For the transition period from __________ to __________

NEW ENGLAND POWER COMPANY

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

Condensed Statements of Comprehensive Income
(In thousands)
(Unaudited)

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

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


NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(Unaudited)

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



NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(Unaudited)

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



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

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, 2003 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, 2003. As such, the March 31, 2003 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, 2003.

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 September 30, 2003 and March 31, 2003 this amounted to approximately $1.1 billion and $1.3 billion, respectively, including $0.7 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 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 monthly for the above-market cost of the Contracts. Annually these fixed payments by the Company average approximately $108 million through December 2007 decreasing to approximately $9 million and $2 million, respectively, in 2008 and 2009. 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 September 30, 2003 and March 31, 2003 the net present value of the liability for the fixed monthly payment is approximately $419 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 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 a $371 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.

Separate from the Transfer Agreement, USGen has asked the bankruptcy court to relieve it of obligations under Hydro Quebec transmission line agreements ("HQ Contracts") to reimburse the Company for monthly costs of approximately $1 million. If the bankruptcy court grants USGen's motion and regulatory approval of the termination is received, the Company will resume performance and payment under the HQ Contracts, and it will have a claim against USGen in bankruptcy for its damages. To date USGen continues to perform under the HQ Contracts. If the Company resumes performance and payment obligations, it will not affect the results of operations, as the Company, after the collection of damages, will be able to recover any remaining costs from customers.

NOTE C - COMMITMENTS AND CONTINGENCIES

Yankee Nuclear Power Companies: The Company has minority interests in three nuclear generating companies: Yankee Atomic, Connecticut Yankee and Maine Yankee (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. The Company has power contracts with each of the Yankees that require the Company to pay an amount equal to its share of total fixed and operating costs 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 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 all prudently incurred decommissioning costs through the 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 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, 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 was approved by the FERC on October 2, 2003. Maine Yankee filed a rate case on October 20, 2003, and Connecticut Yankee is required to file a case within the next 12 months. (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. The DOE has failed to meet its obligations under the Act 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 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 Bechtel's obligations. 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 has filed a counterclaim against Bechtel and intends to defend itself 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.  Following the contract termination, Connecticut Yankee commenced self-performance of the decommissioning work. As part of its transition into self-performance, Connecticut Yankee is updating its 2003 cost estimate. This update will include the impacts of Bechtel's termination and is expected to reflect a substantial increase in cost. 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 had a 23.9 percent equity investment in the Vermont Yankee Nuclear Power Corporation ("Vermont Yankee") as of September 30, 2003, which it redeemed on November 7, 2003. Vermont Yankee formerly owned Vermont Yankee Nuclear Generating station (the "Station"). It sold the Station to Entergy Vermont Yankee LLC in July 2002. Following regulatory approvals, on October 27, 2003, Vermont Yankee distributed to its owners including the Company a majority of the proceeds from the sale after payment of outstanding debt and other obligations. On November 7, 2003, Vermont Yankee repurchased from the Company all of the Company's equity in Vermont Yankee. (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.)

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 September 30, 2003, the charges assessed Norwood amount to approximately $69 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, and the Court of Appeals affirmed the Superior Court's order in October 2003. Norwood filed an appeal with the Supreme Judicial Court in November 2003. Pending the first 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.

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. The FERC set down for hearing Norwood's challenge to the factors used to calculate the CTC rate, noting that Norwood bears the burden of proof on that challenge. The FERC set a refund effective date of February 21, 2003, which empowers the FERC to direct the Company to refund CTC payments that were billed to and paid by Norwood after that date, or to adjust Norwood's liability for unpaid charges billed after that date, in the event that Norwood's challenge is successful. The FERC's administrative law judge set a hearing date of March 29, 2004 to consider Norwood's challenge to the CTC rate, and the judge is expected to issue an initial decision in May 2004. This decision will be subject to review by the FERC. 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 (primarily stranded cost recovery, see Note B - "Rate and Regulatory Issues and Accounting Implications"). 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.

NOTE E - SUBSEQUENT EVENTS

In July 2003, National Grid USA announced an upcoming voluntary early retirement offer ("VERO") to non-union employees in New York and New England who work in areas where workforce reductions are targeted, including transmission, retail operations (in New England), and corporate administrative functions such as finance, human resources, legal, and information technology. Eligible employees include non-union employees in the targeted functions who will be age 55 with at least ten years of service by December 31, 2004. National Grid USA sets the actual retirement dates for individuals based on business operational needs. Retirement dates will conclude no later than November 1, 2004 for the majority of enrollees, but in some cases retirements may not occur until as late as November 1, 2007. The enrollment period for the VERO ended on October 31, 2003. The cost of the VERO to the Company is approximately $3 million. The VERO will not affect the results of operations, as the Company will recover the expense through cost recovery mechanisms.

In October 2003, National Grid USA announced an upcoming VERO to approximately 520 eligible union employees in New England. Eligible employees will include employees who will be age 55 with at least ten years of service by December 31, 2004. National Grid USA will set the actual retirement dates for individuals based on business operational needs. Retirement dates will occur in two groups. The first group will conclude no later than February 1, 2004. The second group will be released over a four year period beginning on February 1, 2004 and concluding no later than January 1, 2008. The expense associated with this early retirement program will be recovered through cost recovery mechanisms.

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.

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. The final rules became effective October 20, 2003, but due to the complexity of coordinating roles and responsibilities in regions with RTOs and ISOs, FERC has extended the deadline for compliance filings by RTOs, ISOs and individual transmission owners in those regions until January 20, 2004. The Company has sought rehearing of various aspects of these rules which could have materially adverse impacts on the Company, and it is actively working in the regional stakeholder process to implement the rules in a manner that will mitigate such adverse impacts.  In particular, the rules appear to require the implementation of pro forma agreements for generator interconnections without recognizing the Company's rights under the Federal Power Act to set the rates, terms and conditions of access to its transmission facilities and 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, and ISO-NE have filed with FERC for approval of a New England RTO that complies with FERC's Order 2000 minimum characteristics, including independence from the market, and functions. The filing includes an RTO transmission tariff which would govern the recovery of the Company's transmission revenues. The proposed tariff continues to provide for a formula rate for the recovery of the Company's transmission expenses. The filing parties have requested that the RTO tariff and related agreements be made effective on or after March 1, 2004 on a date to be designated by transmission owners and the RTO.

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. 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.

Rate Filing: Transmission owners in New England, including the Company, have filed with FERC to increase their allowed return on equity in transmission rates. The filing has three components. First, transmission owners seek an increased return on equity of 12.8%. Second, transmission owners seek an additional 0.5% return on equity for joining the RTO which they have separately proposed to FERC. Third, transmission owners seek an additional 1% equity return on new transmission investment that is constructed pursuant to an approved RTO plan. The increased returns are requested to take effect on the same date that the RTO becomes effective, on or after March 1, 2004 on a date to be designated by transmission owners and the RTO.

Net income for the quarter and six months ended September 30, 2003, decreased by approximately $3 million and $4 million, respectively, compared with the same periods in 2002. The reduction was due primarily to decreased mitigation incentives and reduced return on contract termination charges ("CTC") cost recovery compared with the same periods in 2002. Also contributing to the decrease was reduced equity income from nuclear generation due to the sale of Vermont Yankee in July 2002. These decreases were partially offset by increased transmission earnings during the quarter and six months ended September 30, 2003 as compared to the same periods in 2002.

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 quarter and six months ended September 30, 2003, decreased approximately $9 million and $38 million, respectively, compared to the same periods in 2002. The primary reason for the decrease was reduced sales of power received from Vermont Yankee and Seabrook during the quarter and six months ended September 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. In addition, reduced mitigation incentives under the CTC contributed to the reduction in operating revenue.

OPERATING EXPENSES

Operating expenses for the quarter and six months ended September 30, 2003, decreased approximately $7 million and $33 million, respectively, compared with the same periods in 2002. The following paragraphs describe the respective decreases.

Purchased power expense for the quarter and six months ended September 30, 2003, decreased approximately $9 million and $31 million, respectively, compared with the same periods in 2002. The decrease was primarily caused by the inclusion of purchased power expense from Vermont Yankee during the four months ended July 31, 2002 as compared with the same period in 2003. The Vermont Yankee generating station was sold in July 2002. Also contributing to the decreases were reduced ongoing payments for purchased power during the quarter and six months ended September 30, 2003 as compared with the same periods in 2002, due to the November 2002 buyout of a purchased power contract. Partially offsetting the decreases was an increase in purchased power expenses due to the resumption of decommissioning billings by Yankee Atomic in June 2003.

Operation and maintenance expense for the quarter and six months ended September 30, 2003, decreased approximately $1 million and $8 million, respectively compared with the same periods in 2002. The decreases were primarily caused by the inclusion of expenses from Seabrook during the quarter and six months ended September 30, 2002 as compared with the same periods in 2003. Seabrook was sold in November 2002. (For a more detailed discussion of the Seabrook sale, 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.)

Purchased power contract buyout and nuclear fuel amortization expense for the quarter and six months ended September 30, 2003, increased approximately $3 million and $6 million, respectively, compared with the same periods in 2002. The increases were due primarily to scheduled purchased power contract buyout cost increases based upon rate agreements. The increases were partially offset by the elimination of nuclear fuel amortization cost during the quarter and six months ended September 30, 2003, as compared with the same periods in 2002, due to the sale of Seabrook in November 2002.

Other depreciation and amortization expense for the quarter and six months ended September 30, 2003, increased by approximately $2 million and $4 million, respectively, compared with the same periods in 2002. The increases are primarily due to the scheduled recovery of generation-related stranded costs based upon annual filings. The increases were partially offset by reduced decommissioning expenses during the quarter and six months ended September 30, 2003, as compared with the same periods in 2002, due to the sale of Seabrook in November 2002.

Other income and expense for the quarter ended September 30, 2003, decreased approximately $1 million compared with the same period in 2002. The decrease is due primarily to reduced equity income earnings of nuclear power companies due to the sale of Vermont Yankee in July 2002. Partially offsetting the decrease was increased interest income from loans to affiliated companies during the six months ended September 30, 2003 as compared with the same period in 2002.

There are certain critical accounting policies that are based on assumption and conditions that if changed could have a material effect on the financial condition, results of operations and liquidity of the Company. (For a more detailed discussion of "Critical Accounting Policies" see "Liquidity and Capital Resources", in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's Annual Report on Form 10-K for the year ended March 31, 2003.)

At September 30, 2003 the Company's principal sources of liquidity included cash and cash equivalents of approximately $308 million and accounts receivable of $150 million. The Company has a working capital balance of approximately $302 million.

Net cash flows provided by operating activities for the six months ended September 30, 2003, was approximately $79 million.

Net cash flows used in investing activities for the six months ended September 30, 2003, increased approximately $4 million compared with same period in 2002, primarily due to increased plant expenditures.

At September 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 September 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 September 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 $19 million for the six months ended September 30, 2003, and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

The Company's total capital requirements consist of amounts for its maturing debt issues, purchased power commitments and operating leases. (For a more detailed discussion of "Capital requirements" see "Liquidity and Capital Resources", in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's Annual Report on Form 10-K for the year ended March 31, 2003.)

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 September, 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 six months ended September 30, 2003, was approximately 1.08 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.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended September 30, 2003 to be signed on its behalf by the undersigned thereunto duly authorized.