UNITED STATES
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, 2004

OR

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

              For the transition period from __________ to __________

Commission File Number	Registrant, State of Incorporation Address and Telephone Number	I.R.S. Employer Identification No.
2-26651	New England Power Company (a Massachusetts corporation) 25 Research Drive Westborough, Massachusetts 01582 508.389.2000	04-1663070

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 9, 2004, were as follows:

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

NEW ENGLAND POWER COMPANY

FORM 10-Q - For the Quarter Ended June 30, 2004

			PAGE
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
		Condensed Statements of Income
		Condensed Statements of Retained Earnings
		Condensed Statements of Comprehensive Income
		Condensed Balance Sheets
		Condensed Statements of Cash Flows
		Notes to Unaudited Condensed 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
Condensed Statements of Income
Periods Ended June 30
(In thousands of dollars)
(UNAUDITED)

                                                                                                     Three Months

			2004	2003
Operating revenue, principally from affiliates			$ 113,919	$ 110,629
Operating expenses:
	Purchased electric energy:
		Contract termination and nuclear unit shutdown charges	36,738	35,589
		Other	3,837	2,224
	Other operation		14,840	12,916
	Maintenance		1,922	2,244
	Amortization of stranded costs		17,667	18,052
	Depreciation and amortization		4,790	4,062
	Taxes, other than income taxes		4,293	4,438
	Income taxes		11,326	12,169
		Total operating expenses	95,413	91,694
Operating income			18,506	18,935
Other income:
	Equity in income of nuclear power companies		393	498
	Other income , net		410	1,080
		Operating and other income	19,309	20,513
Interest:
	Interest on long-term debt		1,474	1,616
	Other interest		214	188
		Total interest	1,688	1,804
Net income			$ 17,621	$ 18,709
Dividends on preferred stock			(19)	(20)
Income available to common shareholder			$ 17,602	$ 18,689

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
Condensed Statements of Retained Earnings
Periods Ended June 30
(In thousands of dollars)
(UNAUDITED)

                                                                                                     Three Months

	2004	2003
Retained earnings at beginning of period	$209,319	$214,154
Net income	17,621	18,709
Dividends declared on cumulative preferred stock	(19)	(20)
Retained earnings at end of period	$226,921	$232,843

NEW ENGLAND POWER COMPANY
Condensed Statements of Comprehensive Income
Periods Ended June 30
(In thousands of dollars)
(UNAUDITED)

                                           Three Months

	2004	2003
Net income	$ 17,621	$ 18,709
Unrealized gain(loss) on securities, net of tax	(36)	165
Comprehensive income	$ 17,585	$ 18,874

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
Condensed Balance Sheets
(In thousands of dollars)
(UNAUDITED)

			June 30, 2004	March 31, 2004
Assets
Utility plant, at original cost			$ 921,416	$ 878,824
	Less accumulated depreciation and amortization		243,095	240,203
			678,321	638,621
	Construction work in progress		16,042	12,852
			694,363	651,473
Goodwill			338,188	338,188
Investments:
	Nuclear power companies, at equity (Note C)		17,606	18,305
	Non-utility property and other investments		11,275	11,290
			28,881	29,595
Current assets:
	Cash and cash equivalents (including $253,150 and $229,400 with affiliates)		253,344	229,716
	Accounts receivable:
		Affiliated companies	52,769	51,131
		Others (less reserves of $153 and $153)	112,048	104,338
	Fuel, materials, and supplies, at average cost		2,214	2,054
	Prepaid and other current assets		1,201	1,370
	Deferred federal and state income taxes		420	202
	Regulatory assets – purchased power obligations		105,095	105,011
			527,091	493,822
Regulatory assets (Note B)			1,076,465	1,134,382
Additional minimum pension regulatory asset			62,454	62,454
Prepaid pension asset			49,256	47,245
Deferred charges and other assets			4,871	5,374
	Total assets		$2,781,569	$2,762,533

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

NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(In thousands of dollars)
(UNAUDITED)

			June 30, 2004	March 31, 2004
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		226,921	209,319
	Accumulated other comprehensive income		51	87
		Total common equity	1,031,344	1,013,778
	Cumulative preferred stock, par value $100 per share		1,274	1,274
	Long-term debt		410,299	410,297
		Total capitalization	1,442,917	1,425,349
Current liabilities:
	Accounts payable (including $33,233 and $34,814 affiliates)		59,695	59,620
	Accrued liabilities:
		Taxes	25,433	18,337
		Interest	985	532
		Purchased power obligations	105,095	105,011
		Other accrued expenses	9,097	3,216
	Dividends payable		19	19
		Total current liabilities	200,324	186,735
Deferred federal and state income taxes			233,492	234,054
Unamortized investment tax credits			7,776	7,885
Additional minimum pension liability			39,952	39,952
Accrued Yankee nuclear plant costs			259,327	269,997
Purchased power obligations			263,736	293,296
Other reserves and deferred credits			334,045	305,265
Commitments and contingencies (Note C)
Total capitalization and liabilities			$2,781,569	$2,762,533

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

NEW ENGLAND POWER COMPANY
Condensed Statements of Cash Flows
Periods Ended June 30
(In thousands of dollars)
(UNAUDITED)

	Three Months
	2004	2003
Operating activities:
Net income	$ 17,621	$ 18,709
Adjustments to reconcile net income to net cash provided by operating activities:
Purchased power contract buyout amortization	17,667	18,052
Other depreciation and amortization	4,790	4,062
Deferred income tax(tax benefit) and investment tax credits, net	92	2,317
Allowance for funds used during construction	(171)	(237)
Changes in assets and liabilities:
Increase in accounts receivable, net	(9,348)	(1,932)
Decrease in regulatory assets	39,425	31,331
Increase in prepaid and other current assets	(236)	(1,199)
Increase (decrease) in accounts payable	75	(13,661)
Decrease in purchased power contract obligations	(29,476)	(25,919)
Increase in other current liabilities	9,005	3,913
Decrease in other non-current liabilities	(17,110)	(17,162)
Other, net	842	3,513
Net cash provided by operating activities	$ 33,176	$ 21,787
Investing activities:
Plant expenditures	$ (9,529)	$ (9,262)
Other investing activities	-	292
Net cash used in investing activities	$ (9,529)	$ (8,970)
Financing activities:
Dividends paid on preferred stock	$ (19)	$ (20)
Net cash used in financing activities	$ (19)	$ (20)
Net increase in cash and cash equivalents	$ 23,628	$ 12,797
Cash and cash equivalents at beginning of period	229,716	247,678
Cash and cash equivalents at end of period	$ 253,344	$ 260,475
Supplemental disclosures of cash flow information:
Interest paid	$ 1,235	$ 1,484
Federal and state income taxes paid	$ 4,574	$ 3,002
Dividends received from investments at equity	$ 838	$ 2,352

The accompanying notes are an integral part of these 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. The March 31, 2004 condensed balance sheet data included in this quarterly report on Form 10-Q was derived from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004. As such, the March 31, 2004 balance sheet included in this Form 10-Q is considered unaudited as it does not include all the footnote disclosures contained in the Company’s Form 10-K. These financial statements and the notes thereto should be read in conjunction with the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004.

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

The company is a wholly owned subsidiary of National Grid USA and, indirectly National Grid Transco plc.

New Accounting Standards: On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act expands Medicare, primarily by adding a prescription drug benefit for Medicare-eligibles starting in 2006.  The Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer's program.  

Paragraph 40 of the Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions requires that presently enacted changes in laws impacting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of this Act.

Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy.  Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not impact the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs effective July 1, 2004.

NOTE B — RATE AND REGULATORY ISSUES

Because electricity 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 (CTCs) substantially all of the costs associated with its former generating business not recovered through the divestiture of the generation assets. 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 (nuclear and nonnuclear) and related contractual commitments that were not recovered through the sale of those investments (stranded costs). Stranded costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through a CTC which the affiliated former wholesale customers recover through delivery charges to distribution customers. The Company earns a return on equity (ROE) of approximately 9.7 percent on stranded cost recovery. Most stranded costs will be fully recovered through CTCs by the end of 2010. The Company’s stranded cost 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. The Company, under certain settlement agreements, earns incentives based on successful mitigation of its stranded costs and 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 CTCs. At June 30, 2004 and March 31, 2004 this amounted to approximately $1.0 billion and $1.1 billion, respectively, including $0.6 billion and $0.7 billion, respectively, related to the above-market costs of purchased power contracts, $0.2 billion and $0.3 billion, respectively, related to accrued nuclear plant costs, and $0.2 billion and $0.2 billion, respectively, related to other net 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 monthly for the above-market cost of the Contracts. Annually these fixed payments by the Company average approximately $106 million through December 2007 decreasing to approximately $12 million for 2008 then decreasing to approximately $3 million annually from 2009 to 2014. 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 ratepayers. At June 30, 2004 and March 31, 2004, the net present value of the liability for the fixed monthly payment is approximately $369 million and $398 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 relieved 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 the liability and a corresponding regulatory asset for the above market cost of the Contracts from its balance sheet. At June 30, 2004, the Company’s capitalized cost of the above market portion of the USGen Contracts is approximately $307 million. 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 a CTC.

Separate from the Transfer Agreement, USGen asked the bankruptcy court to relieve it of obligations under Hydro Quebec transmission line agreements (HQ Contracts) under which it was obligated to reimburse the Company for monthly costs of approximately $1 million. USGen and the Company entered into a stipulation under which USGen continued to reimburse the Company through April 1, 2004. As of April 2, 2004, the Company resumed performance and payment under the HQ Contracts. The Company has a claim against USGen in bankruptcy for its damages. The Company’s resumption of performance and payment obligations will not affect the results of operations, as the Company will be able to recover any remaining costs through CTC’s from its customers.

NOTE C — COMMITMENTS AND CONTINGENCIES

Decommissioning Nuclear Units: The Company has minority interests in three nuclear generating companies: Yankee Atomic Electric Company, Connecticut Yankee Atomic Power Company, and Maine Yankee Atomic Power Company (together, the Yankees). These ownership interests are accounted for on the equity method. The Yankees own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These three units are as follows:

	The Company’s Investment as of June, 30 2004			Future Estimated Billings to the Company
Unit	%	$(millions)	Date Retired	$(millions)
Yankee Atomic	34.5	0.3	Feb 1992	53
Connecticut Yankee	19.5	8.3	Dec 1996	125
Maine Yankee	24.0	9.0	Aug 1997	81

With respect to each of these units, NEP has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs.

Maine Yankee and Connecticut Yankee recover their prudently incurred costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. The Company’s share of the decommissioning costs is accounted for in "Purchased electricity" on the income statement.

Future estimated billings from the Yankees are based upon decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission (NRC), dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. Included in the table above are future estimated billings that the Yankees made to their cost estimates beginning in the third quarter of fiscal 2003 and continuing through fiscal 2004 to reflect projected future security and insurance cost increases and other expenses. NEP’s share of these increases is approximately $162 million. Under settlement agreements, NEP is permitted to recover prudently incurred decommissioning costs through CTCs.

Decommissioning Collections: Each of the Yankees has established a trust fund, or escrow fund, to meet the projected costs of decommissioning. In order to collect the costs of decommissioning, from their purchasers (including NEP), the Yankees are required to file rate cases periodically with FERC. The rate filings present the Yankees’ estimates of future decommissioning costs for FERC approval. Yankee Atomic ceased decommissioning collections in June 2000. Subsequently, it filed for a rate increase, and received final approval from the FERC on October 2, 2003. Maine Yankee filed a rate case on October 20, 2003, and Connecticut Yankee filed a rate case on July 1, 2004.

Connecticut Yankee seeks a rate increase of approximately $76 million per year through 2010, of which NEP’s share would be approximately $15 million per year. This amount is included in the $162 million increase for all of the Yankees mentioned above. On June 10, 2004, the Connecticut Department of Public Utilities and the Connecticut Office of Consumer Counsel filed a petition with the FERC alleging that Connecticut Yankee’s management has been imprudent and asking the FERC to determine that if it should find that any of Connecticut Yankee’s decommissioning costs were not prudently incurred, the purchasers may not recover these costs in rates that are ultimately charged to distribution customers. Three other New England states have intervened in support of the state of Connecticut, as has Bechtel Power Corporation. Connecticut Yankee has opposed the petition, as have NEP and the other purchasers. NEP intends to contest the petition vigorously but cannot predict the outcome of this proceeding.

DOE Dispute: The Nuclear Waste Policy Act of 1982 establishes that the federal government, through the Department of Energy (DOE), is responsible for the disposal of spent nuclear fuel. In a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia Circuit ruled in 1997 that the DOE was obligated to begin disposing of utilities’ spent nuclear fuel by January 1998. The DOE failed to meet this deadline. Many owners of nuclear power plants, including the Yankees, filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s failure to begin to take fuel in 1998. In October 1998 the court held that the DOE is liable for such failure. The Yankees have filed a further action against the DOE to determine the level of damages. The trial began July 21, 2004. As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have constructed 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 Betchel’s obligations. Bechtel has filed proceedings in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other claims, seeking compensatory and punitive damages and seeking garnishment of decommissioning trust funds and certain assets of Connecticut Yankee. Connecticut Yankee has filed a counterclaim against Bechtel and has stated that it intends to defend against Bechtel’s claims vigorously and to pursue its rights under the $36 million performance bond supplied by Bechtel’s surety, if necessary.  Following the contract termination, Connecticut Yankee commenced self-performance of the decommissioning work. As part of its transition into self-performance, Connecticut Yankee updated its 2003 cost estimate and filed a rate case as described above. This update includes the impact of Bechtel’s termination and reflects a substantial increase in cost and delay in the estimated completion date.

Divested Nuclear Units:

Vermont Yankee Nuclear Power Corporation (Vermont Yankee): NEP redeemed its 23.9 percent equity investment in Vermont Yankee on November 7, 2003. Vermont Yankee formerly owned the Vermont Yankee Nuclear Generating Station (the Station). It sold the Station to Entergy Vermont Yankee LLC (ENVY) in July 2002 for approximately $180 million. NEP’s portion of the sale price was approximately $43 million before settlement of Vermont Yankee’s outstanding liabilities. As part of the transaction, ENVY assumed the decommissioning liability for the Station. Following regulatory approvals and prior to the redemption of its stock on October 27, 2003, Vermont Yankee distributed to its owners, including NEP, a majority of the proceeds from the sale after payment of outstanding debt and other obligations. NEP received approximately $13 million in this distribution.

Vermont Yankee Missing Fuel Rod Segments: In April 2004, in response to an NRC inspection, which was conducted during the Station’s regularly scheduled refueling outage, ENVY determined that two spent nuclear fuel rod segments were not in their documented location in the spent fuel pool. Following an investigation of the matter, plant officials announced on July 13, 2004 that the missing fuel had been located in the Station’s spent fuel pool. According to station documentation, in 1979 the rods were placed in a special stainless steel container in the spent fuel pool.

ENVY has informed Vermont Yankee that it believes that Vermont Yankee is responsible under their Purchase and Sale Agreement for all costs arising in connection with ENVY's inspection.  On May 20, 2004 Vermont Yankee requested additional information from ENVY. The fuel has been located, and the expenditures made are not material to NEP.

Contracts for the Purchase of Electricity from ENVY: In connection with the sale of the Station, Vermont Yankee entered into a power contract with ENVY. Under an agreement between Vermont Yankee and NEP, NEP buys 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. The Company has a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs. The Company sells the power to the third party at its cost and thus does not recognize any financial impact from the agreement on its financial statements. The Company matches the cost of the power contract with the revenue from the sale of the power to the third party on its income statement. The Company’s commitments for future fiscal periods, under this purchased power contract as of March 31, 2004, are as follows: 2005, $44 million; 2006, $43 million; 2007, $45 million; 2008, $43 million; 2009, $45 million and 2010 and thereafter $157 million.

Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At June 30, 2004, the Company had guaranteed approximately $12 million of project debt with terms through 2015. As a result of the termination of an assignment of certain obligations under the Support Agreements on April 1, 2004, the Company recorded a capital lease with an offsetting liability of $38 million. The Company remains an obligor under the support agreements for the portion of the rights it transferred until 2020. See Note B for a discussion of the termination and the recovery of costs associated with these Support Agreements.

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 the costs to remediate property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws.

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

The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Some of these sites relate to the disposal of ash from fossil fuel generating plants formerly owned by the Company. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The Company has recovered amounts from certain insurers, and, where appropriate, intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company is currently recovering certain environmental cleanup costs in rates. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position.

Town of Norwood Dispute: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood, Massachusetts. From 1983 until 1998, NEP was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through June 30, 2004, the charges assessed Norwood amount to approximately $83 million, approximately $20 million of which was paid in July 2004. The litigation with Norwood is as follows.

State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood had refused to pay.  In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Norwood unsuccessfully appealed the order to the Massachusetts Appeals Court, and the Massachusetts Supreme Judicial Court denied Norwood’s petition for further appellate review.  On June 1, 2004, the Supreme Court denied Norwood’s petition for certiorari.

On December 17, 2003, the Superior Court entered judgment for NEP for approximately $40.6 million, which included interest to that date, and which the Company subsequently moved to increase by approximately $2.7 million, to adjust for computational errors.  Norwood then moved to void the judgment, or stay its enforcement pending completion of the FERC proceeding described below, or both. On June 9, 2004, the Massachusetts Superior Court granted NEP’s motion to increase the judgment and denied Norwood’s motion to void the judgment or stay it pending Norwood’s Section 206 Proceeding at FERC. Norwood has asked the Superior Court to reconsider its grant of NEP’s motion and has appealed the judgment to the Massachusetts Appeals Court.   

FERC 206 Proceeding: In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood, and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula which the FERC accepted and approved in 1998. On July 9, 2004, NEP filed a brief objecting to this initial decision. Norwood and the FERC staff have filed briefs which argue that the CTC rate recommended in the initial decision is too high.

Federal Court Antitrust Claim: In 1997, Norwood filed a lawsuit in the U.S. District Court for the District of Massachusetts challenging NEP’s proposed divestiture of its generating facilities. Following the District Court’s dismissal of all of Norwood’s claims, the U.S. Court of Appeals for the First Circuit reinstated Norwood’s claim that the sale to US Gen New England, Inc. (USGen) violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak because FERC had found no anticompetitive consequences from the sale, and invited the District Court to address whether the FERC’s decision precluded further litigation. This issue was argued to the District Court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself. USGen’s bankruptcy filing on July 2, 2003 resulted in an automatic stay of this case.

Millstone 3 Prudence Challenge: In November 1999, NEP entered into an agreement with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’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, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP 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 NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. On July 16, 2004, the New Hampshire Public Utilities Commission approved a settlement which will become final on August 16, 2004. The settlement provides that NEP will not have to adjust its contract termination charge to its New Hampshire distribution affiliate Granite State Electric Company as a result of NEP’s former ownership interest in Millstone 3. In the event that Rhode Island or Massachusetts or both states proceed with such a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because 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 (primarily stranded cost recovery, see Note B – “Rate and Regulatory Issues”). 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)	2004			2003
	Electric transmission	Electric other	Total	Electric transmission	Electric other	Total
Operating revenues	$42	$72	$114	$42	$69	$111
Operating income before income taxes	21	9	30	20	11	31
Depreciation and amortization	4	-	4	4	-	4
Amortization of stranded costs	-	18	18	-	18	18

	Total assets at:
(In millions)	June 30, 2004	March 31, 2004
Electric transmission	$1,156	$1,111
Electric other	1,345	1,394
Corporate assets	281	258
Total	$2,782	$2,763

NOTE E – EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the year ended March 31, 2004 National Grid USA and its subsidiaries (including the Company), provide benefits to retirees in the form of pension and other postretirement benefits. The qualified defined benefit pension plans cover substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans’ assets primarily consist of investments in equity and debt securities. In addition, National Grid USA and its subsidiaries (including the Company) sponsor non-qualified plans (plans that do not meet the criteria for tax benefits) that cover officers, certain other key employees, and non-employee directors. National Grid USA and its subsidiaries (including the Company) provide certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments.

Benefit plans’ costs charged to the Company during the three months ended June 30, 2004 and 2003 included the following components:

($'s in 000's)	Pension Benefits		Other Postretirement            Benefits
For the Three Months Ended June 30,	2004	2003	2004	2003
Service cost	$ 18	$ 17	$ 18	$ 17
Interest cost	1,959	1,922	947	902
Expected return on plans' assets	(2,551)	(2,330)	(921)	(854)
Amortization of prior service cost	38	46	(14)	(5)
Recognized actuarial loss	680	678	353	129
Net periodic benefit cost	$ 144	$ 333	$ 383	$ 189
Special termination benefits	$     -	$ 180	$      -	$ 28

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 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.

CRITICAL ACCOUNTING POLICIES

Certain critical accounting policies are based on assumptions and conditions that, if changed, could have a material effect on the financial condition, results of operations and liquidity of the Company. See the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2004, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Policies” for a detailed discussion of these policies.

RESULTS OF OPERATIONS

EARNINGS

Net income for the quarter ended June 30, 2004, was not significantly different from the prior year and decreased by approximately $1 million as a result of decreased mitigation incentives and reduced return on CTCs compared with the same period in 2003. This decrease was partially offset by increased transmission earnings during the quarter as compared with the same period in 2003.

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.

Operating revenue for the quarter ended June 30, 2004, increased approximately $3 million as compared to the same period in 2003 as a result of increased recovery of contract termination and nuclear unit shutdown charges.

OPERATING EXPENSES

Purchased power expense for the quarter ended June 30, 2004, increased approximately $3 million compared with the same period in 2003 due to decommissioning collections for Yankee Atomic Electric Company, which resumed in June 2003.

Operation and maintenance expense for the quarter ended June 30, 2004, increased approximately $2 million compared with the same period in 2003. The primary reason for the increase was increased transmission wheeling expenses.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2004 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $253 million and accounts receivable of $165 million. The Company has a working capital balance of approximately $327 million.

Net cash flows provided by operating activities for the quarter ended June 30, 2004, was approximately $33 million.

Net cash flows used in investing activities for the quarter ended June 30, 2004, increased approximately $1 million compared with the same period in 2003, primarily due to increased plant expenditures.

At June 30, 2004, 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, 2004, 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, 2004. 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 quarter ended June 30, 2004, and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

OTHER REGULATORY MATTERS

Rate Filing: As discussed in more detail in the Company’s Form 10-K for the fiscal year ended March 31, 2004, on March 24, 2004 FERC issued an order approving for regional network service rates (RNS) a 0.5% return on equity adder for joining a proposed Regional Transmission Organization (RTO) effective as of the date that the RTO commences operation. NEP would earn this additional return on equity (ROE) provided it joins the RTO. Approximately seventy percent of the company’s transmission costs are recovered through RNS rates. FERC also suspended a proposed increase to 12.8% of the base ROE for both RNS and Local Network Service rates and a 1% adder for new transmission investment recovered through RNS rates subject to refund effective as of the RTO operations date. The issues concerning the base ROE for both RNS rates and LNS rates and the 1% adder for new transmission investment recovered through RNS rates have been set for an evidentiary hearing in December 2004. The Connecticut Department of Public Utility Control and some transmission customers have intervened in the proceeding. On July 30 these interveners filed testimony advocating for a base return on equity ranging from approximately 8.5% to 9.5%, and against the 1% adder for new transmission investment.

The transmission owners on April 15, 2004 filed a motion for clarification with FERC on three issues that were addressed in the March 24 order. Each of these issues concerns the amount of revenues that transmission owners would receive once the RTO commences operations.

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, 2004, 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 quarter ended June 30, 2004, was approximately 1.17 percent.


ITEM 4.     CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

During the most recent fiscal quarter, the Company completed implementation of a new enterprise resource planning and information system to integrate its finance and accounting, supply chain and work management information systems. The implementation of this new system has resulted in new processes for recording the underlying transactions of the Company’s financial statements. As such, the Company’s internal controls have been modified to encompass these new processes.

PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS

Millstone 3 Prudence Challenge: As described in the Company’s Form 10-K for the fiscal year ended March 31, 2004, regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the Company’s settlement agreement with Northeast Utilities, under which NEP received a fixed amount when the Millstone units were sold in 2001. On July 16, 2004, the New Hampshire Public Utilities Commission approved a settlement which will become final on August 16, 2004. The settlement provides that NEP will not have to adjust its contract termination charge to its New Hampshire distribution affiliate Granite State Electric Company as a result of NEP’s former ownership interest in Millstone 3.


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

As reported in the Company’s Form 10-K for the fiscal year ended March 31, 2004, the Annual Meeting of Stockholders was held on April 21, 2004. By a vote of 3,619,906 shares out of 3,632,630 total shares voted, 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 Jeffrey A. Scott.

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

• PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2005.

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, 2004.

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, 2004 to be signed on its behalf by the undersigned thereunto duly authorized.

	NEW ENGLAND POWER COMPANY
Date: August 13, 2004	By	/s/ Edward A. Capomacchio                          Edward A. Capomacchio Authorized Officer and Controller and Principal Accounting Officer

EXHIBIT INDEX

Exhibit Number	Description
31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)
31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)
32	Section 1350 Certifications