would have limited authority to manage transmission. Independent transmission companies may manage a broader set of functions. In addition, to the extent the Company wishes to pursue opportunities related to transmission projects, the FERC rulings in the SMD proceeding and other proceedings may limit the Company’s ability to do so.

Standards of Conduct: In September 2001, the FERC initiated a NOPR 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 the Company’s affiliate National Grid USA Service Company, Inc., as well as the Company’s electric distribution company affiliates. If the FERC were to adopt these rules as proposed, the Company would have to change the way it interacts with its so-called energy affiliates in a manner that could increase costs.

Incentive Pricing: In January 2003, the FERC proposed a pricing policy statement indicating that it may provide incentives to transmission owners to join an RTO or an independent transmission company and to invest in new facilities. The FERC has solicited comments on this statement, and the Company cannot predict what the final policy statement will say or whether it will have a material impact on the Company’s financial position or results of operations.

RESULTS OF OPERATIONS

EARNINGS

Net income for the three months ended June 30, 2003, decreased by approximately $2 million compared with the same period in 2002. The reduction was due primarily to decreased mitigation incentives and reduced return on contract termination charges (“CTC”) cost recovery as compared with the same period in fiscal 2003. These decreases were partially offset by increased transmission earnings during the three months ended June 30, 2003 as compared to the same period in 2002.

REVENUES

The Company has two primary sources of revenue: transmission and stranded investment recovery. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded investment recovery revenues are in the form of a CTC to former all-requirements customers of the Company in connection with the Company’s divestiture of its electric generation investments. During the prior fiscal year, the Company also had revenues associated with its ownership interests in the Vermont Yankee Nuclear Generating Station (“Vermont Yankee”) and the Seabrook Nuclear Generating Station (“Seabrook”). Vermont Yankee and Seabrook were sold in July and November 2002, respectively.

Operating revenue for the three months ended June 30, 2003, decreased approximately $29 million compared to the same period in 2002. The primary reason for the decrease was reduced sales of power received from Vermont Yankee and Seabrook during the three months ended June 30, 2003. 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.

OPERATING EXPENSES

Operating expenses for the three months ended June 30, 2003, decreased approximately $26 million, compared with the same period in 2002. The following paragraphs describe the respective decreases.

Purchased power expense for the three months ended June 30, 2003, decreased approximately $22 million compared with the same period in 2002. The decrease was primarily caused by the inclusion of purchased power expense from Vermont Yankee during the three months ended June 30, 2002 as compared with the same period in 2003. The Vermont Yankee generating station was sold in July 2002. Also contributing to the decrease were reduced ongoing payments for purchased power during the three months ended June 30, 2003 as compared with the same period in 2002, due to the November 2002 buyout of a purchased power contract.

Operation and maintenance expense for the three months ended June 30, 2003, decreased approximately $8 million, compared with the same period in 2002. The decrease was primarily caused by reduced expenses from Seabrook during the three months ended June 30, 2003 as compared with the same period in 2002. Seabrook was sold in November 2002.

Purchased power contract buyout and nuclear fuel amortization expense for the three months ended June 30, 2003, increased approximately $3 million compared with the same period in 2002. The increases were due primarily to scheduled purchased power contract buyout cost increases based upon rate agreements. The increase was partially offset by the elimination of nuclear fuel amortization cost during the three months ended June 30, 2003, as compared with the same period in 2002, due to the sale of Seabrook in November 2002.

Other depreciation and amortization expense for the three months ended June 30, 2003, increased by approximately $2 million compared with the same period in 2002. The increase is primarily due to the recovery and amortization of generation-related stranded costs being greater during the three months ended June 30, 2003 compared with the same period in 2002. The increase was partially offset by reduced decommissioning expenses during the three months ended June 30, 2003, as compared with the same period in 2002, due to the sale of Seabrook in November 2002.

Other income and expense for the three months ended June 30, 2003, increased approximately $1 million compared with the same period in 2002. The increase is due primarily to greater interest income from loans to affiliated companies during the three months ended June 30, 2003 as compared with the same period in 2002.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2003 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $260 million and accounts receivable of $139 million. The Company has a working capital balance of approximately $269 million.

Net cash flows provided by operating activities for the three months ended June 30, 2003, was approximately $22 million.

Net cash flows used in investing activities for the three months ended June 30, 2003, increased approximately $2 million compared with same period in 2002, primarily due to increased plant expenditures.

At June 30, 2003, 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, 2003, the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million which is 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. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at June 30, 2003. Fees are paid on the lines and facilities in lieu of compensating balances.

Utility Plant Expenditures: Cash expenditures for the Company for utility plant totaled approximately $9 million for the three months ended June 30, 2003, and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk: The Company’s major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At June 30, 2003, the Company’s tax exempt variable rate long-term debt had a carrying 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, 2003, was approximately 1.16 percent.

Item 4. Controls and Procedures

The Company has established and maintains disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to the Company is made known to management by others within those entities, particularly during the period in which this report is being prepared. The Company maintains a Disclosure Committee, which is made up of several key management employees and which reports directly to the Chief Financial Officer and President. The Disclosure Committee monitors and evaluates these disclosure controls and procedures. The Chief Financial Officer and President have evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, it was determined that these disclosure controls and procedures were effective in providing reasonable assurance during the period covered in this report. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a discussion of pending legal proceedings, see Note C, Contingencies, in Part I, Item 1. Unaudited Financial Statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Annual Meeting of Stockholders was held on April 16, 2003. By unanimous vote of the 3,619,896 shares present of 3,632,846 total shares having general voting rights, the following actions were taken:

The number of directors was fixed at five.

The following persons were elected as directors: John G. Cochrane, Michael E. Jesanis, Stephen P. Lewis, Lawrence J. Reilly, and Nicholas Winser.

James S. Robinson was elected Treasurer and Gregory A. Hale was elected Clerk.

The firm of PricewaterhouseCoopers was appointed the Company’s auditor for the fiscal year ending March 31, 2004.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits

	The exhibit index is incorporated herein by reference.

(b)	Reports on Form 8-K

	The Company did not file any reports on Form 8-K during the fiscal quarter ended June 30, 2003.

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, 2003 to be signed on its behalf by the undersigned thereunto duly authorized.

	NEW ENGLAND POWER COMPANY


Date: August 8, 2003	By	/s/ Edward A. Capomacchio
		Edward A. Capomacchio
		Authorized Officer and Controller and Principal Accounting Officer

NEW ENGLAND POWER COMPANY

EXHIBIT INDEX

Exhibit Number	Description

31.1	Certification of Principal Executive Officer

31.2	Certification of Principal Financial Officer

32	Certifications under Section 1350

NEW ENGLAND POWER CO 10-Q