National Grid 20F 2008 Annual report | NGG Filing

EXHIBIT 2(b).6.1

PROSPECTUS

National Grid USA

(incorporated in the State of Delaware, United States of America)

Euro 4,000,000,000
Euro Medium Term Note Programme

Under the Euro Medium Term Note Programme (the “Programme”) described in this prospectus (the “Prospectus”), National Grid USA (the “Issuer”), subject to compliance with all relevant laws, regulations and directives, may from time to time issue debt instruments (the “Instruments”) denominated in any currency agreed between the Issuer, the Trustee and the relevant Dealer (as defined below). The aggregate nominal amount of Instruments outstanding will not at any time exceed Euro 4,000,000,000 (or its equivalent in other currencies). The Instruments will only be issued in bearer form.

Application has been made to the Financial Services Authority in its capacity as competent authority (the “U.K. Listing Authority”) under the Financial Services and Markets Act 2000 (“FSMA”) for Instruments issued under the Programme for the period of 12 months from the date of this Prospectus to be admitted to the official list of the U.K. Listing Authority (the “Official List”) and to the London Stock Exchange plc (the “London Stock Exchange”) for such Instruments to be admitted to trading on the London Stock Exchange’s Gilt-Edged and Fixed Interest Market (the “Market”). References in this Prospectus to Instruments being “listed” (and all related references) shall mean that such Instruments have been admitted to trading on the Market and have been admitted to the Official List. The Market is a regulated market for the purposes of the Directive 2004/39/EC of the European Parliament and of the Council on markets in financial instruments.. The Programme also permits Instruments to be issued on an unlisted basis or to be admitted to listing, trading and/or quotation by such other or further listing authorities, stock exchanges and/or quotation systems as may be agreed with the Issuer. The relevant Final Terms (as defined on page 6) in respect of the issue of any Instruments will specify whether or not such Instruments will be listed on the Official List and admitted to trading on the Market (or any other listing authority, stock exchange and/or quotation system).

The Instruments have not been and will not be registered under the United States Securities Act of 1933 (the “Securities Act”), and will be issued in bearer form. The Instruments are subject to U.S. tax law requirements and may not be offered, sold or delivered within the United States or to, or for the account or benefit of, U.S. persons (as defined in Regulation S of the Securities Act and the United States Internal Revenue Code of 1986, as amended, and regulations thereunder) except pursuant to an exemption from, or in a transaction not subject to, registration under the Securities Act. For a description of certain restrictions on offers and sales of Instruments and on distribution of this Prospectus or any Final Terms, see “Plan of Distribution”.

Each Series (as defined on page 6) of Instruments will be represented by a temporary global instrument in bearer form (each a “temporary Global Instrument”) or a permanent global instrument (each a “permanent Global Instrument”, and together with the temporary Global Instrument, the “Global Instruments”). If the Global Instruments are stated in the applicable Final Terms to be issued in new global note (“NGN”) form they may be eligible collateral for Eurosystem monetary policy and the Global Instruments will be delivered on or prior to the original issue date of the relevant Tranche to a common safekeeper (the “Common Safekeeper”) for Euroclear Bank S.A./N.V. (“Euroclear”) and Clearstream Banking,société anonyme(“Clearstream, Luxembourg”) (the “Common Depositary”). Global Instruments which are not issued in NGN form (“Classic Global Notes” or “CGNs”) will be deposited on the issue date of the relevant Tranche with a common depositary on behalf of Euroclear and Clearstream, Luxembourg. Beneficial interests in a temporary Global Instrument will be exchangeable for either (i) a permanent Global Instrument or (ii) Definitive Instruments (as defined on page 47), in each case not earlier than 40 days after the issue date upon certification of non-U.S. beneficial ownership. The provisions governing the exchange of interests in any Global Instrument for interests in any other Global Instrument and Definitive Instruments are described in “Summary of Provisions Relating to the Instruments while in Global Form”.

Tranches of Instruments (as defined in “Overview of the Programme”) may be rated or unrated. Where a Tranche of Instruments is rated, such rating will be specified in the relevant Final Terms. A rating is not a recommendation to buy, sell or hold securities and may be subject to suspension, reduction or withdrawal at any time by the assigning rating agency.

In the case of any Instruments which are to be admitted to trading on a regulated market within the European Economic Area or offered to the public in a Member State of the European Economic Area in circumstances which require the publication of a prospectus under the relevant Directive 2003/71/EC (the “Prospectus Directive”), the minimum denomination shall be€50,000 (or its equivalent in any other currency as at the date of issue of the relevant Instruments).

An investment in Instruments issued under the Programme involves certain risks. For a discussion of such risks, see the section headed “Risk Factors” in this Prospectus.

Programme Arranger and Dealer

HSBC

The date of this Prospectus is 3 December 2007

IMPORTANT NOTICES

This Prospectus comprises a base prospectus (the “Base Prospectus”) for the purposes of Article 5.4 of the Prospectus Directive and relevant implementing measures in the United Kingdom and for the purpose of giving information with regard to the Issuer and each of its subsidiaries (together, the “Group”) and the Instruments which, according to the particular nature of the Issuer and the Instruments to be issued by it, is necessary to enable investors to make an informed assessment of the assets and liabilities, financial position, profit and losses and prospects of the Issuer and the rights attaching to such Instruments.

The Issuer accepts responsibility for the information contained in this Prospectus. To the best of the knowledge of the Issuer (having taken all reasonable care to ensure that such is the case) such information contained in this Prospectus is in accordance with the facts and does not omit anything likely to affect the import of such information.

This Prospectus should be read and construed together with any amendments or supplements hereto and, in relation to any Tranche (as defined herein) of Instruments, should be read and construed together with the applicable Final Terms (as defined herein).

No person has been authorised to give any information or to make any representation other than as contained in this Prospectus in connection with the issue or sale of the Instruments and, if given or made, any such information or representation must not be relied upon as having been authorised by the Issuer or any of the Dealers or the Arranger (as defined in “Overview of the Programme”).

Neither the delivery of this Prospectus or any Final Terms nor the offering, sale or delivery of any Instrument shall, under any circumstances, create any implication that the information contained in this Prospectus is true subsequent to the date hereof, that there has been no change (or any event reasonably likely to involve a change) in the affairs of the Issuer since the date of this Prospectus or the date upon which this Prospectus has been most recently amended or supplemented or that there has been no adverse change (or any event reasonably likely to involve any adverse change) in the financial position of the Issuer since the date of this Prospectus or the date upon which this Prospectus has been most recently amended or supplemented or that any other information supplied in connection with the Programme is correct as of any time subsequent to the date on which it is supplied or, if different, the date indicated in the document containing the same.

The distribution of this Prospectus and the offering, distribution or sale of the Instruments in certain jurisdictions may be restricted by law. Persons into whose possession this Prospectus or any Final Terms comes are required by the Issuer, the Dealers and the Arranger to inform themselves about and to observe any such restriction.

Neither this Prospectus nor any Final Terms constitutes an offer of, or an invitation by or on behalf of the Issuer or the Dealers to subscribe for, or purchase, any Instruments.

None of the Dealers, the Arranger or the Trustee have independently verified the information contained in this Prospectus. None of the Dealers, the Arranger or the Trustee makes any representation, express or implied, or accepts any responsibility, with respect to the accuracy or completeness of any of the information in this Prospectus. Neither this Prospectus nor any other financial statement is intended to provide the basis of any credit or other evaluation and should not be considered as a recommendation by the Issuer, the Trustee, the Arranger or the Dealers that any recipient of this Prospectus or any other financial statements should purchase the Instruments. Each potential purchaser of Instruments should determine for itself the relevance of the information contained in this Prospectus and its purchase of Instruments should be based upon such investigation as it deems necessary. None of the Dealers, the Arranger or the Trustee undertakes to review the financial condition or affairs of the Issuer during the life of the arrangements contemplated by this Prospectus or to advise any investor or potential investor in the Instruments of any information coming to the attention of any of the Dealers, the Arranger or the Trustee.

In this Prospectus, unless otherwise specified or the context otherwise requires, references to “Euro” are to the currency of those member states of the European Union which are participating in European Economic and Monetary Union pursuant to the Treaty establishing the European Community, as amended, to “Japanese yen” are to the lawful currency of Japan, to “£” and “Sterling” are to the lawful currency of the United Kingdom, to “U.S. dollars” and “U.S.$” are to the lawful currency of the United States of America, to “Canadian dollars” are to the lawful currency of Canada, to “Australian dollars” are to the lawful currency of Australia, to “New Zealand dollars” are to the lawful currency of New Zealand, to “Swedish krona” are to the lawful currency of Sweden, to “Danish krone” are to the lawful currency of Denmark, to “Hong Kong dollars” are to the lawful currency of Hong Kong and to “Swiss francs” are to the lawful currency of Switzerland.

In connection with the issue of any Tranche (as defined in “Overview of the Programme - Method of Issue”), the Dealer or Dealers (if any) named as the stabilising manager(s) (the “Stabilising Manager(s)”) in the applicable Final Terms (or any person acting on behalf of any Stabilising Manager(s)) may over-allot Instruments or effect transactions with a view to supporting the market price of the Instruments at a level higher than that which might otherwise prevail. However, there is no assurance that the Stabilising Manager(s) (or any person acting on behalf of any Stabilising Manager) will undertake stabilisation action. Any stabilisation action may begin on or after the date on which adequate public disclosure of the final terms of the offer of the relevant Tranche is made and, if begun, may be ended at any time, but it must end no later than the earlier of 30 days after the issue date of the relevant Tranche and 60 days after the date of the allotment of the relevant Tranche. Any stabilisation action or over-allotment must be conducted by the relevant Stabilising Manager(s) or person(s) acting on behalf of any Stabilising Manager(s) in accordance with all applicable laws and rules.

TABLE OF CONTENTS


	Page
IMPORTANT NOTICES		2
SUPPLEMENTAL PROSPECTUS		5
OVERVIEW OF THE PROGRAMME		6
RISK FACTORS		12
TERMS AND CONDITIONS OF THE INSTRUMENTS		23
SUMMARY OF PROVISIONS RELATING TO THE INSTRUMENTS WHILE IN GLOBAL FORM		45
USE OF PROCEEDS		50
DESCRIPTION OF NATIONAL GRID USA		51
TAXATION		68
PLAN OF DISTRIBUTION		71
FORM OF FINAL TERMS		74
GENERAL INFORMATION		84
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

SUPPLEMENTAL PROSPECTUS

If at any time the Issuer shall be required to prepare a supplemental prospectus pursuant to Section 87G of FSMA (“Supplemental Prospectus”), the Issuer will prepare and make available to the public an appropriate amendment or supplement to this Prospectus or a further prospectus which, in respect of any subsequent issue of Instruments to be listed on the Official List and admitted to trading on the Market, shall constitute a Supplemental Prospectus as required by the U.K. Listing Authority and Section 87G of FSMA.

OVERVIEW OF THE PROGRAMME

The following overview is qualified in its entirety by the remainder of this Prospectus.


Issuer		National Grid USA

Description		Euro Medium Term Note Programme

Size		Up to Euro 4,000,000,000 (or its equivalent in other currencies at the date of issue) aggregate nominal amount of Instruments outstanding at any one time.

Arranger		HSBC Bank plc

Dealer		HSBC Bank plc

		The Issuer may from time to time terminate the appointment of any dealer under the Programme or appoint additional dealers either in respect of one or more Tranches or in respect of the whole Programme. References in this Prospectus to the “Permanent Dealers” are to the person listed above as Dealer and to such additional persons that are appointed as dealers in respect of the whole Programme (and whose appointment has not been terminated) and to “Dealers” are to all Permanent Dealers and all persons appointed as a dealer in respect of one or more Tranches.

Trustee		The Law Debenture Trust Corporation p.l.c.

Issuing and Paying Agent		The Bank of New York

Other Paying Agent		Kredietbank S.A. Luxembourgeoise

Method of Issue		The Instruments will be issued on a syndicated or non-syndicated basis. The Instruments will be issued in series (each a “Series”) having one or more issue dates and on terms otherwise identical (or identical other than in respect of the first payment of interest), the Instruments of each Series being intended to be interchangeable with all other Instruments of that Series. Each Series may be issued in tranches (each a “Tranche”) on the same or different issue dates. The specific terms of each Tranche (which will be completed, where necessary, with supplemental terms and conditions and, save in respect of the issue date, issue price, first payment of interest and nominal amount of the Tranche, will be identical to the terms of other Tranches of the same Series) will be completed in the final terms document (the “Final Terms”).

Issue Price		Instruments may be issued at their nominal amount or at a discount or premium to their nominal amount. Partly Paid Instruments may be issued, the issue price of which will be payable in two or more instalments.

Form of Instruments		The Instruments may be issued in bearer form only. Each Tranche of Instruments will be represented on issue by a temporary Global Instrument. The Temporary Global Instrument may be deposited on the relevant issue date with


		a common depositary for Euroclear and Clearstream, Luxembourg and/or any other agreed clearance system. Temporary Global Instruments will be exchangeable, only in the manner and upon compliance with the procedures described herein, (i) for permanent Global Instruments or (ii) for Definitive Instruments, in each case not earlier than 40 days after the issue date, upon certification of non-U.S. beneficial ownership. No interest will be payable in respect of a temporary Global Instrument except as described under “Summary of Provisions Relating to the Instruments while in Global Form”. Any permanent Global Instrument shall only be exchanged for Instruments in definitive form in the limited circumstances set out in the permanent Global Instrument.

Clearing Systems		Clearstream, Luxembourg, Euroclear and, in relation to any Tranche, such other clearing system as may be agreed between the Issuer, the Issuing and Paying Agent, the Trustee and the relevant Dealer.

Initial Delivery of Instruments		On or before the issue date for each Tranche, if the relevant Global Instrument is intended to be eligible collateral for Eurosystem monetary policy and intra-day credit operations, the Global Instrument will be delivered to a Common Safekeeper for Euroclear and Clearstream, Luxembourg. On or before the issue date for each Tranche, if the relevant Global Instrument is not intended to be eligible collateral for Eurosystem monetary policy and intra-day credit operations, the Global Instrument representing the relevant Instruments may be deposited with a common depositary for Euroclear and Clearstream, Luxembourg. Global Instruments may also be deposited with any other clearing system or may be delivered outside any clearing system provided that the method of such delivery has been agreed in advance by the Issuer, the Issuing and Paying Agent, the Trustee and the relevant Dealer.

Currencies		Subject to compliance with all relevant laws, regulations and directives, Instruments may be issued in Euro, Japanese yen, Sterling, U.S. dollars, Canadian dollars, Australian dollars, New Zealand dollars, Swedish krona, Danish krone, Hong Kong dollars or Swiss francs or in other currencies if the Issuer and the relevant Dealer(s) so agree. Instruments may, subject to compliance as above, be issued as Dual Currency Instruments.

Maturities		Subject to compliance with all relevant laws, regulations and directives, any maturity from one month to perpetuity.

		Any Instruments having a maturity of less than one year from their date of issue must (a) have a minimum redemption value of £100,000 (or its equivalent in other currencies) and be issued only to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their


		businesses or who it is reasonable to expect will acquire, hold, manage or dispose of investments (as principal or agent) for the purposes of their businesses or (b) be issued in other circumstances which do not constitute a contravention of Section 19 of FSMA by the Issuer.

Denominations		Definitive Instruments will be in such denominations as may be specified in the relevant Final Terms, save that (i) in the case of any Instruments which are to be admitted to trading on a regulated market within the European Economic Area or offered to the public in a Member State of the European Economic Area in circumstances which require the publication of a prospectus under the Prospectus Directive, the minimum denomination shall be€50,000 (or its equivalent in any other currency as at the date of issue of the Instruments); and (ii) unless otherwise permitted by then current laws and regulations, Instruments which have a maturity of less than one year will have a minimum denomination of £100,000 (or its equivalent in other currencies).

Fixed Rate Instruments		Fixed interest will be payable in arrear on the date or dates in each year specified in the relevant Final Terms and at maturity.

Floating Rate Instruments		Floating Rate Instruments will bear interest set separately for each Series as follows:

		(a) on the same basis as the floating rate under a notional interest rate swap transaction in the relevant Specified Currency governed by an agreement incorporating the 2006 ISDA Definitions published by the International Swaps and Derivatives Association, Inc. or

		(b) by reference to LIBOR, LIBID, LIMEAN or EURIBOR (or such other benchmark as may be specified in the relevant Final Terms) as adjusted for any applicable margin. Interest periods will be selected by the Issuer prior to issue and specified in the relevant Final Terms. Floating Rate Instruments may also have a maximum interest rate, a minimum interest rate, or both.

Zero Coupon Instruments		Zero Coupon Instruments may be issued at their nominal amount or at a discount to it and will not bear interest.

Dual Currency Instruments		Payments (whether in respect of principal or interest and whether at maturity or otherwise) in respect of Dual Currency Instruments will be made in such currencies, and based on such rates of exchange as may be specified in the relevant Final Terms.

Interest Periods and Rates of Interest		The length of the interest periods for the Instruments and the applicable interest rate or its method of calculation may differ from time to time or be constant for any Series. Instruments may have a maximum interest rate, a minimum interest rate, or both. The use of interest accrual periods permits the


		Instruments to bear interest at different rates in the same interest period. All such information will be set out in the relevant Final Terms.

Redemption		The relevant Final Terms will specify the basis for calculating the redemption amounts payable, which may be by reference to a formula or as otherwise provided in the relevant Final Terms.

		Unless permitted by then current laws and regulations, Instruments which have a maturity of less than one year must have a minimum redemption amount of £100,000 (or its equivalent in other currencies).

Redemption by Instalments		The Final Terms issued in respect of each issue of Instruments that are redeemable in two or more instalments will set out the dates on which, and the amounts in which, such Instruments may be redeemed.

Other Instruments		Terms applicable to high interest Instruments, low interest Instruments, step-up Instruments, step-down Instruments, Dual Currency Instruments, reverse Dual Currency Instruments, optional Dual Currency Instruments, Partly-Paid Instruments and any other type of Instrument that the Issuer, the Trustee and any Dealer(s) may agree to issue under the Programme, subject to compliance with all relevant laws, regulations and directives, will be set out in the relevant Final Terms and (if applicable) the relevant Supplemental Prospectus.

Optional Redemption		The Final Terms issued in respect of each issue of Instruments will state whether such Instruments may be redeemed prior to their stated maturity at the option of the Issuer (either in whole or in part) and/or the Instrumentholders, and if so the terms applicable to such redemption.

		The Issuer may elect to redeem all, but not some only, of the Instruments of any Series at their Residual Holding Redemption Amount at any time if the Residual Holding Percentage or more of the aggregate nominal amount of such Instruments originally issued shall have been redeemed or purchased and cancelled.

Status of Instruments		The Instruments will constitute unsubordinated and unsecured obligations of the Issuer, all as described in “Terms and Conditions of the Instruments — Status”.

Negative Pledge		The Instruments will have the benefit of a negative pledge as described in “Terms and Conditions of the Instruments — Status and Negative Pledge”.

Cross Acceleration		The Instruments will have the benefit of a cross acceleration provision as described in “Terms and Conditions of the Instruments — Events of Default”.

Other Events of Default		The other events of default under the Instruments are as specified below under “Terms and Conditions of the


		Instruments — Events of Default”.

Early Redemption		Except as provided in “Optional Redemption” and “Redemption” above, Instruments will be redeemable at the option of the Issuer prior to maturity only for tax reasons. See “Terms and Conditions of the Instruments — Redemption, Purchase and Options”.

Withholding Tax		All payments of principal and interest in respect of the Instruments, Receipts and Coupons will be made free and clear of withholding taxes of the United States of America or any political sub-division of the United States of America or any authority in or of the United States of America having power to tax, unless compelled by law. In that event, the Issuer will, subject to customary exceptions (including the standard EU exceptions), pay such additional amounts as will result in the payment to the Instrumentholders, Receiptholders or Couponholders of the amounts which would otherwise have been received in respect of the Instruments, Receipts and Coupons had no withholding or deduction been made, all as described in “Terms and Conditions of the Instruments — Taxation”.

Governing Law		English

Listing		Each Series may be admitted to the Official List and admitted to trading on the Market and/or admitted to listing, trading and/or quotation by any other listing authority, stock exchange and/or quotation system as may be agreed between the Issuer and the relevant Dealer(s) and specified in the relevant Final Terms or may be unlisted.

Ratings		Tranches of Instruments (as defined in “Overview of the Programme”) may be rated or unrated. Where a Tranche of Instruments is rated, such rating will be specified in the relevant Final Terms. A rating is not a recommendation to buy, sell or hold securities and may be subject to suspension, reduction or withdrawal at any time by the assigning rating agency.

Selling Restrictions		United States, United Kingdom, European Economic Area (in the case of unlisted Instruments) and Japan. See “Plan of Distribution”.

		Category 3 selling restrictions will apply to the Instruments for the purposes of Regulation S under the Securities Act.

		The Instruments will be issued in compliance with U.S. Treas. Reg. §1.163-5(c)(2)(i)(D) (the “D Rules”) unless the Instruments are issued other than in compliance with the D Rules but in circumstances in which the Instruments will not constitute “registration required obligations” under the United States Tax Equity and Fiscal Responsibility Act of 1982 (“TEFRA”), which circumstances will be referred to in the relevant Final Terms as a transaction to which TEFRA is not applicable.


Terms and Conditions		The Terms and Conditions applicable to each Series will be as agreed between the Issuer, the Trustee and the relevant Dealer(s) or other subscriber at or prior to the time of issuance of such Series and will be specified in the relevant Final Terms. The Terms and Conditions applicable to each Series will therefore be those as set out in “Terms and Conditions of the Instruments” below as supplemented, modified or replaced by the relevant Final Terms.

RISK FACTORS

The Issuer believes that the following factors may affect its ability to fulfil its obligations under Instruments issued under the Programme. All of these factors are contingencies which may or may not occur and the Issuer is not in a position to express a view on the likelihood of any such contingency occurring.

Factors which the Issuer believes may be material for the purpose of assessing the market risks associated with Instruments issued under the Programme are also described below.

The Issuer believes that the factors described below represent the principal risks inherent in investing in Instruments issued under the Programme, but the Issuer may be unable to pay interest, principal or other amounts on or in connection with any Instruments for other reasons. If this occurs, prospective investors may lose the value of their entire investment or part of it. Prospective investors should read the detailed information set out elsewhere in this Prospectus and reach their own views prior to making any investment decision.

Factors that may affect the Issuer’s ability to fulfil its obligations under Instruments issued under the Programme

Risks relating to the Issuer and its businesses

Holding company status and changes in law or regulation in the geographies in which the Group operates could have an adverse effect on its results of operations.

The Issuer is a holding company with no business operations of its own and depends on the earnings and cash flow of, and dividends or distributions from, its subsidiaries. The Issuer conducts all of its businesses through its subsidiaries. Each of the Issuer’s public utility subsidiaries are subject to various dividend restrictions contained in federal and state regulatory approvals, financing instruments and organisational documents which, under certain circumstances, may limit the ability of these subsidiaries to pay dividends; none of these subsidiaries are currently prohibited from paying a dividend. Many of the Issuer’s businesses are utilities that are subject to regulation by governments and other authorities; these businesses’ legal authority to pay dividends or make other distributions to the Issuer is subject to regulation by the utility regulatory commissions of the states in which it operates. A significant portion of the Group’s revenues in its utility businesses is directly dependent on rates established by federal or state regulatory authorities, and any change in these rates and regulatory structure could significantly impact the Group’s financial results. Increases in utility costs, not otherwise offset by increases in revenues or reductions in other expenses, could have an adverse effect on earnings due to the time lag associated with obtaining regulatory approval to recover such increased costs and expenses in rates. Changes in federal law, or in state or local law in the jurisdictions in which the Group operates, could adversely affect it. Regulatory decisions concerning, for example, whether licences or approvals to operate are granted or are renewed, whether there has been any breach of the terms of a licence or approval, the level of permitted revenues for the Group’s businesses and proposed business development activities could have an adverse impact on its results of operations, cash flows, the financial condition of its businesses and the ability to develop those businesses in the future.

Breaches of, or changes in, environmental or health and safety laws or regulations could expose the Group to claims for financial compensation and adverse regulatory consequences, as well as damaging the reputation of the Group.

Aspects of the Group’s activities are potentially dangerous, such as the operation and maintenance of electric generation facilities, electricity lines and the transmission and distribution of gas. Electricity and gas utilities also typically use and generate in their operations hazardous and potentially hazardous products and by-products. In addition, there may be other aspects of the Group’s operations that are not

currently regarded or proved to have adverse effects but could become so; for example, the effects of electric and magnetic fields. The Group’s operations are subject to extensive federal, state and local laws and regulations relating to pollution, the protection of the environment, and how the Group uses and disposes of hazardous substances and waste materials. The Group is also subject to laws and regulations governing health and safety matters protecting the public and its employees. These environmental laws and regulations expose the Group to costs and liabilities relating to its operations and its current and formerly owned properties. Compliance with these legal requirements requires the Group to commit significant capital toward environmental monitoring, installation of pollution control equipment and permits at the Group’s facilities. Costs of compliance with these laws and regulations could have a material impact on the Group’s businesses and its results of operations and financial position, especially if these laws or regulations are modified to impose additional or more extensive requirements or the number and type of facilities that the Group operates increases. Any breach of these obligations, or even incidents that do not amount to a breach, could adversely affect the Group’s results of operations and its reputation.

In addition, a number of the Issuer’s businesses are responsible for the clean-up of contamination at certain manufactured gas plant (“MGP”) sites and at other sites and the Issuer is aware of additional MGP sites where it may have responsibility for clean-up costs. While some of the Issuer’s subsidiaries have rate plans generally allowing for recovery of the costs of investigation and remediation of MGP sites, these rate recovery mechanisms may change in the future. To the extent rate recovery mechanisms change in the future, or if additional environmental matters arise in the future at the Group’s currently or historically owned facilities, at sites the Group may acquire in the future or at third-party waste disposal sites, costs associated with investigating and remedying these sites could have a material adverse effect on the Group’s results of operations, cash flows and financial condition.

Network failure or the inability to carry out critical non-network operations may have significant adverse impacts on both the Group’s financial position and its reputation.

The Group may suffer a major network failure or may not be able to carry out critical non-network operations. Operational performance could be adversely affected by a failure to maintain the health of the system or network, inadequate forecasting of demand or inadequate record keeping. This could cause the Group to fail to meet agreed standards of service or to be in breach of a licence or approval, and even incidents that do not amount to a breach could result in adverse regulatory and financial consequences, as well as harming the Group’s reputation. In addition to these risks, the Group may be affected by other potential events that are largely outside the Group’s control such as the impact of weather or unlawful acts of third parties. Weather conditions can affect financial performance and severe weather that causes outages or damages infrastructure will adversely affect operational and potentially business performance. Terrorist attack, sabotage or other intentional acts may also physically damage the Group’s businesses or otherwise significantly affect corporate activities and as a consequence have an adverse impact on the results of operations. The cost of repairing damage to the Issuer’s operating subsidiaries’ facilities and the potential disruption of their operations or supplier operations due to storms, natural disasters, wars, terrorist acts and other catastrophic events could be substantial. The occurrence or risk of occurrence of future terrorist attacks or related acts of war or violence may lead to increased political, economic and financial market instability and volatility in prices which could materially adversely affect the Group in ways it cannot predict at this time. A lower level of economic activity for these or other reasons could result in a decline in energy consumption, which could adversely affect the Group’s net revenues.

The Group’s results of operations depend on a number of factors relating to business performance including performance against regulatory targets, recovery of incurred expenditure and the delivery of anticipated cost and efficiency savings.

Earnings maintenance and growth from the Group’s regulated gas and electricity businesses will be affected by its ability to meet or better efficiency targets set by or agreed with regulators, including, but

not limited to, the levels of synergy and efficiency savings contemplated in connection with the Group’s recent acquisition of KeySpan Corporation (“KeySpan”). Under the Group’s state rate plans, earnings from its regulated businesses will be affected by its ability to deliver integration and efficiency savings. Earnings from the Group’s regulated businesses will be affected by its ability to recover incurred expenditure. Levels of earnings also depend on meeting service quality standards set by regulators. In addition, from time to time, the Group publishes cost and efficiency savings targets for its businesses. The Group has also substantially completed reorganising its operations along lines of business. To meet these targets and standards, the Group must continue to improve operational performance, service reliability and customer service. If the Group does not meet these targets and standards, it is not able to recover incurred expenditure or it does not complete implementation of this reorganisation as envisaged, the Group may not achieve the expected benefits, its business may be adversely affected and its performance, results of operations and its reputation may be harmed.

Business development activity risks.

Business development activities, including acquisitions and disposals, may be based on incorrect assumptions or conclusions; significant liabilities may be overlooked or there may be other unanticipated or unintended effects. The Group has recently completed the acquisition of KeySpan and plans to achieve certain levels of synergy and efficiency savings from this acquisition, but these may not subsequently be achievable. The risks and uncertainties to which KeySpan’s operations are subject have been assumed by the Group. Many of these risks and uncertainties are similar to those that are faced by the Group’s pre-existing businesses; however, there are some that are not, including, without limitation, risks related to KeySpan’s Ravenswood Generating Station.

The Group’s risk mitigation techniques such as hedging and current regulatory arrangements may not adequately provide protection.

Changes in commodity prices could potentially impact the Group’s energy delivery businesses. To mitigate the Group’s financial exposure related to commodity price fluctuations, the Group’s energy delivery businesses routinely enter into contracts to hedge a portion of its purchase and sale commitments, weather fluctuations, electricity sales, gas supply and other commodities. In addition, current regulatory arrangements provide the ability to pass through virtually all of the increased costs related to commodity prices to consumers. However, if the Group’s regulators were to restrict this ability, it could have an adverse effect on the Group’s operating results. Moreover, the Group does not always cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent the Group has unhedged positions or its hedging strategies do not work as planned, fluctuating commodity prices could cause the Group’s sales and net income to be volatile.

The Group’s reputation and long-term financial condition may be harmed if consumers of energy suffer a disruption to their supply even if this disruption is outside the Group’s control.

The Group’s energy delivery businesses are responsible for transporting available electricity and gas. The development of additional gas reserves requires significant capital expenditure by others for exploring, drilling and installing production, gathering, storage, transportation and other facilities that permit gas to be produced and delivered to the Group’s distribution systems. Low prices for gas, regulatory restrictions, or the lack of available capital for these projects could adversely affect the development of additional gas reserves. Additional gas reserves may not be developed in sufficient amounts to fill the capacities of the Group’s distribution systems, thus limiting the Group’s prospects for long-term growth. Such supply issues could hinder the Group’s ability to successfully contract for gas and electricity supplies required to meet the needs of its customers. In addition, the Group consults with and provides information to regulators, governments and industry participants about future demand and the availability of supply. However, where there is insufficient supply, the Group’s role is to manage the relevant network safely, which in extreme circumstances may require the Group to disconnect consumers.

The Group’s financial position may be adversely affected by a number of factors including restrictions in borrowing and debt arrangements, changes to credit ratings or outlook and effective tax rates.

The Group is subject to certain covenants and restrictions in relation to its debt securities and its bank lending facilities. The Group is also subject to restrictions on financing that have been imposed by regulators. These restrictions may hinder it in servicing the financial requirements of its current businesses or the financing of newly acquired or developing businesses. For the portion of the Group’s debt that is rated by credit rating agencies, it can provide no assurances that the ratings or outlook on its debt securities will not be reduced or otherwise negatively changed. Changes to these ratings or outlook may affect both the Group’s borrowing capacity and the cost of those borrowings. The effective rate of tax the Group pays may be influenced by a number of factors including changes in law and accounting standards, the results of which could increase that rate.

Future funding requirements of Issuer’s pension plans could adversely affect the results of operations of the Issuer.

The Issuer participates in a number of pension plans that together cover substantially all of the Issuer’s subsidiaries’ employees. The principal plans are defined benefit plans where the program assets are held independently of the Issuer’s own financial resources. Estimates of the amount and timing of future funding for these plans are based on various actuarial assumptions and other factors including, among other things, the actual and projected market performance of the plan assets, future long-term bond yields, average life expectancies and relevant legal requirements. The impact of these assumptions and other factors may require the Issuer to make additional contributions to these pension plans which, to the extent they are not recoverable (under applicable state rate plans, for example) could adversely affect the results of operations of the Issuer.

New or revised accounting standards, rules and interpretations.

The implementation of new accounting standards or changes in accounting standards or Generally Accepted Accounting Principles which may require adjustments to financial statements, could have significant adverse effects on the Issuer’s reported financial results.

The Group’s operating results may fluctuate on a seasonal and quarterly basis.

The Group’s electric and gas businesses are seasonal businesses and are subject to weather conditions. The Group receives most of its gas distribution revenues in the third and fourth quarters, when demand for gas increases due to colder weather conditions. As a result, the Group is subject to seasonal variations in working capital because it purchases gas supplies for storage in the first and second quarters and must finance these purchases. Accordingly, the Group’s results of operations for its gas distribution business fluctuate substantially on a seasonal basis. In addition, portions of the Group’s electric businesses are seasonal and subject to weather and market conditions. Sales of electricity to customers are influenced by temperature changes. Significant changes in heating or cooling degree days, for example, could have a substantial effect. As a result, fluctuations in weather and competitive supply between years may have a significant effect on the Group’s results of operations for these businesses; both gas and electric.

Customers and counterparties to the Group’s transactions may fail to perform their obligations, which could harm the Group’s results of operations.

The Group’s operations are exposed to the risk that customers and counterparties to the Group’s transactions that owe it money or supplies will not perform their obligations. The Issuer’s KeySpan businesses, for example, derive a substantial portion of revenues in the electric services segment from two customers: the Long Island Power Authority (“LIPA”) and the New York Independent System Operator (“NYISO”). The Issuer’s KeySpan businesses manage LIPA’s transmission and distribution system and supply the majority of LIPA’s customers’ electricity needs pursuant to a series of agreements with LIPA; the Issuer also sells the capacity, energy and ancillary services from its Ravenswood

Generating Station facility into the NYISO. Should the counterparties to arrangements with the Issuer fail to perform, the Issuer might be forced to enter into alternative hedging arrangements or honour its underlying commitment at then-current market prices that may exceed the Issuer’s contractual prices. In such event, the Issuer might incur additional losses to the extent of amounts, if any, already paid to counterparties. This risk is most significant where the Issuer’s subsidiaries have concentrations of receivables from gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout the north-east of the United States.

A substantial portion of revenues are derived from agreements with LIPA and no assurances can be made that these arrangements will not be discontinued at some point in the future.

A substantial portion of the Issuer’s KeySpan affiliate’s revenues in its electric services segment are derived from a series of agreements with LIPA pursuant to which the Issuer manages LIPA’s transmission and distribution system and supply the majority of LIPA’s customers’ electricity needs. These operating agreements provide LIPA with the right to terminate the agreements upon the occurrence of certain events of default, which may result from the change of control of KeySpan, poor performance under the performance metrics under an amended and restated Management Services Agreement (the “2006 MSA”) or the Department of Justice’s investigation into competitive issues in the New York City electric capacity market which results in a finding triggering an event of default as described below.

On 19 July 2007, LIPA signed an agreement addressing KeySpan’s receipt of a Civil Investigative Demand (“CID”) for the United States Department of Justice, Antitrust Division (“DOJ”) regarding the DOJ’s investigation into competitive issues in the New York City electric capacity market. This agreement amends an existing agreement to add an additional event of default, such that LIPA will have the contractual right to terminate such agreement if, in connection with the DOJ’s investigation referenced in the CID, (a) there is a finding (through either a final, non-appealable judgment by a court of competent jurisdiction or final consent decree with the DOJ) that KeySpan or any of its affiliates violated Section 1 or 2 of the Sherman Antitrust Act of 1890 and (b) pursuant to which KeySpan or any of its affiliates is assessed or has agreed to be assessed a monetary or criminal penalty or sanction or is the subject of injunctive relief.

Ravenswood Generating Station.

The Issuer has announced that it will be moving expeditiously to divest the Ravenswood Generating Station (a number of generators totalling approximately 2,450 MW). Divestiture of the Ravenswood Generating Station within three years (with a possible one year extension) is a condition of the New York State Public Service Commission (“NYPSC”) order approving the acquisition of KeySpan (the “NYPSC Order”). The Issuer cannot predict the timing, terms, or outcome of this divestiture process or its impact on results. Until Ravenswood Generating Station is divested, the Issuer remains subject to risk factors related to the Station, such as:

	(i)		as a condition of the NYPSC Order, by 1 January 2008, 100 per cent. of the energy from the Ravenswood Generating Station must be sold via a short term energy agreement;

	(ii)		as a condition of the NYPSC Order, the capacity of the Ravenswood Generating Station must initially be bid at zero, commencing with the spot auction the NYISO holds for March 2008 capacity;

	(iii)		revisions to the NYISO market rules and Services Tariff;

	(iv)		the financial performance of the Ravenswood Generating Station is subject to competition and general economic conditions having an impact on supply and demand as well as other related risks;

	(v)		risks related to available sources and cost of fuel; and

(vi)

risks related to certain Federal Energy Regulatory Commission (“FERC”) proceedings concerning New York City’s In-City capacity market as explained below.

In addition, under the terms of the NYPSC Order, if the short term energy agreement is delayed Ravenswood Generating Station would be subject to cost-of-service revenue caps. If divestiture is not completed on time, the NYPSC has the right to consider all options, including cost-of-service revenue caps and the possible requirement that the Group pays U.S.$15 million per month into a fund for the benefit of certain affected electric customers.

Additional risks include, but are not limited to, the following:

	•		inflationary trends and increases in prevailing interest rates on the Group’s borrowings as well as general economic conditions, especially in the northeast United States;

	•		creditworthiness of counterparties to derivative instruments and commodity contracts;

	•		retention of key personnel and the Group’s ability to successfully negotiate extensions to collective bargaining agreements;

	•		potential write-down of the Group’s investment in gas properties when gas prices are depressed or if the Group has significant downward revisions in its estimated proved gas reserves;

	•		the degree to which the Group develops unregulated business ventures as well as federal and state regulatory policies affecting the ability of the Group to retain and operate such business ventures profitably;

	•		a change in the fair market value of the Group’s investments that could cause a significant change in the carrying value of such investments or the carrying value of related goodwill;

	•		the Group’s insurance not adequately providing coverage for certain hazards, such as unexpected outages at critical facilities, damage to pipelines, equipment, properties and people;

	•		material losses resulting from In-City Unforced Capacity prices being on average less than U.S.$7.57/kW-month in connection with the financial swap agreement for In-City Unforced Capacity;

	•		competition facing the Group’s unregulated energy services businesses as well as the Group’s gas distribution business; and

	•		other risks detailed from time to time in other reports and other documents filed by the Group or its affiliates with the SEC.

For additional background information related to these risk factors, see “Description of National Grid USA” contained herein.

Factors which are material for the purpose of assessing the market risks associated with Instruments issued under the Programme

Instruments may not be a suitable investment for all investors

Each potential investor in any Instruments must determine the suitability of that investment in light of its own circumstances. In particular, each potential investor should:

(i)

have sufficient knowledge and experience to make a meaningful evaluation of the relevant Instruments, the merits and risks of investing in the relevant Instruments and the information contained or incorporated by reference in this Prospectus or any applicable supplement;

	(ii)		have access to, and knowledge of, appropriate analytical tools to evaluate, in the context of its particular financial situation, an investment in the relevant Instruments and the impact such investment will have on its overall investment portfolio;

	(iii)		have sufficient financial resources and liquidity to bear all of the risks of an investment in the relevant Instruments, including where principal or interest is payable in one or more currencies, or where the currency for principal or interest payments is different from the potential investor’s currency;

	(iv)		understand thoroughly the terms of the relevant Instruments and be familiar with the behaviour of any relevant indices and financial markets; and

	(v)		be able to evaluate (either alone or with the help of a financial adviser) possible scenarios for economic, interest rate and other factors that may affect its investment and its ability to bear the applicable risks.

Certain Instruments may be complex financial instruments and such instruments may be purchased as a way to reduce risk or enhance yield with an understood, measured, appropriate addition of risk to their overall portfolios. A potential investor should not invest in Instruments which are complex financial instruments unless it has the expertise (either alone or with the help of a financial adviser) to evaluate how the Instruments will perform under changing conditions, the resulting effects on the value of such Instruments and the impact this investment will have on the potential investor’s overall investment portfolio.

Risks related to the structure of a particular issue of Instruments

A wide range of Instruments may be issued under the Programme. Certain of these Instruments may have features which contain particular risks for potential investors. Set out below is a description of certain such features:

Instruments subject to optional redemption by the Issuer

An optional redemption feature is likely to limit the market value of Instruments. During any period when the Issuer may elect to redeem Instruments, the market value of those Instruments generally will not rise substantially above the price at which they can be redeemed. This also may be true prior to any redemption period.

The Issuer may be expected to redeem Instruments when its cost of borrowing is lower than the interest rate on the Instruments. At those times, an investor generally would not be able to reinvest the redemption proceeds at an effective interest rate as high as the interest rate on the Instruments being redeemed and may only be able to do so at a significantly lower rate. Potential investors should consider reinvestment risk in light of other investments available at that time.

Dual Currency Instruments

The Issuer may issue Instruments with principal or interest payable in one or more currencies which may be different from the currency in which the Instruments are denominated. Potential investors should be aware that:

	(i)		the market price of such Instruments may be volatile;

	(ii)		they may receive no interest;

	(iii)		payment of principal or interest may occur at a different time or in a different currency than expected; and

	(iv)		the amount of principal payable at redemption may be less than the nominal amount of such Instruments or even zero;

Partly-paid Instruments

The Issuer may issue Instruments where the issue price is payable in more than one instalment. Failure to pay any subsequent instalment could result in an investor losing all of its investment.

Variable rate Instruments with a multiplier or other leverage factor

Instruments with variable interest rates can be volatile investments. If they are structured to include multipliers or other leverage factors, or caps or floors, or any combination of those features or other similar related features, their market values may be even more volatile than those for securities that do not include those features.

Fixed/Floating Rate Instruments

Fixed/Floating Rate Instruments may bear interest at a rate that the Issuer may elect to convert from a fixed rate to a floating rate, or from a floating rate to a fixed rate. The Issuer’s ability to convert the interest rate will affect the secondary market and the market value of such Instruments since the Issuer may be expected to convert the rate when it is likely to produce a lower overall cost of borrowing. If the Issuer converts from a fixed rate to a floating rate, the spread on the Fixed/Floating Rate Instruments may be less favourable than the prevailing spreads on comparable Floating Rate Instruments tied to the same reference rate. In addition, the new floating rate at any time may be lower than the rates on other Instruments. If the Issuer converts from a floating rate to a fixed rate, the fixed rate may be lower than the prevailing rates on its Instruments.

Instruments issued at a substantial discount or premium

The market values of securities issued at a substantial discount or premium to their nominal amount tend to fluctuate more in relation to general changes in interest rates than do prices for conventional interest-bearing securities. Generally, the longer the remaining term of the securities, the greater the price volatility as compared to conventional interest-bearing securities with comparable maturities.

Risks related to Instruments generally

Set out below is a brief description of certain risks relating to the Instruments generally:

Modification, waiver and substitution

The Terms and Conditions of the Instruments contain provisions for calling meetings of Instrumentholders to consider matters affecting their interests generally. These provisions permit defined majorities to bind all Instrumentholders including Instrumentholders who did not attend and vote at the relevant meeting and Instrumentholders who voted in a manner contrary to the majority.

The Terms and Conditions of the Instruments also provide that the Trustee may, without the consent of Instrumentholders, agree to (a) any modification of any of the provisions of the Trust Deed that is of a formal, minor or technical nature or is made to correct a manifest error, (b) any other modification (except as mentioned in the Trust Deed), and any waiver or authorisation of any breach or proposed breach, of any of the provisions of the Trust Deed that is in the opinion of the Trustee not materially prejudicial to the interests of the Instrumentholders or (c) the substitution of another company as principal debtor under any Instruments in place of the Issuer, in the circumstances described in Condition 10.

European Monetary Union

If the United Kingdom joins the European Monetary Union prior to the maturity of the Instruments, there is no assurance that this would not adversely affect investors in the Instruments. It is possible that prior to the maturity of the Instruments the United Kingdom may become a participating Member State and that the Euro may become the lawful currency of the United Kingdom. In that event (i) all amounts payable in respect of any Instruments denominated in Sterling may become payable in Euro (ii) the law may allow or require such Instruments to be re-denominated into Euro and additional measures to be taken in respect of such Instruments; and (iii) there may no longer be available published or displayed rates for deposits in Sterling used to determine the rates of interest on such Instruments or changes in

the way those rates are calculated, quoted and published or displayed. The introduction of the Euro could also be accompanied by a volatile interest rate environment, which could adversely affect investors in the Instruments.

EU Savings Directive

Under EU Council Directive 2003/48/EC on the taxation of savings income, each Member State is required to provide to the tax authorities of another Member State details of payments of interest or other similar income paid by a person within its jurisdiction to, or collected by such a person for, an individual or certain other persons resident in that other Member State; however, for a transitional period, Austria, Belgium and Luxembourg may instead apply a withholding system in relation to such payments, deducting tax at rates rising over time to 35 per cent. The transitional period is to terminate at the end of the first full fiscal year following agreement by certain non-EU countries to the exchange of information relating to such payments.

Also, a number of non-EU countries and certain dependent or associated territories of certain Member States, have agreed to adopt similar measures (either provision of information or transitional withholding) in relation to payments made by a person within its jurisdiction to, or collected by such a person for, an individual resident in a Member State. In addition, the Member States have entered into reciprocal provision of information or transitional withholding arrangements with certain of those dependent or associated territories in relation to payments made by a person in a Member State to, or collected by such a person for, an individual resident in one of those territories.

If a payment in respect of an Instrument which is the subject of the Directive were to be made or collected through a Member State which has opted for a withholding system and an amount of, or in respect of, tax were to be withheld from that payment, neither the Issuer nor any Paying Agent nor any other person would be obliged to pay additional amounts with respect to such Instrument as a result of the imposition of such withholding tax. However, the Issuer is required, save as provided in Condition 5.4, to maintain a Paying Agent in a Member State that will not be obliged to withhold or deduct tax pursuant to any law implementing the Directive or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000.

Change of law

The Terms and Conditions of the Instruments are based on English law in effect as at the date of issue of the relevant Instruments. No assurance can be given as to the impact of any possible judicial decision or change to English law or administrative practice after the date of issue of the relevant Instruments.

Risks related to the market generally

Set out below is a brief description of certain market risks, including liquidity risk, exchange rate risk, interest rate risk and credit risk:

The secondary market generally

Instruments may have no established trading market when issued, and one may never develop. If a market does develop, it may not be liquid. Therefore, investors may not be able to sell their Instruments easily or at prices that will provide them with a yield comparable to similar investments that have a developed secondary market. This is particularly the case for Instruments that are especially sensitive to interest rate, currency or market risks, are designed for specific investment objectives or strategies or have been structured to meet the investment requirements of limited categories of investors. These types of Instruments generally would have a more limited secondary market and more price volatility than conventional debt securities. Illiquidity may have a severely adverse effect on the market value of Instruments.

The Clearing Systems

The Global Instruments may be held by or on behalf of Euroclear Bank and Clearstream Luxembourg and consequently investors will have to rely on their procedures for transfer, payment and communication with the Issuer.

Instruments may be represented by one or more temporary Global Instruments or permanent Global Instruments. Such Global Instruments may be deposited with a common depositary for Euroclear and Clearstream, Luxembourg. Except in the circumstances described in the relevant Global Instrument, investors will not be entitled to receive Definitive Instruments. Euroclear and Clearstream, Luxembourg will maintain records of the interests in the Global Instruments. While the Instruments are represented by one or more Global Instruments, investors will be able to trade their interests only through Euroclear or Clearstream, Luxembourg.

While Instruments are represented by one or more Global Instruments, the Issuer will discharge its payment obligations under such Instruments by making payments to the common depositary for Euroclear and Clearstream, Luxembourg for distribution to their account holders. A holder of an interest in a Global Instrument must rely on the procedures of Euroclear and Clearstream, Luxembourg to receive payments under the relevant Instruments. The Issuer has no responsibility or liability for the records relating to, or payments made in respect of, interests in the Global Instruments.

Holders of interests in the Global Instruments will not have a direct right to vote in respect of the relevant Instruments. Instead, such holders will be permitted to act only to the extent that they are enabled by Euroclear or Clearstream, Luxembourg.

Exchange rate risks and exchange controls

The Issuer will pay principal and interest on the Instruments in the Specified Currency. This presents certain risks relating to currency conversions if an investor’s financial activities are denominated principally in a currency or currency unit (the “Investor’s Currency”) other than the Specified Currency. These include the risk that exchange rates may significantly change (including changes due to devaluation of the Specified Currency or revaluation of the Investor’s Currency) and the risk that authorities with jurisdiction over the Investor’s Currency may impose or modify exchange controls. An appreciation in the value of the Investor’s Currency relative to the Specified Currency would decrease (1) the Investor’s Currency-equivalent yield on the Instruments, (2) the Investor’s Currency equivalent value of the principal payable on the Instruments and (3) the Investor’s Currency equivalent market value of the Instruments.

Government and monetary authorities may impose (as some have done in the past) exchange controls that could adversely affect an applicable exchange rate. As a result, investors may receive less interest or principal than expected, or no interest or principal.

Interest rate risks

Investment in Fixed Rate Instruments involves the risk that subsequent changes in market interest rates may adversely affect the value of Fixed Rate Instruments.

Credit ratings may not reflect all risks

One or more independent credit rating agencies may assign credit ratings to an issue of Instruments. The ratings may not reflect the potential impact of all risks related to structure, market, additional factors discussed above, and other factors that may affect the value of the Instruments. A credit rating is not a recommendation to buy, sell or hold securities and may be revised or withdrawn by the rating agency at any time.

Legal investment considerations may restrict certain investments

The investment activities of certain investors are subject to legal investment laws and regulations, or review or regulation by certain authorities. Each potential investor should consult its legal advisers to determine whether and to what extent (1) Instruments are legal investments for it, (2) Instruments can be used as collateral for various types of borrowing and (3) other restrictions apply to its purchase or pledge of any Instruments. Financial institutions should consult their legal advisers or the appropriate regulators to determine the appropriate treatment of Instruments under any applicable risk-based capital or similar rules.

TERMS AND CONDITIONS OF THE INSTRUMENTS

The following is the text of the terms and conditions which, save for the text in italics and subject to completion and amendment and as supplemented or varied in accordance with the provisions of Part A of the relevant Final Terms, will be endorsed on the Instruments in definitive form (if any) issued in exchange for the Global Instrument(s) representing each Series. Either (a) the full text of these terms and conditions together with the relevant provisions of Part A of the Final Terms or (b) these terms and conditions as so completed, amended, supplemented or varied (and subject to simplification by the deletion of non-applicable provisions), shall be endorsed on such Instruments. All capitalised terms which are not defined in these Conditions will have the meanings given to them in the Trust Deed or Part A of the relevant Final Terms. Those definitions will be endorsed on the Definitive Instruments.

References in these terms and conditions to “Instruments” (as defined below) are to the Instruments of one Series only of the Issuer (as defined below), not to all Instruments that may be issued under the Programme.

National Grid USA (the “Issuer”) has established a Euro Medium Term Note Programme (the “Programme”) for the issuance of up to Euro 4,000,000,000 in aggregate principal amount of debt instruments (the “Instruments”). The Instruments are constituted by a Trust Deed (as amended or supplemented from time to time, the “Trust Deed”) dated 3 December 2007 between the Issuer and The Law Debenture Trust Corporation p.l.c. (the “Trustee”, which expression shall include all persons for the time being the trustee or trustees under the Trust Deed) as trustee for the Instrumentholders (as defined below). These terms and conditions include summaries of, and are subject to, the detailed provisions of the Trust Deed, which includes the form of the Definitive Instruments, Receipts, Coupons and Talons referred to below. An Agency Agreement (as amended or supplemented from time to time, the “Agency Agreement”) dated 3 December 2007 has been entered into in relation to the Instruments between the Issuer, the Trustee, The Bank of New York as initial issuing and paying agent and the other agent(s) named in it. The issuing and paying agent, the paying agent(s) and the calculation agent(s) for the time being (if any) are referred to below respectively as the “Issuing and Paying Agent”, the “Paying Agents” (which expression shall include the Issuing and Paying Agent) and the “Calculation Agent(s)”. Copies of the Trust Deed and the Agency Agreement are available for inspection by prior appointment during usual business hours at the registered office of the Trustee (as at 3 December 2007 at Fifth Floor, 100 Wood Street, London EC2V 7EX) and at the specified offices of the Paying Agents.

The Instrumentholders, the holders of the interest coupons (the “Coupons”) appertaining to interest bearing Instruments and, where applicable in the case of such Instruments, talons for further Coupons (the “Talons”) (the “Couponholders”) and the holders of the receipts for the payment of instalments of principal (the “Receipts”) relating to Instruments of which the principal is payable in instalments are entitled to the benefit of, are bound by, and are deemed to have notice of, all the provisions of the Trust Deed and are deemed to have notice of those provisions of the Agency Agreement applicable to them.

1		Form, Denomination and Title

		The Instruments are issued in bearer form in the Specified Denomination(s) specified in the relevant Final Terms and are serially numbered. Instruments of one Specified Denomination are not exchangeable for Instruments of another Specified Denomination provided that in the case of any Instruments which are to be admitted to trading on a regulated market within the European Economic Area or offered to the public in a Member State of the European Economic Area in circumstances which require the publication of a prospectus under the Prospectus Directive, the minimum Specified Denomination shall be€50,000 (or its equivalent in any other currency as at the date of issue of the relevant Instruments).

This Instrument is a Fixed Rate Instrument, a Floating Rate Instrument, a Zero Coupon Instrument, a Perpetual Instrument, an Instalment Instrument, a Dual Currency Instrument or a Partly Paid Instrument, a combination of any of the preceding or any other kind of Instrument, depending upon the Interest and Redemption/Payment Basis specified in the relevant Final Terms.

Instruments are issued with Coupons (and, where appropriate, a Talon) attached, save in the case of Zero Coupon Instruments in which case references to interest (other than in relation to interest due after the Maturity Date), Coupons and Talons in these Conditions are not applicable.

Instalment Instruments are issued with one or more Receipts attached. Title to the Instruments and the Receipts, Coupons and Talons shall pass by delivery and except as ordered by a court of competent jurisdiction or as required by law, the Issuer and the Paying Agents shall be entitled to treat the bearer of any Instrument, Receipt, Coupon or Talon as the absolute owner of that Instrument, Receipt, Coupon or Talon, as the case may be, and shall not be required to obtain any proof of ownership as to the identity of the bearer.

In these Conditions, “Instrumentholder” means the bearer of any Instrument of one Series only of the Issuer and the Receipts relating to it, “holder” (in relation to an Instrument, Receipt, Coupon or Talon) means the bearer of any Instrument, Receipt, Coupon or Talon and capitalised terms have the meanings given to them herein, the absence of any such meaning indicating that such term is not applicable to the Instruments.

Status and Negative Pledge

	2.1		Status

			The Instruments and the Receipts and Coupons relating to them constitute direct, unconditional and unsecured obligations of the Issuer and rankpari passuwithout any preference or priority among themselves. The payment obligations of the Issuer under the Instruments, Receipts and Coupons shall, subject to such exceptions as are from time to time applicable under the laws of England, rank equally with all other present and future unsecured obligations (other than subordinated obligations, if any) of the Issuer.

	2.2		Negative Pledge

			So long as any Instrument, Receipt or Coupon remains outstanding (as defined in the Trust Deed) the Issuer will not create or permit to subsist any mortgage, charge, pledge, lien or other form of encumbrance or security interest (“Security”) upon the whole or any part of its undertaking, assets or revenues present or future to secure any Relevant Indebtedness, or any guarantee of or indemnity in respect of any Relevant Indebtedness unless, at the same time or prior thereto, the Issuer’s obligations under the Instruments, the Receipts, the Coupons and the Trust Deed (a) are secured equally and rateably therewith or benefit from a guarantee or indemnity in substantially identical terms thereto, as the case may be, in each case to the satisfaction of the Trustee, or (b) have the benefit of such other security, guarantee, indemnity or other arrangement as the Trustee in its absolute discretion shall deem to be not materially less beneficial to the Instrumentholders or as shall be approved by an Extraordinary Resolution (as defined in the Trust Deed) of the Instrumentholders.

			For the purposes of these Conditions, “Relevant Indebtedness” means any present or future indebtedness in the form of, or represented by, bonds, notes, debentures, loan stock or other securities which are for the time being, or are intended, with the agreement of the Issuer, to be quoted, listed or ordinarily dealt in on any stock exchange.

Interest

	3.1		Interest on Fixed Rate Instruments

			Each Fixed Rate Instrument bears interest on its outstanding nominal amount from the Interest Commencement Date at the rate per annum (expressed as a percentage) equal to the Rate of Interest, payable in arrear on each Interest Payment Date. The amount of Interest payable shall be determined in accordance with Condition 3.8.

			If a Fixed Coupon Amount or a Broken Amount is specified in the relevant Final Terms, the amount of interest payable on each Interest Payment Date will amount to the Fixed Coupon Amount, or, if applicable, the Broken Amount so specified and in the case of a Broken Amount will be payable on the particular Interest Payment Date(s) specified in the relevant Final Terms.

3.2

Interest on Floating Rate Instruments

	3.2.1		Interest Payment Dates

			Each Floating Rate Instrument bears interest on its outstanding nominal amount from the Interest Commencement Date at the rate per annum (expressed as a percentage) equal to the Rate of Interest, such interest being payable in arrear on each Interest Payment Date. The amount of Interest payable shall be determined in accordance with Condition 3.8. Such Interest Payment Date(s) is/are either specified in the relevant Final Terms as Specified Interest Payment Dates or, if no Specified Interest Payment Date(s) is/are specified in the relevant Final Terms, Interest Payment Date shall mean each date which falls the number of months or other period shown on this Instrument as the Interest Period after the preceding Interest Payment Date or, in the case of the first Interest Payment Date, after the Interest Commencement Date.

	3.2.2		Business Day Convention

			If any date which is specified to be subject to adjustment in accordance with a Business Day Convention would otherwise fall on a day which is not a Business Day, then, if the Business Day Convention specified is (a) the Floating Rate Convention, such date shall be postponed to the next day which is a Business Day unless it would then fall into the next calendar month, in which event (x) such date shall be brought forward to the immediately preceding Business Day and (y) each subsequent such date shall be the last Business Day of the month in which such date would have fallen had it not been subject to adjustment, (b) the Following Business Day Convention, such date shall be postponed to the next day which is a Business Day, (c) the Modified Following Business Day Convention, such date shall be postponed to the next day which is a Business Day unless it would then fall into the next calendar month, in that event such date shall be brought forward to the immediately preceding Business Day or (d) the Preceding Business Day Convention, such date shall be brought forward to the immediately preceding Business Day.

	3.2.3		Rate of Interest for Floating Rate Instruments

			The Rate of Interest in respect of Floating Rate Instruments for each Interest Accrual Period shall be determined in the manner specified in the relevant Final Terms and the provisions below relating to either ISDA Determination or Screen Rate Determination shall apply, depending upon which is specified on this Instrument.

(a)

ISDA Determination for Floating Rate Instruments: Where ISDA Determination is specified in the relevant Final Terms as the manner in which the Rate of Interest is to be determined, the Rate of Interest for each Interest Accrual Period shall be determined by the Calculation Agent as a rate equal to the relevant ISDA Rate. For

the purposes of this sub-paragraph (a), “ISDA Rate” for an Interest Accrual Period means a rate equal to the Floating Rate which would be determined by the Calculation Agent under a Swap Transaction under the terms of an agreement incorporating the ISDA Definitions and under which:

	(i)		the Floating Rate Option is as specified in the relevant Final Terms;

	(ii)		the Designated Maturity is a period specified in the relevant Final Terms; and

	(iii)		the relevant Reset Date is the first day of that Interest Accrual Period unless otherwise specified in the relevant Final Terms.

For the purposes of this sub-paragraph (a), “Floating Rate”, “Calculation Agent”, “Floating Rate Option”, “Designated Maturity”, “Reset Date” and “Swap Transaction” have the meanings given to those terms in the ISDA Definitions.

(b)

Screen Rate Determination for Floating Rate Instruments:

(i)

Where Screen Rate Determination is specified in the relevant Final Terms as the manner in which the Rate of Interest is to be determined, the Rate of Interest for each Interest Accrual Period will, subject as provided below, be either:

	(x)		the offered quotation; or

	(y)		the arithmetic mean of the offered quotations,

(expressed as a percentage rate per annum) for the Reference Rate which appears or appear, as the case may be, on the Relevant Screen Page as at either 11.00 a.m. (London time in the case of LIBOR or Brussels time in the case of EURIBOR) on the Interest Determination Date in question as determined by the Calculation Agent. If five or more of such offered quotations are available on the Relevant Screen Page, the highest (or, if there is more than one such highest quotation, one only of such quotations) and the lowest (or, if there is more than one such lowest quotation, one only of such quotations) shall be disregarded by the Calculation Agent for the purpose of determining the arithmetic mean of such offered quotations.

If the Reference Rate from time to time in respect of Floating Rate Instruments is specified hereon as being other than LIBOR or EURIBOR, the Rate of Interest in respect of such Instruments will be determined as provided hereon.

(ii)

if the Relevant Screen Page is not available or if, sub-paragraph (i)(x) applies and no such offered quotation appears on the Relevant Screen Page or if sub-paragraph (i)(y) above applies and fewer than three such offered quotations appear on the Relevant Screen Page in each case as at the time specified above, subject as provided below, the Calculation Agent shall request, if the Reference Rate is LIBOR, the principal London office of each of the Reference Banks or, if the Reference Rate is EURIBOR, the principal Euro-zone office of each of the Reference Banks, to provide the Calculation Agent with its offered quotation (expressed as a percentage rate per annum) for the Reference Rate if the Reference Rate is LIBOR, at approximately 11.00 a.m. (London time), or if the Reference Rate is EURIBOR, at approximately 11.00 a.m. (Brussels time) on the Interest Determination Date in question. If two or more of the Reference Banks provide the Calculation

Agent with such offered quotations, the Rate of Interest for such Interest Period shall be the arithmetic mean of such offered quotations as determined by the Calculation Agent; and

(iii)

if paragraph (ii) above applies and the Calculation Agent determines that fewer than two Reference Banks are providing offered quotations, subject as provided below, the Rate of Interest shall be the arithmetic mean of the rates per annum (expressed as a percentage) as communicated to (and at the request of) the Calculation Agent by the Reference Banks or any two or more of them, at which such banks were offered, if the Reference Rate is LIBOR, at approximately 11.00 a.m. (London time) or, if the Reference Rate is EURIBOR, at approximately 11.00 a.m. (Brussels time) on the relevant Interest Determination Date, deposits in the Specified Currency for a period equal to that which would have been used for the Reference Rate by leading banks in, if the Reference Rate is LIBOR, the London inter-bank market or, if the Reference Rate is EURIBOR, the Euro-zone inter-bank market, as the case may be, or, if fewer than two of the Reference Banks provide the Calculation Agent with such offered rates, the offered rate for deposits in the Specified Currency for a period equal to that which would have been used for the Reference Rate, or the arithmetic mean of the offered rates for deposits in the Specified Currency for a period equal to that which would have been used for the Reference Rate, at which, if the Reference Rate is LIBOR, at approximately 11.00 a.m. (London time) or, if the Reference Rate is EURIBOR, at approximately 11.00 a.m. (Brussels time), on the relevant Interest Determination Date, any one or more banks (which bank or banks is or are in the opinion of the Trustee and the Issuer suitable for such purpose) informs the Calculation Agent it is quoting to leading banks in, if the Reference Rate is LIBOR, the London inter-bank market or, if the Reference Rate is EURIBOR, the Euro-zone inter-bank market, as the case may be, provided that, if the Rate of Interest cannot be determined in accordance with the foregoing provisions of this paragraph, the Rate of Interest shall be determined as at the last preceding Interest Determination Date (though substituting, where a different Margin or Maximum or Minimum Rate of Interest is to be applied to the relevant Interest Accrual Period from that which applied to the last preceding Interest Accrual Period, the Margin or Maximum or Minimum Rate of Interest relating to the relevant Interest Accrual Period, in place of the Margin or Maximum or Minimum Rate of Interest relating to that last preceding Interest Accrual Period).

	3.3		Zero Coupon Instruments

			Where an Instrument, the Interest Basis of which is specified to be Zero Coupon, is repayable prior to the Maturity Date and is not paid when due, the amount due and payable prior to the Maturity Date shall be the Early Redemption Amount of such Instrument. As from the Maturity Date, the Rate of Interest for any overdue principal of such an Instrument shall be a rate per annum (expressed as a percentage) equal to the Amortisation Yield (as defined in Condition 4.4.1(b)).

	3.4		Dual Currency Instruments

			In the case of Dual Currency Instruments, if the rate or amount of interest falls to be determined by reference to a Rate of Exchange or a method of calculating a Rate of Exchange, the rate or amount of interest payable shall be determined in the manner specified in the relevant Final Terms.

	3.5		Partly Paid Instruments

			In the case of Partly Paid Instruments (other than Partly Paid Instruments which are Zero Coupon Instruments), interest will accrue as previously stated on the paid-up nominal amount of such Instruments and otherwise as specified in the relevant Final Terms.

	3.6		Accrual of Interest

			Interest shall cease to accrue on each Instrument on the due date for redemption unless, upon due presentation, payment is improperly withheld or refused, in which event interest shall continue to accrue (as well after as before judgment) at the Rate of Interest in the manner provided in this Condition 3 to the Relevant Date (as defined in Condition 6).

	3.7		Margin, Maximum/Minimum Rates of Interest, Instalment Amounts and Redemption Amounts and Rounding

	(i)		If any Margin is specified in the relevant Final Terms (either (x) generally, or (y) in relation to one or more Interest Accrual Periods), an adjustment shall be made to all Rates of Interest, in the case of (x), or the Rates of Interest for the specified Interest Accrual Periods, in the case of (y), calculated in accordance with Condition 3.2.3(b) above, by adding (if a positive number) or subtracting (if a negative number) the absolute value of such Margin, subject always to the next paragraph.

	(ii)		If any Maximum or Minimum Rate of Interest, Instalment Amount or Redemption Amount is specified in the relevant Final Terms, then any Rate of Interest, Instalment Amount or Redemption Amount shall be subject to such maximum or minimum, as the case may be.

	(iii)		For the purposes of any calculations required pursuant to these Conditions (unless otherwise specified), (x) all percentages resulting from such calculations shall be rounded, if necessary, to the nearest one hundred thousandth of a percentage point (with halves being rounded up), (y) all figures shall be rounded to seven significant figures (with halves being rounded up) and (z) all currency amounts that fall due and payable shall be rounded to the nearest unit of such currency (with halves being rounded up), save in the case of yen, which shall be rounded down to the nearest yen. For these purposes “unit” means the lowest amount of such currency which is available as legal tender in the country of such currency.

	3.8		Calculations

			The amount of interest payable per Calculation Amount in respect of any Instrument for any Interest Accrual Period shall be equal to the product of the Rate of Interest, the Calculation Amount as specified in the relevant Final Terms, and the Day Count Fraction for such Interest Accrual Period, unless an Interest Amount (or a formula for its calculation) is applicable to such Interest Accrual Period, in which case the amount of interest payable per Calculation Amount in respect of such Instrument for such Interest Accrual Period shall equal such Interest Amount (or be calculated in accordance with such formula). Where any Interest Period comprises two or more Interest Accrual Periods, the amount of interest payable per Calculation Amount in respect of such Interest Period shall be the sum of the Interest Amounts payable in respect of each of those Interest Accrual Periods. In respect of any other period for which interest is required to be calculated, the provisions above shall apply save that the Day Count Fraction shall be for the period for which interest is required to be calculated.

	3.9		Determination and Publication of Rates of Interest, Interest Amounts, Final Redemption Amounts, Early Redemption Amounts, Optional Redemption Amounts and Instalment Amounts

			The Calculation Agent shall as soon as practicable on each Interest Determination Date or such other time on such date as the Calculation Agent may be required to calculate any rate or amount, obtain any quotation or make any determination or calculation, determine such rate and calculate the Interest Amounts for the relevant Interest Accrual Period, calculate the Redemption Amount or Instalment Amount, obtain such quote or make such determination or calculation, as the case may be, and cause the Rate of Interest and the Interest Amounts for each Interest Accrual Period and the relevant Interest Payment Date and, if required to be calculated, the Final Redemption Amount, Early Redemption Amount, Optional Redemption Amount or any Instalment Amount to be notified to the Trustee, the Issuer, each of the Paying Agents, the Instrumentholders, any other Calculation Agent appointed in respect of the Instruments that is to make a further calculation upon receipt of such information and, if the Instruments are listed on a stock exchange and the rules of such exchange so require, such exchange as soon as possible after their determination but in no event later than (i) the commencement of the relevant Interest Period, if determined prior to such time, in the case of notification to such exchange of a Rate of Interest and Interest Amount, or (ii) in all other cases, the fourth Business Day after such determination. Where any Interest Payment Date or Interest Period Date is subject to adjustment pursuant to Condition 3.2.3(b)(ii), the Interest Amounts and the Interest Payment Date so published may subsequently be amended (or appropriate alternative arrangements made with the consent of the Trustee by way of adjustment) without notice in the event of an extension or shortening of the Interest Period. If the Instruments become due and payable under Condition 8, the accrued interest and the Rate of Interest payable in respect of the Instruments shall nevertheless continue to be calculated as previously in accordance with this Condition but no publication of the Rate of Interest or the Interest Amount so calculated need be made unless the Trustee otherwise requires. The determination of any rate or amount, the obtaining of each quotation and the making of each determination or calculation by the Calculation Agent(s) shall (in the absence of manifest error) be final and binding upon all parties.

	3.10		Determination or Calculation by Trustee

			If the Calculation Agent does not at any time for any reason determine or calculate the Rate of Interest for an Interest Accrual Period or any Interest Amount, Instalment Amount, Final Redemption Amount, Early Redemption Amount or Optional Redemption Amount the Trustee shall do so (or shall appoint an agent on its behalf to do so) and such determination or calculation shall be deemed to have been made by the Calculation Agent. In doing so, the Trustee shall apply the preceding provisions of this Condition, with any necessary consequential amendments, to the extent that, in its opinion, it can do so, and, in all other respects it shall do so in such manner as it shall deem fair and reasonable in all the circumstances.

	3.11		Definitions

			In these Conditions, unless the context otherwise requires, the following defined terms shall have the meanings set out below:

			“Business Day” means:

	(a)		in the case of a currency other than Euro, a day (other than a Saturday or Sunday) on which commercial banks and foreign exchange markets settle payments in the principal financial centre for such currency; and/or

	(b)		in the case of Euro, a day on which the TARGET System is operating (a “TARGET Business Day”); and/or

(c)

in the case of a currency and/or one or more Business Centres as specified in the relevant Final Terms, a day (other than a Saturday or a Sunday) on which commercial banks and foreign exchange markets settle payments in such currency or, if no currency is indicated, generally in each of the Business Centres.

“Day Count Fraction” means, in respect of the calculation of an amount of interest on any Instrument for any period of time (from and including the first day of such period to but excluding the last) (whether or not constituting an Interest Period or Interest Accrual Period, the “Calculation Period”):

	(a)		if “Actual/Actual” or “Actual/Actual-ISDA” is specified in the relevant Final Terms, the actual number of days in the Calculation Period divided by 365 (or, if any portion of that Calculation Period falls in a leap year, the sum of (i) the actual number of days in that portion of the Calculation Period falling in a leap year divided by 366 and (ii) the actual number of days in that portion of the Calculation Period falling in a non-leap year divided by 365);

	(b)		if “Actual/365 (Fixed)” is specified in the relevant Final Terms, the actual number of days in the Calculation Period divided by 365;

	(c)		if “Actual/360” is specified in the relevant Final Terms, the actual number of days in the Calculation Period divided by 360;

	(d)		if “30/360”, “360/360” or “Bond Basis” is specified in the relevant Final Terms, the number of days in the Calculation Period divided by 360 calculated on a formula basis as follows:


Day Count Fraction	=	[360 x (Y₂ -Y₁)] + [30 x (M₂ -M₁)]+ (D₂ -D₁)
			360

where:

“Y1” is the year, expressed as a number, in which the first day of the Calculation Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Calculation Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“D₁” is the first calendar day, expressed as a number, of the Calculation Period, unless such number would be 31, in which case D₁ will be 30; and

“D₂” is the calendar day, expressed as a number, immediately following the last day included in the Calculation Period, unless such number would be 31 and D₁ is greater than 29, in which case D₂ will be 30;

(e)

if “30E/360” or “Eurobond Basis” is specified in the relevant Final Terms, the number of days in the Calculation Period divided by 360 calculated on a formula basis as follows:


Day Count Fraction	=	[360 x (Y₂ -Y₁)] + [30 x (M₂ -M₁)]+ (D₂ -D₁)
			360

where:

“Y1” is the year, expressed as a number, in which the first day of the Calculation Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Calculation Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“D1” is the first calendar day, expressed as a number, of the Calculation Period, unless such number would be 31, in which case D1 will be 30; and

“D2” is the calendar day, expressed as a number, immediately following the last day included in the Calculation Period, unless such number would be 31, in which case D2 will be 30;

(f)

if “30E/360 (ISDA)” is specified in the relevant Final Terms, the number of days in the Calculation Period divided by 360, calculated on a formula basis as follows:


Day Count Fraction	=	[360 x (Y₂ -Y₁)] + [30 x (M₂ -M₁)]+ (D₂ -D₁)
			360

where:

“Y1” is the year, expressed as a number, in which the first day of the Calculation Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Calculation Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day included in the Calculation Period falls;

“D1” is the first calendar day, expressed as a number, of the Calculation Period, unless (i) that day is the last day of February or (ii) such number would be 31, in which case D1 will be 30; and

“D2” is the calendar day, expressed as a number, immediately following the last day included in the Calculation Period, unless (i) that day is the last day of February but not the Maturity Date or (ii) such number would be 31, in which case D₂ will be 30; and

(g)

if “Actual/Actual-ICMA” is specified in the relevant Final Terms:

	(i)		if the Calculation Period is equal to or shorter than the Determination Period during which it falls, the actual number of days in the Calculation Period divided by the product of (x) the actual number of days in such Determination Period and (y) the number of Determination Periods in any year; and

	(ii)		if the Calculation Period is longer than one Determination Period, the sum of:

	(A)		the actual number of days in such Calculation Period falling in the Determination Period in which it begins divided by the product of (a) the actual number of days in such Determination Period and (b) the number of Determination Periods in any year; and

	(B)		the actual number of days in such Calculation Period falling in the next Determination Period divided by the product of (a) the actual number of days in such Determination Period and (b) the number of Determination Periods in any year,

			where:

			“Determination Period” means the period from and including a Determination Date in any year to but excluding the next Determination Date; and

			“Determination Date” means the date specified as such in the relevant Final Terms or, if none is so specified, the Interest Payment Date.

“Euro-zone” means the region comprising of member states of the European Union that adopt the single currency in accordance with the Treaty establishing the European Community as amended.

“Interest Accrual Period” means the period beginning on (and including) the Interest Commencement Date and ending on (but excluding) the first Interest Period Date and each successive period beginning on (and including) an Interest Period Date and ending on (but excluding) the next succeeding Interest Period Date.

“Interest Amount” means:

	(a)		in respect of an Interest Accrual Period, the amount of interest payable per Calculation Amount for that Interest Accrual Period and which, in the case of Fixed Rate Instruments, and unless otherwise specified in the relevant Final Terms, shall mean the Fixed Coupon Amount or Broken Amount specified in the relevant Final Terms as being payable on the Interest Payment Date ending the Interest Period of which such Interest Accrual Period forms part; and

	(b)		in respect of any other period, the amount of interest payable per Calculation Amount for that period.

“Interest Commencement Date” means the Issue Date or such other date as may be specified in the relevant Final Terms.

“Interest Determination Date” means, with respect to a Rate of Interest and Interest Accrual Period, the date specified as such in the relevant Final Terms or, if none is so specified, (a) the first day of such Interest Accrual Period if the Specified Currency is Sterling or (b) the day falling two Business Days in London prior to the first day of such Interest Accrual Period if the Specified Currency is neither Sterling nor Euro or (c) the day falling two TARGET Business Days prior to the first day of such Interest Accrual Period if the Specified Currency is Euro.

“Interest Payment Date” means the date or dates specified as such in, or determined in accordance with the provisions of, the relevant Final Terms and, if a Business Day Convention is specified in the relevant Final Terms, as the same may be adjusted in accordance with the relevant Business Day Convention.

“Interest Period” means the period beginning on (and including) the Interest Commencement Date and ending on (but excluding) the first Interest Payment Date and each successive period

beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date.

“Interest Period Date” means each Interest Payment Date unless otherwise specified in the relevant Final Terms.

“ISDA Definitions” means the 2006 ISDA Definitions as published by the International Swaps and Derivatives Association, Inc., unless otherwise specified in the relevant Final Terms.

“Rate of Interest” means the rate of interest payable from time to time in respect of this Instrument and that is either specified on, or calculated in accordance with the provisions of, the relevant Final Terms.

“Redemption Amount” means, as appropriate, the Final Redemption Amount, the Early Redemption Amount (Tax), the Optional Redemption Amount (Call), the Optional Redemption Amount (Put), the Early Termination Amount or such other amount in the nature of a redemption amount as may be specified in, or determined in accordance with the provisions of the relevant Final Terms.

“Reference Banks” means, in the case of a determination of LIBOR, the principal London office of four major banks in the London inter-bank market and, in the case of a determination of EURIBOR, the principal Euro-zone office of four major banks in the Euro-zone inter-bank market, in each case selected by the Calculation Agent or as specified in the relevant Final Terms.

“Reference Rate” means the rate specified as such in the relevant Final Terms.

“Relevant Screen Page” means such page, section, caption, column or other part of a particular information service as may be specified in the relevant Final Terms.

“Specified Currency” means the currency specified as such in the relevant Final Terms or, if none is specified, the currency in which the Instruments are denominated.

“TARGET System” means the Trans-European Automated Real-Time Gross Settlement Express Transfer (TARGET) System or any successor to it.

	3.12		Calculation Agent

			The Issuer shall procure that there shall at all times be one or more Calculation Agents if provision is made for them in the relevant Final Terms and for so long as any Instrument is outstanding. Where more than one Calculation Agent is appointed in respect of the Instruments, references in these Conditions to the Calculation Agent shall be construed as each Calculation Agent performing its respective duties under these Conditions. If the Calculation Agent is unable or unwilling to act as such or if the Calculation Agent fails duly to establish the Rate of Interest for an Interest Period or Interest Accrual Period or to calculate any Interest Amount, Instalment Amount, Final Redemption Amount, Early Redemption Amount or Optional Redemption Amount, as the case may be, or to comply with any other requirement, the Issuer shall (with the prior approval of the Trustee) appoint a leading bank or investment banking firm engaged in the interbank market (or, if appropriate, money, swap or over-the-counter index options market) which is most closely connected with the calculation or determination to be made by the Calculation Agent (acting through its principal London office or any other office actively involved in such market) to act as such in its place. The Calculation Agent may not resign its duties without a successor having been appointed as specified in this paragraph.

Redemption, Purchase and Options

	4.1		Final Redemption

			Unless previously redeemed, purchased and cancelled as provided below, this Instrument will be redeemed at its Final Redemption Amount (which, unless otherwise provided, is its nominal amount) on the Maturity Date specified in the relevant Final Terms provided, however, that if this Instrument is a Perpetual Instrument it will only be redeemable and repayable in accordance with the following provisions of this Condition 4.

	4.2		Redemption for Taxation Reasons

			If, on the occasion of the next payment in respect of the Instruments the Issuer satisfies the Trustee immediately before the giving of the notice referred to below that it would be unable to make such payment without having to pay additional amounts as described in Condition 6, and such requirement to pay such additional amounts arises by reason of a change in the laws of the United States of America or any political sub-division of the United States of America or any authority in or of the United States of America having power to tax or in the interpretation or application of the laws of the United States of America or any political sub-division of the United States of America or any authority in or of the United States of America having power to tax or in any applicable double taxation treaty or convention, which change becomes effective on or after the date on which agreement is reached to issue the first Tranche of the Instruments, and such requirement cannot be avoided by the Issuer taking reasonable measures (such measures not involving any material additional payments by, or expense for, the Issuer), the Issuer may, at its option, at any time, having given not less than 30 nor more than 45 days’ notice to the Instrumentholders in accordance with Condition 13, redeem all, but not some only, of the Instruments at their Early Redemption Amount together with interest accrued to the date of redemption provided that the date fixed for redemption shall not be earlier than 90 days prior to the earliest date on which the Issuer would be obliged to pay such additional amounts or make such withholding or deduction, as the case may be, were a payment in respect of the Instruments then due. Prior to the publication of any notice of redemption pursuant to this Condition 4.2, the Issuer shall deliver to the Trustee a certificate signed by two directors of the Issuer stating that the requirement referred to above cannot be avoided by the Issuer taking reasonable measures available to it and the Trustee shall be entitled to accept such certificate as sufficient evidence of the satisfaction of the condition precedent set out above in which event it shall be conclusive and binding on Instrumentholders and Couponholders.

	4.3		Purchases

			The Issuer and any of its Subsidiaries may at any time purchase Instruments (provided that all unmatured Receipts and Coupons and unexchanged Talons appertaining to them are attached or surrendered with them) in the open market or otherwise at any price.

			“Subsidiary” means any corporation a majority of the outstanding voting stock of which is owned, directly or indirectly, by the Issuer.

4.4

Early Redemption

4.4.1

Zero Coupon Instruments

(a)

The Early Redemption Amount payable in respect of any Zero Coupon Instrument, the Early Redemption Amount of which is not linked to a formula, upon redemption of such Instrument pursuant to Condition 4.2 or upon it becoming due and payable as provided in Condition 8 shall be the Amortised Face Amount (calculated as provided below) of such Instrument unless otherwise specified in the relevant Final Terms.

	(b)		Subject to the provisions of sub-paragraph (c) below, the Amortised Face Amount of any such Instrument shall be the scheduled Final Redemption Amount of such Instrument on the Maturity Date discounted at a rate per annum (expressed as a percentage) equal to the Amortisation Yield (which, if none is specified in the relevant Final Terms, shall be such rate as would produce an Amortised Face Amount equal to the issue price of the Instruments if they were discounted back to their issue price on the Issue Date) compounded annually.

	(c)		If the Early Redemption Amount payable in respect of any such Instrument upon its redemption pursuant to Condition 4.2 or, if applicable, Condition 4.5 or upon it becoming due and payable as provided in Condition 8, is not paid when due, the Early Redemption Amount due and payable in respect of such Instrument shall be the Amortised Face Amount of such Instrument as defined in sub-paragraph (b) above, except that such sub-paragraph shall have effect as though the reference in that sub-paragraph to the date on which the Instrument becomes due and payable was replaced by a reference to the Relevant Date as defined in Condition 6. The calculation of the Amortised Face Amount in accordance with this sub-paragraph shall continue to be made (as well after as before judgment) until the Relevant Date, unless the Relevant Date falls on or after the Maturity Date, in which case the amount due and payable shall be the scheduled Final Redemption Amount of such Instrument on the Maturity Date together with any interest that may accrue in accordance with Condition 3.2.

Where such calculation is to be made for a period of less than one year, it shall be made on the basis of the Day Count Fraction specified in the relevant Final Terms.

	4.4.2		Other Instruments

			The Early Redemption Amount payable in respect of any Instrument (other than Instruments described in Condition 4.4.1), upon redemption of such Instrument pursuant to this Condition 4.4 or upon it becoming due and payable as provided in Condition 8, shall be the Final Redemption Amount unless otherwise specified in the relevant Final Terms.

4.5

Redemption at the Option of the Issuer and Exercise of Issuer’s Options

	4.5.1		If (i) Residual Holding Call Option is specified in the relevant Final Terms, and (ii) if at any time the Residual Holding Percentage or more of the aggregate nominal amount of Instruments originally issued shall have been redeemed or purchased and cancelled, the Issuer shall have the option to redeem such outstanding Instruments in whole, but not in part, at their Residual Holding Redemption Amount. Unless otherwise specified in the relevant Final Terms, the Residual Holding Redemption Amount will be calculated by the Calculation Agent by discounting the outstanding nominal amount of the Instruments and the remaining interest payments (if applicable) to the Maturity Date by a rate per annum (expressed as a percentage to the nearest one hundred thousandth of a percentage point (with halves being rounded up)) equal to the Benchmark Yield, being the yield on the Benchmark Security at the close of business on the third Business Day prior to the date fixed for such redemption, plus the Benchmark Spread. Where the specified calculation is to be made for a period of less than one year, it shall be calculated using the Benchmark Day Count Fraction. The Issuer will give not less than 15 nor more than 30 days’ irrevocable notice to the Instrumentholders and the Trustee of any such redemption pursuant to this Condition 4.5.1.

	4.5.2		If Call Option is specified in the relevant Final Terms, the Issuer may, on giving not less than 15 nor more than 30 days’ irrevocable notice to the Instrumentholders (or such other notice period as may be specified in the relevant Final Terms), redeem, or exercise any

Issuer’s option in relation to, all or, if so provided, some of such Instruments on any Optional Redemption Date or Option Exercise Date, as the case may be. Any such redemption of Instruments shall be at their Optional Redemption Amount together with interest accrued to the date fixed for redemption. Any such redemption or exercise must relate to Instruments of a nominal amount at least equal to the minimum nominal amount (if any) permitted to be redeemed specified hereon and no greater than the maximum nominal amount (if any) permitted to be redeemed specified on this Instrument.

All Instruments in respect of which any such notice is given shall be redeemed, or the Issuer’s option shall be exercised, on the date specified in such notice in accordance with this Condition.

In the case of a partial redemption or a partial exercise of the Issuer’s option, the notice to Instrumentholders shall also contain the serial numbers of the Instruments to be redeemed, which shall have been drawn in such place as the Trustee may approve and in such manner as it deems appropriate, subject to compliance with any applicable laws, listing authority and stock exchange requirements.

	4.6		Redemption at the Option of Instrumentholders

			If Put Option is specified in the relevant Final Terms, the Issuer shall, at the option of any Instrumentholder, upon such Instrumentholder giving not less than 15 nor more than 30 days’ notice to the Issuer (or such other notice period as may be specified on this Instrument) redeem such Instrument on the Optional Redemption Date(s) (as specified in the Final Terms) at its Optional Redemption Amount (as specified in the Final Terms) together with interest accrued to the date fixed for redemption.

			To exercise such option (which must be exercised on an Option Exercise Date) the holder must deposit such Instrument with any Paying Agent at its specified office, together with a duly completed option exercise notice (“Exercise Notice”) in the form obtainable from any Paying Agent within the Instrumentholders’ Option Period (as specified in the Final Terms). No Instrument so deposited and option exercised may be withdrawn (except as provided in the Agency Agreement) without the prior consent of the Issuer.

	4.7		Partly Paid Instruments

			Partly Paid Instruments will be redeemed, whether at maturity, early redemption or otherwise, in accordance with the provisions of this Condition and the provisions specified in the relevant Final Terms.

	4.8		Redemption by Instalments

			Unless previously redeemed, purchased and cancelled as provided in this Condition 4, each Instrument which provides for Instalment Dates and Instalment Amounts will be partially redeemed on each Instalment Date at the Instalment Amount specified in the relevant Final Terms. The outstanding nominal amount of each such Instrument shall be reduced by the Instalment Amount (or, if such Instalment Amount is calculated by reference to a proportion of the nominal amount of such Instrument, such proportion) for all purposes with effect from the related Instalment Date, unless payment of the Instalment Amount is improperly withheld or refused on presentation of the related Receipt, in which case, such amount shall remain outstanding until the Relevant Date relating to such Instalment Amount.

	4.9		Cancellation

			All Instruments redeemed pursuant to any of the foregoing provisions will be cancelled forthwith together with all unmatured Receipts and Coupons and unexchanged Talons attached thereto. All Instruments purchased by or on behalf of the Issuer or any of its Subsidiaries may, at the option of the Issuer be held by or may be surrendered together with all unmatured Receipts and Coupons

and all unexchanged Talons attached to them to a Paying Agent for cancellation, but may not be resold and when held by the Issuer or any of its Subsidiaries shall not entitle the holder to vote at any meeting of Instrumentholders and shall not be deemed to be outstanding for the purposes of calculating quorums at meetings of Instrumentholders or for the purposes of Condition 10.

Payments and Talons

	5.1		Payments

			Payments of principal and interest in respect of Instruments will, subject as mentioned below, be made against presentation and surrender of the relevant Receipts (in the case of payments of Instalment Amounts other than on the due date for redemption and provided that the Receipt is presented for payment together with its relative Instrument), Instruments (in the case of all other payments of principal and, in the case of interest, as specified in Condition 5.5.6) or Coupons (in the case of interest, save as specified in Condition 5.5.6), as the case may be, at the specified office of any Paying Agent outside the United States by a cheque payable in the currency in which such payment is due drawn on, or, at the option of the holder, by transfer to an account denominated in that currency with, a bank in the principal financial centre for that currency; provided that in the case of Euro, the transfer shall be in a city in which banks have access to the TARGET System.

	5.2		Payments in the United States

			Notwithstanding the above, if any Instruments are denominated in U.S. dollars, payments in respect of them may be made at the specified office of any Paying Agent in New York City in the same manner as specified above if (a) the Issuer shall have appointed Paying Agents with specified offices outside the United States with the reasonable expectation that such Paying Agents would be able to make payment of the amounts on the Instruments in the manner provided above when due, (b) payment in full of such amounts at all such offices is illegal or effectively precluded by exchange controls or other similar restrictions on payment or receipt of such amounts and (c) such payment is then permitted by United States law, without involving, in the opinion of the Issuer, any adverse tax consequence to the Issuer.

	5.3		Payments subject to Fiscal Laws etc.

			All payments are subject in all cases to any applicable fiscal or other laws, regulations and directives, but without prejudice to the provisions of Condition 6. No commission or expenses shall be charged to the Instrumentholders or Couponholders in respect of such payments.

	5.4		Appointment of Agents

			The Issuing and Paying Agent, the Paying Agents and the Calculation Agent initially appointed by the Issuer and their respective specified offices are listed below. The Issuing and Paying Agent, the Paying Agents and the Calculation Agent act solely as agents of the Issuer and do not assume any obligation or relationship of agency or trust for or with any holder. The Issuer reserves the right at any time with the approval of the Trustee to vary or terminate the appointment of the Issuing and Paying Agent, any other Paying Agent or the Calculation Agent and to appoint additional or other Paying Agents, provided that the Issuer shall at all times maintain (a) an Issuing and Paying Agent, (b) a Paying Agent having its specified office in a major European city, which shall be London so long as the Instruments are admitted to the Official List of the Financial Services Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 and admitted to trading on the London Stock Exchange’s Gilt-Edged and Fixed Interest Market, (c) a Calculation Agent where the Conditions so require one, (d) so long as the Instruments are listed on any stock exchange or admitted to listing by any other relevant authority, a Paying Agent having a specified office in such place as may be required by the rules and regulations of any other relevant stock exchange or other relevant authority and (e) to the extent

that the Issuer is able to do so and not provided for by the foregoing provisions of this Condition 5.4, a Paying Agent with a specified office in a European Union member state that will not be obliged to withhold or deduct tax pursuant to any law implementing European Council Directive 2003/48/EC or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000. As used in these Conditions, the terms “Issuing and Paying Agent”, “Calculation Agent”, and “Paying Agent” include any additional or replacement Issuing and Paying Agent, Calculation Agent or Paying Agent appointed under this Condition.

In addition, the Issuer shall forthwith appoint a Paying Agent in New York City in respect of any Instruments denominated in U.S. dollars in the circumstances described in Condition 5.2.

Notice of any such change or any change of any specified office shall promptly be given to the Instrumentholders in accordance with Condition 13.

5.5

Unmatured Coupons and Receipts and unexchanged Talons

	5.5.1		Unless the Instrument provides that the relevant Coupons are to become void upon the due date for redemption of those Instruments, Instruments should be surrendered for payment together with all unmatured Coupons (if any) appertaining to them, failing which an amount equal to the face value of each missing unmatured Coupon (or, in the case of payment not being made in full, that proportion of the amount of such missing unmatured Coupon that the sum of principal so paid bears to the total principal due) will be deducted from the Final Redemption Amount, Early Redemption Amount or Optional Redemption Amount, as the case may be, due for payment. Any amount so deducted shall be paid in the manner mentioned above against surrender of such missing Coupon within a period of 10 years from the Relevant Date for the payment of such principal (whether or not such Coupon has become void pursuant to Condition 7).

	5.5.2		If the relevant Instrument so provides, upon the due date for redemption of any Instrument, unmatured Coupons relating to such Instrument (whether or not attached) shall become void and no payment shall be made in respect of them.

	5.5.3		If the relevant Instrument so provides, upon the due date for redemption of any Instrument, any unexchanged Talon relating to such Instrument (whether or not attached) shall become void and no Coupon shall be delivered in respect of such Talon.

	5.5.4		Upon the due date for redemption of any Instrument which is redeemable in instalments, all Receipts relating to such Instrument having an Instalment Date falling on or after such due date (whether or not attached) shall become void and no payment shall be made in respect of them.

	5.5.5		Where any Instrument which provides that the relevant Coupons are to become void upon the due date for redemption of those Instruments is presented for redemption without all unmatured Coupons and any unexchanged Talon relating to it, and where any Instrument is presented for redemption without any unexchanged Talon relating to it, redemption shall be made only against the provision of such indemnity as the Issuer may require.

	5.5.6		If the due date for redemption of any Instrument is not a due date for payment of interest, interest accrued from the preceding due date for payment of interest or the Interest Commencement Date, as the case may be, shall only be payable against presentation (and surrender if appropriate) of the relevant Instrument. Interest accrued on an Instrument that only bears interest after its Maturity Date shall be payable on redemption of that Instrument against presentation of that Instrument.

	5.6		Non-business days

			If any date for payment in respect of any Instrument, Receipt or Coupon is not a business day, the holder shall not be entitled to payment until the next following business day nor to any interest or other sum in respect of such postponed payment. In this paragraph, “business day” means a day (other than a Saturday or a Sunday) on which banks and foreign exchange markets are open for business in the relevant place of presentation, in such jurisdictions as shall be specified as “Financial Centres” in the relevant Final Terms and:

	5.6.1		(in the case of a payment in a currency other than Euro) where payment is to be made by transfer to an account maintained with a bank in the relevant currency, on which foreign exchange transactions may be carried on in the relevant currency in the principal financial centre of the country of such currency; or

	5.6.2		(in the case of a payment in Euro) which is a TARGET Business Day.

	5.7		Talons

			On or after the Interest Payment Date for the final Coupon forming part of a Coupon sheet issued in respect of any Instrument, the Talon forming part of such Coupon sheet may be surrendered at the specified office of the Issuing and Paying Agent in exchange for a further Coupon sheet (but excluding any Coupons which may have become void pursuant to Condition 7).

6		Taxation

		All payments of principal and interest by or on behalf of the Issuer in respect of the Instruments, the Receipts and the Coupons will be made without withholding or deduction for or on account of, any present or future taxes or duties of whatever nature imposed or levied by or on behalf of the United States of America or any political sub-division of the United States of America or any authority in or of the United States of America having power to tax, unless such withholding or deduction is compelled by law. In that event, the Issuer will pay such additional amounts of principal and interest as will result in the payment to the Instrumentholders, Receiptholders or, as the case may be, the Couponholders of the amounts which would otherwise have been receivable in respect of the Instruments, Receipts or Coupons had no withholding or deduction been made, except that no such additional amounts shall be payable in respect of any Instrument, Receipt or Coupon presented for payment:

	(a)		by or on behalf of, a person who is liable to such taxes or duties in respect of such Instrument, Receipt or Coupon by reason of his having some connection with the United States of America other than the mere holding of such Instrument, Receipt or Coupon; or

	(b)		by or on behalf of a person who would not be liable or subject to such deduction or withholding by making a declaration of non-residence or other claim for exemption to a tax authority; or

	(c)		more than 30 days after the Relevant Date except to the extent that the holder would have been entitled to such additional amounts on presenting the same for payment on such 30th day; or

	(d)		where such withholding or deduction is imposed on a payment to an individual and is required to be made pursuant to any law implementing European Council Directive 2003/48/EC or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000; or

	(e)		by a holder which is or was a controlled foreign corporation, personal holding company or passive foreign investment company with respect to the United States or a corporation that accumulates earnings to avoid United States federal income tax; or

	(f)		if such tax is an estate, inheritance, gift, sales, transfer or personal property tax or any similar tax, assessment, or governance charge; or

	(g)		by a holder which is or has been a “10 per cent. shareholder” of the obligor of the Instruments as defined in Section 871(h)(3) of the United States Internal Revenue Code or any successor provisions; or

	(h)		by or on behalf of a holder who would have been able to avoid such withholding or deduction (i) by presenting the relevant Instrument, Receipt or Coupon to another Paying Agent in a Member State of the European Union; or (ii) by satisfying any statutory or procedural requirements (including, without limitation, the provision of information); or

	(i)		in the case of any combination of items (a) to (h) above.

As used in these Conditions, “Relevant Date” in respect of any Instrument, Receipt or Coupon means the date on which payment in respect of it first becomes due or (if any amount of the money payable is improperly withheld or refused) the date on which payment in full of the amount outstanding is made or (if earlier) the date on which notice is duly given to the Instrumentholders in accordance with Condition 13 that, upon further presentation of the Instrument, Receipt or Coupon being made in accordance with the Conditions, such payment will be made, provided that payment is in fact made upon such presentation. References in these Conditions to (a) “principal” shall be deemed to include any premium payable in respect of the Instruments, all Instalment Amounts, Final Redemption Amounts, Early Redemption Amounts, Optional Redemption Amounts, Amortised Face Amounts and all other amounts in the nature of principal payable pursuant to Condition 4 or any amendment or supplement to it, (b) “interest” shall be deemed to include all Interest Amounts and all other amounts payable pursuant to Condition 3 or any amendment or supplement to it and (c) “principal” and/or “interest” shall be deemed to include any additional amounts which may be payable under this Condition or any undertaking given in addition to or in substitution for it under the Trust Deed.

7		Prescription

		Instruments, Receipts and Coupons (which, for this purpose, shall not include Talons) shall be prescribed and become void unless presented for payment within 10 years (in the case of principal) or five years (in the case of interest) from the appropriate Relevant Date in respect of them.

8		Events of Default

		If any of the following events (each an “Event of Default”) occurs and is continuing, the Trustee at its discretion may, and if so requested by the holders of at least one-quarter in nominal amount of the Instruments then outstanding or if so directed by an Extraordinary Resolution shall, give notice to the Issuer at its registered office that the Instruments are, and they shall accordingly immediately become due and repayable at their Redemption Amount together with accrued interest (if any) to the date of payment:

	(a)		Non-Payment:there is default for more than 30 days in the payment of any principal or interest due in respect of the Instruments; or

	(b)		Breach of Other Obligations:there is default in the performance or observance by the Issuer of any other obligation or provision under the Trust Deed or the Instruments (other than any obligation for the payment of any principal or interest in respect of the Instruments) which default is incapable of remedy or, if in the opinion of the Trustee capable of remedy, is not remedied within 90 days after notice of such default shall have been given to the Issuer by the Trustee; or

	(c)		Cross-Acceleration:if (i) any other present or future Relevant Indebtedness of the Issuer or a Principal Subsidiary becomes due and payable prior to its stated maturity by reason of any actual event of default or (ii) any amount in respect of such Relevant Indebtedness is not paid when due or, as the case may be, within any applicable grace period, provided that the aggregate amount of the Relevant Indebtedness in respect of which one or more of the events mentioned above in this

paragraph (c) have occurred equals or exceeds U.S.$100,000,000 for the period up to and including 31 March 2017, and thereafter U.S.$200,000,000 or

	(d)		Winding-up:a resolution is passed, or a final order of a court in the United States of America is made and, where possible, not discharged or stayed within a period of 90 days, that the Issuer be wound up or dissolved; or

	(e)		Enforcement Proceedings:attachment is made of the whole or substantially the whole of the assets or undertakings of the Issuer and such attachment is not released or cancelled within 90 days or an encumbrancer takes possession or an administrative or other receiver or similar officer is appointed of the whole or substantially the whole of the assets or undertaking of the Issuer or an administration or similar order is made in relation to the Issuer and such taking of possession, appointment or order is not released, discharged or cancelled within 90 days; or

	(f)		Insolvency:the Issuer ceases to carry on all or substantially all of its business or is unable to pay its debts; or

	(g)		Bankruptcy:the Issuer is adjudged bankrupt or insolvent by a court of competent jurisdiction in the United States of America,

provided that in the case of paragraph (b) the Trustee shall have certified that in its opinion such event is materially prejudicial to the interests of the Instrumentholders.

For the purposes of this Condition 8, “Principal Subsidiary” means KeySpan Corporation, KeySpan Energy Delivery New York, KeySpan Energy Delivery Long Island, Niagara Mohawk Power Corporation and New England Power Company, and includes any successor entity thereto or any member of the group of companies comprising National Grid USA and each of its subsidiaries (the “Group”) which the Auditors have certified to the Trustee as being a company to which all or substantially all of the assets of a Principal Subsidiary are transferred. In the event that all or substantially all of the assets of a Principal Subsidiary are transferred to a member of the Group as described above, the transferor of such assets shall cease to be deemed to be a Principal Subsidiary for the purposes of this Condition.

9		Enforcement

		The Trustee may, at its discretion and without further notice, institute such proceedings against the Issuer as it may think fit to enforce any obligation, condition or provision binding on the Issuer under the Instruments or under the Trust Deed, but shall not be bound to do so unless:

	(a)		it has been so directed by an Extraordinary Resolution or in writing by the holders of at least one-quarter of the principal amount of the Instruments outstanding; and

	(b)		it has been indemnified to its satisfaction.

No Instrumentholder, Receiptholder or Couponholder shall be entitled to institute proceedings directly against the Issuer unless the Trustee, having become bound to proceed as specified above, fails to do so within a reasonable time and such failure is continuing.

Meetings of Instrumentholders, Modifications and Substitution

	10.1		Meetings of Instrumentholders

			The Trust Deed contains provisions for convening meetings of Instrumentholders to consider any matter affecting their interests, including the sanctioning by Extraordinary Resolution (as defined in the Trust Deed) of a modification of any of these Conditions or any provisions of the Trust Deed. An Extraordinary Resolution duly passed at any such meeting shall be binding on Instrumentholders (whether or not they were present at the meeting at which such resolution was passed) and on all Couponholders, except that any Extraordinary Resolution proposed,inter alia,

(a) to amend the dates of maturity or redemption of the Instruments, any Instalment Date or any date for payment of interest on the Instruments, (b) to reduce or cancel the nominal amount of, or any Instalment Amount of, or any premium payable on redemption of, the Instruments, (c) to reduce the rate or rates of interest in respect of the Instruments or to vary the method or basis of calculating the rate or rates or amount of interest or the basis for calculating any Interest Amount in respect of the Instruments, (d) if a Minimum and/or a Maximum Rate of Interest is shown on the face of the Instrument, to reduce any such Minimum and/or Maximum Rate of Interest, (e) to vary any method of calculating the Final Redemption Amount, the Early Redemption Amount or the Optional Redemption Amount, (f) to take any steps that as specified in this Instrument may only be taken following approval by an Extraordinary Resolution to which the special quorum provisions apply, and (g) to modify the provisions concerning the quorum required at any meeting of Instrumentholders or the majority required to pass the Extraordinary Resolution will only be binding if passed at a meeting of the Instrumentholders (or at any adjournment of that meeting) at which a special quorum (as defined in the Trust Deed) is present. A resolution in writing signed by the holders of not less than 95 per cent. in nominal amount of the Instruments will be binding on all Instrumentholders and Couponholders. The Issuer may convene a meeting of Instrumentholders jointly with the holders of all other instruments issued pursuant to the Agency Agreement and not forming a single series with the Instruments to which meeting the provisions referred to above apply as if all such instruments formed part of the same series, provided that the proposals to be considered at such meeting affect the rights of the holders of the instruments of each series attending the meeting in identical respects (save insofar as the Conditions applicable to each such series are not identical).

	10.2		Modification of the Trust Deed

			The Trustee may agree, without the consent of the Instrumentholders or Couponholders, to (a) any modification of any of the provisions of the Trust Deed that is of a formal, minor or technical nature or is made to correct a manifest error, and (b) any other modification (except as mentioned in the Trust Deed), and any waiver or authorisation of any breach or proposed breach, of any of the provisions of the Trust Deed that is in the opinion of the Trustee not materially prejudicial to the interests of the Instrumentholders. Any such modification, authorisation or waiver shall be binding on the Instrumentholders and the Couponholders and, if the Trustee so requires, such modification shall be notified to the Instrumentholders as soon as practicable.

	10.3		Substitution

			The Trust Deed contains provisions permitting the Trustee to agree, subject to such amendment of the Trust Deed and such other conditions as the Trustee may require, but without the consent of the Instrumentholders or the Couponholders, to the substitution of any other company in place of the Issuer or of any previous substituted company, as principal debtor under the Trust Deed and the Instruments. In the case of such a substitution the Trustee may agree, without the consent of the Instrumentholders or the Couponholders, to a change of the law governing the Instruments, the Receipts, the Coupons, the Talons and/or the Trust Deed provided that such change would not in the opinion of the Trustee be materially prejudicial to the interests of the Instrumentholders.

	10.4		Entitlement of the Trustee

			In connection with the exercise of its functions (including but not limited to those referred to in this Condition) the Trustee shall have regard to the interests of the Instrumentholders as a class and shall not have regard to the consequences of such exercise for individual Instrumentholders or Couponholders and the Trustee shall not be entitled to require, nor shall any Instrumentholder or Couponholder be entitled to claim, from the Issuer any indemnification or payment in respect of any tax consequence of any such exercise upon individual Instrumentholders or Couponholders.

11		Replacement of Instruments, Receipts, Coupons and Talons

		If an Instrument, Receipt, Coupon or Talon is lost, stolen, mutilated, defaced or destroyed, it may be replaced, subject to applicable laws, listing authority and stock exchange regulations, at the specified office of such other Paying Agent as may from time to time be designated by the Issuer for the purpose and notice of whose designation is given to Instrumentholders in accordance with Condition 13 on payment by the claimant of the fees and costs incurred in connection with that replacement and on such terms as to evidence, security and indemnity (which may provide,inter alia, that if the allegedly lost, stolen or destroyed Instrument, Receipt, Coupon or Talon is subsequently presented for payment or, as the case may be, for exchange for further Coupons, there shall be paid to the Issuer on demand the amount payable by the Issuer in respect of such Instruments, Receipts, Coupons or further Coupons) and otherwise as the Issuer may require. Mutilated or defaced Instruments, Receipts, Coupons or Talons must be surrendered before replacements will be issued.

12		Further Issues

		The Issuer may from time to time without the consent of the Instrumentholders or Couponholders create and issue further instruments having the same terms and conditions as the Instruments and so that such further issue shall be consolidated and form a single series with such Instruments.

		References in these Conditions to the Instruments include (unless the context requires otherwise) any other instruments issued pursuant to this Condition and forming a single series with the Instruments. Any such further instruments forming a single series with Instruments constituted by the Trust Deed or any deed supplemental to it shall, and any other instruments may (with the consent of the Trustee), be constituted by the Trust Deed.

		The Trust Deed contains provisions for convening a single meeting of the Instrumentholders and the holders of instruments of other series if the Trustee so decides.

13		Notices

		All notices to the Instrumentholders will be valid if published in a daily English language newspaper of general circulation in the United Kingdom (which is expected to be theFinancial Times). If in the opinion of the Trustee any such publication is not practicable, notice shall be validly given if published in another leading daily English language newspaper with general circulation in Europe. Any such notice shall be deemed to have been given on the date of such publication or, if published more than once or on different dates, on the first date on which publication is made, as provided above.

		Couponholders shall be deemed for all purposes to have notice of the contents of any notice given to the holders of Instruments in accordance with this Condition.

14		Indemnification of Trustee

		The Trust Deed contains provisions for the indemnification of the Trustee and for its relief from responsibility, including but not limited to provisions relieving it from any obligation to (a) appoint an independent financial adviser and (b) take proceedings to enforce repayment unless indemnified to its satisfaction. The Trustee is entitled to enter into business transactions with the Issuer or any of its subsidiary undertakings, parent undertakings, joint ventures or associated undertakings without accounting for any profit resulting from these transactions and to act as trustee for the holders of any other securities issued by the Issuer or any of its subsidiary undertakings, parent undertakings, joint ventures or associated undertakings.

15		Contracts (Rights of Third Parties) Act 1999

		No person shall have any right to enforce any term or condition of the Instruments under the Contracts (Rights of Third Parties) Act 1999.

Governing Law and Jurisdiction

	16.1		Governing Law

			The Instruments and all matters arising from or connected with the Instruments are governed by, and shall be construed in accordance with, English law.

	16.2		Jurisdiction

			The courts of England have exclusive jurisdiction to settle any dispute (a “Dispute”), arising from or connected with the Instruments. The Issuer agrees that the courts of England are the most appropriate and convenient courts to settle any Dispute and, accordingly, that it will not argue to the contrary. Nothing in this Condition 16 prevents the Trustee or any Instrumentholder from taking proceedings relating to a Dispute (“Proceedings”) in any other courts with jurisdiction. To the extent allowed by law, the Trustee or Instrumentholders may take concurrent Proceedings in any number of jurisdictions.

	16.3		Process Agent

			The Issuer has irrevocably appointed National Grid plc at its registered office for the time being, currently at 1-3 Strand, London WC2N 5EH as its agent in England to receive, for it and on its behalf, service of process in any Proceedings in England. Nothing herein or in the Trust Deed shall affect the right to serve process in any other manner permitted by law.

SUMMARY OF PROVISIONS RELATING TO THE INSTRUMENTS
WHILE IN GLOBAL FORM

Initial Issue of Instruments

Upon the initial deposit of a Global Instrument with a common depositary for Euroclear and Clearstream, Luxembourg (the “Common Depositary”), Euroclear or Clearstream, Luxembourg will credit each subscriber with a nominal amount of Instruments equal to the nominal amount of those Instruments for which it has subscribed and paid.

If the Global Instruments are stated in the applicable Final Terms to be issued in NGN form, they are intended to be eligible collateral for Eurosystem monetary policy and the Global Instruments will be delivered on or prior to the original issue date of the Tranche to a Common Safekeeper. Depositing the Global Instruments with the Common Safekeeper does not necessarily mean that the Instruments will be recognised as eligible collateral for Eurosystem monetary policy and intra-day credit operations by the Eurosystem either upon issue, or at any or all times during their life. Such recognition will depend upon satisfaction of the Eurosystem eligibility criteria.

Global Instruments which are issued in CGN form may be delivered on or prior to the original issue date of the Tranche to a Common Depositary.

If the Global Instrument is a CGN, upon the initial deposit of a Global Instrument with the Common Depositary, Euroclear or Clearstream, Luxembourg will credit each subscriber with a nominal amount of Instruments equal to the nominal amount of those Instruments for which it has subscribed and paid. If the Global Instrument is an NGN, the nominal amount of the Instruments shall be the aggregate amount from time to time entered in the records of Euroclear or Clearstream, Luxembourg. The records of such clearing system shall be conclusive evidence of the nominal amount of Instruments represented by the Global Instrument and a statement issued by such clearing system at any time shall be conclusive evidence of the records of the relevant clearing system at that time.

Instruments which are initially deposited with the Common Depositary may also be credited to the accounts of subscribers with (if indicated in the relevant Final Terms) other clearing systems through direct or indirect accounts with Euroclear and Clearstream, Luxembourg held by such other clearing systems. Conversely, Instruments that are initially deposited with another clearing system may similarly be credited to the accounts of subscribers with Euroclear, Clearstream, Luxembourg or other clearing systems.

Relationship of Accountholders with Clearing Systems

Each of the persons shown in the records of Euroclear, Clearstream, Luxembourg or any other clearing system as the holder of an Instrument represented by a Global Instrument must look solely to Euroclear, Clearstream, Luxembourg or such clearing system (as the case may be) for his share of each payment made by the Issuer to the bearer of such Global Instrument and in relation to all other rights arising under the Global Instruments, subject to and in accordance with the respective rules and procedures of Euroclear, Clearstream, Luxembourg or such clearing systems (as the case may be). Such persons shall have no claim directly against the Issuer in respect of payments due on the Instruments for so long as the Instruments are represented by such Global Instrument and such obligations of the Issuer will be discharged by payment to the bearer of such Global Instrument in respect of each amount so paid.

The Trustee may call for any certificate or other document to be issued by Euroclear, Clearstream, Luxembourg or any other clearing system as to the principal amount of Instruments represented by a Global Instrument standing to the account of any person. Any such certificate or other document shall, in the absence of manifest error, be conclusive and binding for all purposes. Any such certificate or other

document may comprise any form of statement or print out of electronic records provided by the relevant clearing system (including Euroclear’s EUCLID or Clearstream, Luxembourg’s Cedcom system) in accordance with its usual procedures and in which the holder of a particular principal amount of any other clearing system is clearly identified together with the amount of such holding. The Trustee shall not be liable to any person by reason of having accepted as valid or not having rejected any certificate or other document to such effect purporting to be issued by Euroclear, Clearstream, Luxembourg or any other clearing system and subsequently found to be forged or not authentic.

Exchange

1		Temporary Global Instruments

		Each temporary Global Instrument will be exchangeable, free of charge to the holder, on or after its Exchange Date:

	1.1		if the relevant Final Terms indicates that such Global Instrument is issued in compliance with the C Rules or in a transaction to which TEFRA is not applicable (as to which, see “Summary of the Programme — Selling Restrictions”), in whole, but not in part, for the Definitive Instruments defined and described below; and

	1.2		otherwise, in whole or in part upon certification as to non-U.S. beneficial ownership in the form set out in the Agency Agreement for interests in a permanent Global Instrument or, if so provided in the relevant Final Terms, for Definitive Instruments.

2		Permanent Global Instruments

		Each permanent Global Instrument will be exchangeable, free of charge to the holder, on or after its Exchange Date in whole but not, except as provided under “Partial Exchange of Permanent Global Instruments”, in part for Definitive Instruments (i) if the holder of an Instrument gives notice to the Issuing and Paying Agent of its election for such exchange and (ii) otherwise, if the permanent Global Instrument is held on behalf of Euroclear or Clearstream, Luxembourg or any other clearing system (an “Alternative Clearing System”) and any such clearing system is closed for business for a continuous period of 14 days (other than by reason of holidays, statutory or otherwise) or announces an intention permanently to cease business or in fact does so.

3		Partial Exchange of Permanent Global Instruments

		For so long as a permanent Global Instrument is held on behalf of a clearing system and the rules of that clearing system permit, such permanent Global Instrument will be exchangeable in part on one or more occasions for Definitive Instruments (a) if principal in respect of any Instruments is not paid when due or (b) if so provided in, and in accordance with, the Conditions (which will be set out in the relevant Final Terms) relating to Partly Paid Instruments.

4		Delivery of Instruments

		If the Global Instrument is a CGN, on or after any due date for exchange the holder of a Global Instrument may surrender such Global Instrument or, in the case of a partial exchange, present it for endorsement to or to the order of the Issuing and Paying Agent. In exchange for any Global Instrument, or the part of that Global Instrument to be exchanged, the Issuer will (a) in the case of a temporary Global Instrument exchangeable for a permanent Global Instrument, deliver, or procure the delivery of, a permanent Global Instrument in an aggregate nominal amount equal to that of the whole or that part of a temporary Global Instrument that is being exchanged or, in the case of a subsequent exchange, endorse, or procure the endorsement of, a permanent Global Instrument to reflect such exchange or (b) in the case of a Global Instrument exchangeable for Definitive Instruments, deliver, or procure the delivery of, an equal aggregate nominal amount of duly executed and authenticated Definitive

		Instruments or if the Global Instrument is a NGN, the Issuer will procure that details of such exchange be enteredpro ratain the records of the relevant clearing system. In this Prospectus, “Definitive Instruments” means, in relation to any Global Instrument, the Definitive Instruments for which such Global Instrument may be exchanged (if appropriate, having attached to them all Coupons and Receipts in respect of interest or Instalment Amounts that have not already been paid on the Global Instrument and a Talon). Definitive Instruments will be security printed in accordance with any applicable legal and stock exchange requirements in or substantially in the form set out in the Schedules to the Trust Deed. On exchange in full of each permanent Global Instrument, the Issuer will, if the holder so requests, procure that it is cancelled and returned to the holder together with the relevant Definitive Instruments.

5		Exchange Date

		“Exchange Date” means, in relation to a temporary Global Instrument, the day falling after the expiry of 40 days after its issue date and, in relation to a permanent Global Instrument, a day falling not less than 60 days, or in the case of failure to pay principal in respect of any Instruments when due 30 days, after that on which the notice requiring exchange is given and on which banks are open for business in the city in which the specified office of the Issuing and Paying Agent is located and in the city in which the relevant clearing system is located.

6		Amendment to Conditions

		The temporary Global Instruments and permanent Global Instruments contain provisions that apply to the Instruments which they represent, some of which modify the effect of the terms and conditions of the Instruments set out in this Prospectus. The following is a summary of certain of those provisions:

7		Payments

		No payment falling due after the Exchange Date will be made on any Global Instrument unless exchange for an interest in a permanent Global Instrument or for Definitive Instruments is improperly withheld or refused. Payments on any temporary Global Instrument issued in compliance with the D Rules before the Exchange Date will only be made against presentation of certification as to non-U.S. beneficial ownership in the form set out in the Agency Agreement. All payments in respect of Instruments represented by a Global Instrument will be made against presentation for endorsement and, if no further payment falls to be made in respect of the Instruments, surrender of that Global Instrument to or to the order of the Issuing and Paying Agent or such other Paying Agent as shall have been notified to the Instrumentholders for such purpose. If the Global Instrument is a CGN, a record of each payment so made will be endorsed on each Global Instrument, which endorsement will beprima facieevidence that such payment has been made in respect of the Instruments. If the Global Instrument is a NGN, the Issuer shall procure that details of each such payment shall be enteredpro ratain the records of the relevant clearing system and in the case of payments of principal, the nominal amount of the Instruments recorded in the records of the relevant clearing system and represented by the Global Instrument will be reduced accordingly. Payments under the NGN will be made to its holder. Each payment so made will discharge the Issuer’s obligations in respect thereof. Any failure to make the entries in the records of the relevant clearing system shall not affect such discharge.

8		Prescription

		Claims against the Issuer in respect of Instruments which are represented by a permanent Global Instrument will become void unless it is presented for payment within a period of 10 years (in the case of principal) and five years (in the case of interest) from the appropriate Relevant Date (as defined in Condition 6).

9		Meetings

		The holder of a permanent Global Instrument shall (unless such permanent Global Instrument represents only one Instrument) be treated as being two persons for the purposes of any quorum requirements of a meeting of Instrumentholders and, at any such meeting, as having one vote in respect of each integral currency unit of the Specified Currency of the Instruments for which it may be exchanged in accordance with its terms.

10		Cancellation

		Cancellation of any Instrument represented by a permanent Global Instrument which is required by the Conditions to be cancelled (other than upon its redemption) will be effected by reduction in the nominal amount of the relevant permanent Global Instrument.

11		Purchase

		Instruments represented by a permanent Global Instrument may only be purchased by the Issuer or any of its subsidiary undertakings if they are purchased together with the right to receive all future payments of interest and Instalment Amounts (if any) on those Instruments.

12		Issuer’s Option

		Any option of the Issuer provided for in the Conditions of any Instruments while such Instruments are represented by a permanent Global Instrument shall be exercised by the Issuer giving notice to the Instrumentholders within the time limits set out in and containing the information required by the Conditions, except that the notice shall not be required to contain the serial numbers of Instruments drawn in the case of a partial exercise of an option and accordingly no drawing of Instruments shall be required. In the event that any option of the Issuer is exercised in respect of some but not all of the Instruments of any Series, the rights of accountholders with a clearing system or Approved Intermediary in respect of the Instruments will be governed by the standard procedures of Euroclear and/or Clearstream, Luxembourg (to be reflected in the records of Euroclear and Clearstream, Luxembourg as either a pool factor or a reduction in nominal amount, at their discretion) or any other Alternative Clearing System (as the case may be).

13		Instrumentholders’ Options

		Any option of the Instrumentholders provided for in the Conditions of any Instruments while such Instruments are represented by a permanent Global Instrument may be exercised by the holder of the permanent Global Instrument giving notice to the Issuing and Paying Agent within the time limits relating to the deposit of Instruments with a Paying Agent set out in the Conditions substantially in the form of the notice available from any Paying Agent stating the nominal amount of Instruments in respect of which the option is exercised and at the same time, where the permanent Global Instrument is a CGN, presenting the permanent Global Instrument for notation. Where the Global Instrument is an NGN, the Issuer shall procure that details of such exercise shall be enteredpro ratain the records of the relevant clearing system and the nominal amount of the Instruments recorded in those records will be reduced accordingly.

14		NGN nominal amount

		Where the Global Note is a NGN, the Issuer shall procure that any exchange, payment, cancellation, exercise of any option or any right under the Instruments, as the case may be, in addition to the circumstances set out above shall be entered in the records of the relevant clearing systems and upon any such entry being made, in respect of payments of principal, the nominal amount of the Instruments represented by such Global Instrument shall be adjusted accordingly.

15		Trustee’s Powers

		In considering the interests of Instrumentholders while any Global Instrument is held on behalf of a clearing system, the Trustee may have regard to any information provided to it by such clearing system or its operator as to the identity (either individually or by category) of its accountholders with entitlements to such Global Instrument and may consider such interests as if such accountholders were the holders of the Instruments represented by such Global Instrument.

16		Events of Default

		Each Global Instrument provides that the Trustee, at its discretion, may, and if so requested by holders of at least one-quarter in nominal amount of the Instruments then outstanding or if so directed by an Extraordinary Resolution, shall cause such Global Instrument to become due and repayable in the circumstances described in Condition 8 by stating in the notice to the Issuer the principal amount of such Global Instrument which is becoming due and repayable. If principal in respect of any Instrument is not paid when due, only the Trustee may enforce the rights of the Instrumentholders against such Issuer under the terms of the Trust Deed unless the Trustee, having become bound to proceed, fails to do so within a reasonable time and such failure is continuing.

17		Notices

		So long as any Instruments are represented by a Global Instrument and such Global Instrument is held on behalf of a clearing system, notices to the holders of Instruments of that Series may be given by delivery of the relevant notice to that clearing system for communication by it to entitled accountholders in substitution for publication as required by the Conditions or by delivery of the relevant notice to the holder of the Global Instrument.

18		Partly Paid Instruments

		The provisions relating to Partly Paid Instruments are not set out in this Prospectus, but will be contained in the relevant Final Terms and so in the Global Instruments. While any instalments of the subscription moneys due from the holder of Partly Paid Instruments are overdue, no interest in a Global Instrument representing such Instruments may be exchanged for an interest in a permanent Global Instrument or for Definitive Instruments (as the case may be). If any Instrumentholder fails to pay any instalment due on any Partly Paid Instruments within the time specified, the Issuer may forfeit such Instruments and shall have no further obligation to their holder in respect of them.

USE OF PROCEEDS

The net proceeds of the issue of each Series of Instruments will be used by the Issuer for its general corporate purposes. If in respect of any particular issue of Instruments, there is a particular identified use of proceeds, this will be stated in the applicable Final Terms.

DESCRIPTION OF NATIONAL GRID USA

Overview

National Grid USA is an indirect wholly owned U.S. subsidiary of National Grid plc, a London based international network utility with principal activities in the regulated electric and gas industries. As used in this description, unless the context requires otherwise, National Grid USA or the “Issuer”, refer to National Grid USA and its principal public utility subsidiaries. National Grid USA is the U.S. public utility holding company of various U.S. electric and gas subsidiaries in the National Grid plc system. National Grid USA’s assets primarily consist of shares of the U.S. public utility companies acquired, over time, pursuant to several merger and acquisition transactions, including, most recently, KeySpan Corporation in August 2007. National Grid USA does not conduct any business other than through its U.S. subsidiaries and is accordingly dependent on revenue received from its U.S. subsidiaries’ core businesses, which are the delivery of electricity and gas. National Grid USA, through its subsidiaries and their predecessors, has been serving various portions of New York and New England since the mid-1800s.

National Grid USA was incorporated in the State of Delaware on 10 December 1998 under the General Corporation Laws of the State of Delaware with file number 2977161. The address of National Grid USA is 25 Research Drive, Westborough, MA 01582 and its telephone number is +1-508-389-2000.

Introduction

National Grid USA’s principal operations are in regulated networks and comprise the transmission and distribution of electricity and gas based in the United States. The Issuer also owns, leases and operates electric generating facilities in New York State and has interests in electricity interconnectors in the United States.

Business overview

Principal activities and markets

National Grid USA’s principal businesses are:

	•		Electricity Transmission;

	•		Gas distribution;

	•		Electricity distribution; and

	•		Non-regulated businesses.

National Grid USA’s London based parent, National Grid plc, owns businesses that operate in both the United States and the United Kingdom. As a consequence of the respective economic and regulatory environments, performance of these U.S. businesses is reported by National Grid plc by segment reflecting the management responsibilities and economic characteristics of each of these operating activities. National Grid USA’s segments as reported by National Grid plc are:

	•		Electricity Transmission – U.S.;

	•		Gas Distribution – U.S.;

	•		Electricity Distribution – U.S.; and

	•		U.S. stranded cost recoveries.

National Grid USA’s principal public utility subsidiaries are as follows:

•

KeySpan Corporation (collectively “KeySpan”) directly and indirectly owned public utilities consisting of:

	•		The Brooklyn Union Gas d/b/a/ KeySpan Energy Delivery New York (“KEDNY”) – New York;

	•		KeySpan Gas East Corporation d/b/a KeySpan Energy Delivery Long Island (“KEDLI”) – New York;

	•		Colonial Gas Company – New England;

	•		Boston Gas Company – New England;

	•		Essex Gas Company – New England; and

	•		EnergyNorth Natural Gas, Inc. – New England;

	•		Niagara Mohawk Power Corporation (“NMPC”) – New York;

	•		New England Power Company (“NEP”) – New England;

	•		Massachusetts Electric Company (“MECO”) – Massachusetts;

	•		The Narragansett Electric Company (“Narragansett”) – Rhode Island

	•		Granite State Electric Company (“Granite State”) – New Hampshire

	•		Nantucket Electric Company (“NEC”) – Massachusetts

	•		New England Electric Transmission Corporation (“NEET”) – Massachusetts and New Hampshire;

	•		New England Hydro-Transmission Corporation (“N.H. Hydro”) – New Hampshire; and

	•		New England Hydro-Transmission Electric Company, Inc. (“Mass. Hydro”) – Massachusetts.

National Grid USA’s principal electric transmission and distribution subsidiaries provide the following services: (i) electricity transmission and distribution in New York through NMPC; (ii) electricity transmission in New England principally through NEP; and (iii) electricity distribution in New England through MECO, Narragansett, Granite State and NEC. National Grid USA’s principal gas distribution subsidiaries provide gas distribution in central and eastern New York through NMPC, and in downstate New York and in New England through KeySpan’s gas utility affiliates and through Narragansett in Rhode Island. In addition to the Issuer’s regulated networks for the transmission and distribution of electricity and gas, National Grid USA’s KeySpan affiliates (i) manage the electric transmission and distribution system in Long Island, New York owned by the Long Island Power Authority (“LIPA”); (ii) provide generating capacity and, to the extent required, energy conversion services for LIPA; (iii) own and/or, lease and operate an electric generation facility located in Queens County, New York City collectively known as the Ravenswood Facility or Ravenswood Generating Station which is expected to be divested in accordance with the recent New York Public Service Commission’s (“NYPSC”) merger order dated 17 September 2007; (iv) provide energy-related and fibre optic services to customers primarily located within the northeast of the United States, with concentrations in the New York City and Boston metropolitan areas; and (v) operate gas exploration and production activities as well as domestic pipelines and gas storage facilities.

Electricity Transmission

The Issuer owns and operates an electricity transmission network, excluding the managed LIPA facilities, of approximately 8,600 miles spanning upstate New York, Massachusetts, Rhode Island, New Hampshire and Vermont. National Grid USA’s U.S. transmission facilities operate at voltages ranging from 69 kV to 345kV, utilising nearly 8,500 miles of overhead lines, 89 miles of underground cable and 501 substations. The Issuer is the largest electricity transmission service provider in the northeast of the United States, by reference to the length of these high-voltage transmission lines. In addition, as referenced below, the Issuer owns and operates a 139-mile direct current transmission line rated at 450 kV that is a key section of an interconnector between New England and Canada.

In New England and New York, the Issuer’s transmission business, managed as part of National Grid plc’s international transmission business, operates within two independent system operators (“ISOs”), ISO – New England and ISO – New York. These non-profit entities are the system operators for the New England and New York transmission networks. The ISOs are responsible for operating organised wholesale markets for energy, operating reserves and capacity; for maintaining the operating reliability of the New England and New York transmission networks; for co-ordinating the activities of the transmission owners; and for managing transparent transmission expansion planning processes.

The Issuer is one of several transmission owners operating within each of these ISOs. The transmission owners are responsible for certain aspects of the operation of the transmission facilities they each own, such as maintenance, equipment restoration and switching operations. The Issuer works closely with the ISOs in New England and New York to support efficient market and network operations and transmission investment.

Gas Distribution

National Grid USA’s gas distribution businesses in upstate New York, Massachusetts, and Rhode Island, prior to the acquisition of KeySpan, provided services to 571,000 customers in 216 communities across upstate New York through NMPC and 248,000 customers in 33 communities in Rhode Island through Narragansett. With the recent acquisition of KeySpan, the largest distributor of gas in the northeast of the United States, the Issuer now provides gas distribution services to approximately 2.6 million additional gas customers located in downstate New York, Massachusetts, and New Hampshire. National Grid USA’s gas distribution companies network, prior to the KeySpan acquisition, was 11,800 miles of gas pipelines in upstate New York and Rhode Island, which covered approximately 5,460 square miles. The gas distribution, transmission and storage systems owned and operated by KeySpan businesses have increased the Issuer’s gas network by approximately 23,336 miles of gas mains and distribution pipelines. Additionally, through assets acquired in the KeySpan acquisition, National Grid USA is now capable of supplementing its winter supply portfolio with peaking supplies that are available on the coldest days of the year to economically meet the increased requirements of its heating customers. These peaking supplies include various liquefied natural gas (“LNG”) interests and operations, including local production plants that store LNG and liquid propane until vaporised, which are located strategically across National Grid USA’s service territories in New York, New Hampshire, Rhode Island and Massachusetts.

National Grid USA’s gas distribution operations provide the core services of operation and emergency response, as well as billing, customer service, and supply services. Except for residential and small business customers in Rhode Island, customers may purchase their supply from independent providers, with the option of having billing services for those purchases provided

by the Issuer’s gas distribution companies. The majority of gas supplied to customers in the United States is still sold by local regulated utilities to their customers. Regulated utilities, such as National Grid USA’s gas distribution operations, purchase gas from gas producers and gas transporters, then transport this gas on the independent interstate pipeline system and into regulated utilities’ gas distribution networks for delivery to customers. National Grid USA’s gas distribution companies receive gas from the inter-state pipeline system at various gate stations of the Issuer’s gas distribution companies. The interstate pipeline system and local gas distribution networks are also used to deliver gas on behalf of customers who have purchased gas from independent suppliers or direct from gas producers.

National Grid USA’s gas delivery rates comprise a combination of a per customer charge, a demand charge, and a price per additional therm of gas delivered. The allocation between these components varies by size of customer.

New York

In New York, the NYPSC sets gas delivery rates to recover estimates of operating costs, capital investment, and an allowed rate of return inclusive of a return on equity depending on the achievement of certain customer related performance metrics. Gas commodity costs are generally fully recovered from customers, subject to NYPSC review and approval. An adjustment to certain customer bills is made during the months of October to May to cap the Issuer’s exposure to sales variations caused by weather. The current gas rate structure of each of the Issuer’s KeySpan companies includes a gas adjustment clause pursuant to which variations between actual gas costs incurred and gas costs billed are deferred and subsequently refunded to or collected from firm customers.

The Issuer also has a number of service standards for the Issuer’s New York companies, MECo, and Narragansett, which are subject to penalties for non-achievement, including: the maximum rate of customer complaints to the state regulator; minimum satisfaction rates for residential, commercial and industrial customer billing and service transactions; minimum percentage of meters actually read compared to readings scheduled; minimum percentage of customer calls answered within 30 seconds; minimum enrolment of customers into the low income customer assistance programme; maximum number of outstanding gas leaks requiring repair measured on 31 December of each year; maximum number of reportable incidents resulting from the Issuer’s failure to respond to a request to mark the Issuer’s facilities in 48 hours; and cathodically protecting an agreed-upon mileage of pre-1971 installed wrapped steel gas main.

The Issuer’s New York gas distribution operations are also measured on the Issuer’s performance in responding to gas emergency calls within 30, 45 and 60 minutes without associated financial penalties.

Gas supplies required to meet the needs of the Issuer’s gas customers’ winter demands for gas are purchased under long and short-term firm contracts, as well as on the spot market. Gas supplies purchased by the Issuer for its customers are transported by interstate pipelines under long term contracts with interstate pipeline companies from domestic and Canadian supply basins. Gas peaking supplies are also available to meet National Grid USA’s system requirements on the coldest days of the winter season. In addition to long term pipeline contracts, the Issuer also has available seasonal firm transportation pipeline contracts and various long-term contracts for underground storage capacity.

Massachusetts and New Hampshire

National Grid USA’s Massachusetts gas utility operations are subject to Massachusetts’ statutes applicable to gas utilities. Rates for gas sales and transportation service, distribution safety practices, issuance of securities and affiliate transactions are regulated by the Massachusetts Department of Public Utilities (“MDPU”). The MDPU also has service quality standards for both electric and gas utilities. National Grid USA’s New Hampshire gas utility operations are subject to New Hampshire’s statutes applicable to gas utilities. Rates for gas sales and transportation service, distribution safety practices, issuance of securities and affiliate transactions are regulated by the New Hampshire Public Utilities Commission (“NHPUC”).

Gas supplies required to meet the needs of the Issuer’s New England customers’ winter demands for gas are purchased under long and short-term firm contracts, as well as on the spot market. Gas supplies purchased by the Issuer for its customers are transported by interstate pipelines under long term contracts with interstate pipeline companies from domestic and Canadian supply basins. Gas peaking supplies are also available to meet the Issuer’s system requirements on the coldest days of the winter season. In addition to long term pipeline contracts, the Issuer also has available seasonal firm transportation pipeline contracts and various long-term contracts for underground storage capacity. The current gas rate structure of each of the Massachusetts and New Hampshire based gas distribution utilities includes a gas adjustment clause pursuant to which variations between actual gas costs incurred and gas costs billed are deferred and subsequently refunded to or collected from firm customers.

Rhode Island

In Rhode Island, delivery rates are set to recover estimates of operating costs, capital investment and an allowed rate of return. Gas commodity rates are adjusted every November, subject to approval by the state regulator, and they are also adjusted whenever a significant over- or under-collection of gas costs is expected. Gas commodity costs are fully recovered from customers. There is also a surcharge mechanism that allows for the recovery of environmental response costs, any recovery or returns to customers as a result of a weather normalisation clause, a sharing of non-firm margins (non-firm margin earned from interruptible customers with the ability to switch to alternative fuels), and a portion of earnings in excess of an 11.25 per cent. return on equity.

The public utility commission in Rhode Island has established a number of service standards with associated non-achievement penalties, including: a benchmark percentage of abandoned customer calls and a benchmark percentage of calls answered within 60 seconds; a benchmark percentage of meters read during their normal read cycle; testing a predetermined amount of gas meters on an annual basis, as well as a benchmark percentage of meter testing initiated by customer request; meeting a benchmark percentage of customer service appointments; and benchmarks for responding to gas emergency calls within 30 minutes or less during normal working hours and 45 minutes or less after hours.

Electricity Distribution

National Grid USA operates National Grid plc’s United States electricity distribution business. The United States electricity distribution business for National Grid plc’s financial reporting purposes is split into two segments:

	•		Electricity Distribution

	•		United States and United States stranded cost recoveries.

National Grid USA’s electricity distribution system operates in upstate New York through NMPC and in Massachusetts, Rhode Island and New Hampshire through MECO, Narragansett, Granite State

and NEC, with customers that include domestic homes and small and large commercial and industrial enterprises. The Issuer is one of the leading electricity distribution service providers in the northeast of the United States, as measured by energy delivered, and one of the largest utilities in the United States, as measured by the number of electricity distribution customers. National Grid USA’s United States electricity distribution business, excluding KeySpan’s management and operation of LIPA described below, serves approximately 3.4 million electricity customers over a network of 71,000 circuit miles in New England and New York.

National Grid USA’s primary business drivers are the long-term rate plans with state regulators for the Issuer’s utility subsidiaries. These plans provide incentive returns and shared savings allowances, which allow us an opportunity to benefit from efficiency gains that the Issuer may identify and achieve within the operations of its subsidiaries.

The Issuer recovers its costs of providing electricity to customers through delivery rates approved by applicable regulators, which are based on historical or forecasted costs, and which include a return on the Issuer’s assets. The cost of the electricity supplied is passed through to customers. The Issuer’s businesses are also subject to service quality standards in New York, Massachusetts, and Rhode Island with respect to reliability and certain aspects of customer service and safety.

Long Island Power Authority

LIPA is a corporate municipal instrumentality and a political subdivision of the State of New York. On 28 May 1998, certain of the Long Island Lighting Company’s (“LILCO’s”) business units were merged with KeySpan and LILCO’s common stock and remaining assets were acquired by LIPA. Also effective on that date, KeySpan and LIPA entered into three major long-term service agreements that (i) provide to LIPA all operation, maintenance and construction services and significant administrative services relating to the Long Island electric transmission and distribution (“T&D”) system pursuant to a Management Services Agreement (the “1998 MSA”); (ii) supply LIPA with electric generating capacity, energy conversion and ancillary services from the Issuer’s Long Island generating units pursuant to a Power Supply Agreement (the “1998 PSA”) and other long-term agreements through which the Issuer provides LIPA with approximately one half of its customers’ energy needs; and (iii) manage all aspects of the fuel supply for the Issuer’s Long Island generating facilities, as well as all aspects of the capacity and energy owned by or under contract to LIPA pursuant to an Energy Management Agreement (the “1998 EMA”). The Issuer also purchases energy, capacity and ancillary services in the open market on LIPA’s behalf under the 1998 EMA. The 1998 MSA, 1998 PSA and 1998 EMA all became effective on 28 May 1998 and are collectively referred to as the “1998 LIPA Agreements”.

KeySpan sells to LIPA all of the capacity and, to the extent requested, energy conversion services from the Issuer’s existing Long Island based oil and gas-fired generating plants. Sales of capacity and energy conversion services are made under rates approved by the FERC in accordance with the 1998 PSA. The original FERC-approved rates, which had been in effect since May 1998, expired on 31 December 2003. On 1 October 2004 the FERC approved a settlement reached between KeySpan and LIPA to reset rates which became effective on 1 January 2004. The settlement agreement reflects a cost of equity of 9.5 per cent., as well as updated operating and maintenance expense levels and recovery of certain other costs as agreed to by the parties.

On 1 February 2006, KeySpan and LIPA entered into (i) the 2006 MSA, pursuant to which KeySpan will continue to operate and maintain the electric T&D System owned by LIPA on Long Island; (ii) a new Option and Purchase and Sale Agreement (the “2006 Option Agreement”), to replace the Generation Purchase Rights Agreement (as amended, the “GPRA”), pursuant to which LIPA had the option, through 15 December 2005, to acquire substantially all of the electric generating

facilities owned by KeySpan on Long Island; and (iii) a Settlement Agreement (the “2006 Settlement Agreement”) resolving outstanding issues between the parties regarding the 1998 LIPA Agreements.

Under the above described contractual arrangements, the Issuer’s KeySpan subsidiaries provide power, electric transmission and distribution services, billing and other customer services for approximately 1.1 million electric customers of LIPA. These subsidiaries own and operate 5 large generating plants and 13 smaller facilities which consist of 57 generating units in Nassau and Suffolk Counties on Long Island and the Rockaway Peninsula in Queens. These facilities consist of subsidiaries that manage the electric transmission and distribution system (“T&D System”) owned by LIPA; provide generating capacity and, to the extent required, energy conversion services for LIPA from the Issuer’s approximately 4,200 megawatts (“MW”) of generating facilities located on Long Island; and manage fuel supplies for LIPA to fuel the Issuer’s Long Island generating facilities.

U.S. Stranded Cost Recoveries

The U.S. stranded cost recoveries segment captures the recovery of the Issuer’s historical investments in generating plants that were “stranded” when the Issuer divested its generation business as part of the industry restructuring and wholesale power deregulation process in New England and New York. In addition, this segment includes the recovery of certain above-market costs of commodity purchase contracts that were in place at the time of restructuring and deregulation.

The Issuer is able, with the approval of the utility commissions in the states in which the Issuer’s public utility subsidiaries operate, to recover most of these costs through a special rate charged to electricity customers. Pursuant to the settlement and stranded cost recovery agreements in effect in each of the states in which the Issuer operates, revenue from this segment will decline as the recovery of stranded costs is completed.

Other activities

NEET owns and operates an alternating current/direct current converter terminal and related facilities for the first phase of the Hydro-Quebec and New England interconnection (the “Interconnection”), and six miles of high-voltage direct current transmission line in New Hampshire. N.H. Hydro, in which the Issuer holds 54 per cent. of the common stock, owns and operates 139 miles of high-voltage direct current transmission line in New Hampshire for the second phase of the Interconnection, extending to the Massachusetts border. Mass. Hydro, in which the Issuer holds 54 per cent. of the voting stock, owns and operates an alternating current/direct current terminal and related facilities for the second phase of the Interconnection and 12 miles of high-voltage direct current transmission line in Massachusetts. These facilities are made available to customers under ISO-New England’s Open Access Transmission Tariff, and are subject to ISO-New England operational control.

Non Regulated Activity

As part of the Issuer’s recent KeySpan acquisition the Issuer also has an interest in the following unregulated business activities:

KeySpan subsidiaries that provide energy-related services to customers located primarily within the northeast of the United States, with concentrations in the New York City and Boston metropolitan areas. These subsidiaries provide residential and small commercial customers with service and maintenance of energy systems and appliances, as well as operation and maintenance, design, engineering, consulting and fiber optic services to commercial, institutional and industrial

customers. The Issuer’s subsidiaries involved in this type of unregulated activity have over 200,000 service contracts in place to provide home energy services.

KeySpan subsidiaries engaged in gas production and development activities, domestic pipelines, gas storage facilities and LNG facilities and operations. These subsidiaries own an interest in a partnership of affiliates of six U.S. and Canadian energy companies, which partnership is the owner of a 411-mile interstate gas pipeline extending from the U.S.-Canadian border at Waddington, New York through western Connecticut to its terminus in Commack, New York, and from Huntington to the Bronx. The pipeline can transport up to 1,124,500 decatherms (“DTH”) per day of Canadian gas supply from the New York-Canadian border to markets in the northeast of the United States. Through such entities, the Issuer is also a shipper and currently transport up to 304,950 DTH of gas per day.

KeySpan subsidiary that was created to pursue the authorization and construction of an interstate pipeline from Connecticut, across Long Island Sound, to a terminus near Shoreham, Long Island. In addition, the Issuer owns an interest in a pipeline project which is anticipated to transport up to 525,000 DTH of gas a day from Corning to Ramapo, New York, interconnecting with the pipeline systems of various other utilities in New York.

Equity investments, in two gas storage facilities in the State of New York which provide up to 4.3 billion cubic feet of storage service to New York and New England, and up to 6.2 billion cubic feet of storage service to New Jersey and Massachusetts, respectively.

Ravenswood Generating Station

The Ravenswood Facility (defined below) is expected to be divested in accordance with the terms of the National Grid/KeySpan NYPSC merger order dated 17 September 2007. At present, one of the Issuer’s KeySpan subsidiaries owns, leases and operates the 2,200 MW Ravenswood electric generation facility (the “Ravenswood Facility”), located in Queens County in New York City, and the 250 MW combined cycle generating unit (the “Ravenswood Expansion”) which began full commercial operation in May 2004 (collectively, the Ravenswood Facility and the Ravenswood Expansion are referred to as the “Ravenswood Generating Station” and have a total electric capacity of 2,450 MW). The Ravenswood Generating Station located in Queens County, is the largest generating facility in New York City. The Ravenswood Generating Station consists of 3 large steam-generating units, a 250 MW combined cycle generating unit and 17 gas turbine generators. The Ravenswood Generating Station sells capacity, energy and ancillary services into the ISO-New York electricity market at market-based rates, subject to mitigation. The Ravenswood Generating Station Facility has the ability to provide approximately 25 per cent. of New York City’s capacity requirements and is a strategic asset that is available to serve residents and businesses in New York City.

The ISO-New York’s New York City local reliability rules require that 80 per cent. of the electric capacity needs of New York City be provided by “in-City” generators. National Grid USA’s Ravenswood Generating Station is an “in-City” generator. As the electric infrastructure in New York City and the surrounding areas continues to change and evolve and the demand for electric power increases, the in-City generator requirement could be further modified. Construction of new transmission and generation facilities may cause significant changes to the market for sales of capacity, energy and ancillary services from the Issuer’s Ravenswood Generating Station. The Issuer’s Keyspan subsidiary also operates and maintains a 55 MW gas turbine unit in Greenport, Long Island under an agreement with a third party.

Regulatory Environment

The securities of the Issuer’s London based parent, National Grid plc, are listed on the London Stock Exchange plc and on the New York Stock Exchange and, as a consequence, both National Grid plc and National Grid USA, are subject to regulation by the Financial Services Authority in the UK and by the Securities and Exchange Commission (“SEC”) in the U.S. However, because the Issuer, as a public utility holding company with federal and state regulated subsidiaries, operates in a highly regulated environment, good relationships with economic and safety regulators, in addition to other stakeholders, are essential because this establishes the framework within which the Issuer’s businesses operate.

U.S. electricity transmission

The transmission activities of each of the Issuer’s public utilities is regulated by the relevant state utility commission in the states in which the Issuer operates (including New York, Massachusetts, Rhode Island, Vermont, and New Hampshire) and by the FERC.

In relation to electricity transmission, the FERC, amongst other things, sets service standards for the transmission business of the Issuer’s public utilities, approves reliability standards set by the North American Electric Reliability Council (“NERC”) (an industry self regulatory body), determines the potential levels of return on regulated transmission service, and approves wholesale electricity market rules. Although FERC has siting authority over transmission lines in certain limited circumstances, the siting of transmission lines, as well as the ultimate recovery of transmission rates from retail customers is principally regulated by the relevant state utility commission (in addition to the other matters regulated by these commissions).

U.S. Gas Distribution

The Issuer’s gas distribution activities through the Issuer’s various operating subsidiaries, including Niagara Mohawk Power Corporation, The Narragansett Electric Issuer, as well as those entities recently acquired through the acquisition of KeySpan, including The Boston Gas Issuer, The Essex Gas Issuer, the Colonial Gas Issuer, EnergyNorth Natural Gas, Inc., The Brooklyn Union Gas Issuer d/b/a KeySpan Energy Delivery New York and KeySpan Gas East Corporation d/b/a KeySpan Energy Delivery Long Island, are regulated by the relevant state utility commissions in the states in which each such subsidiary operates.

In relation to National Grid USA’s gas distribution activities, the various state utility commissions, amongst other things, set distribution service standards for the jurisdictional public utilities, set retail rates for end use customers, and determine the public utility potential levels of return on distribution service.

U.S. Electricity Distribution

The electricity distribution activities through the Issuer’s various operating subsidiaries are regulated by the relevant state utility commission in the states in which the Issuer operates.

As with the Issuer’s gas distribution activity, the various state utility commissions, amongst other things: (i) set distribution service standards and retail rates for end use customers; and (ii) determine the potential levels of return on distribution service. However, FERC regulates wholesale electricity sales by us, to the extent that any sales are made.

The following is a brief overview of the description of the various rate plans in effect in the various states in which the Issuer’s subsidiaries operate:

Overview of Rate Plans

Revenue for the Issuer’s transmission business is collected from transmission customers, including the Issuer’s electricity distribution businesses, pursuant to tariffs approved by state utility commissions and by the FERC.

In New York, NMPC operates under a long term rate plan expiring in 2011 with a 50 per cent. synergy sharing and earnings sharing mechanism. Over the period of the plan, capital expenditure in the rate plan for transmission and distribution was based on forecasts made at the time of the acquisition of NMPC by National Grid, which are significantly lower than the capital expenditure required to maintain a safe and reliable network. For the past three years, the Issuer’s incremental investment in transmission for example has exceeded the investment included in the forecast underlying the rate plan by a factor of at least two.

This coming year, the Issuer’s plans are to spend at a level similar to 2006 and 2007. The rate plan includes provisions for the Issuer’s upstate New York public utility, NMPC, to petition the NYPSC for recovery of incremental investment. In a recent NYPSC order on the KeySpan transaction, the NYPSC indicated that NMPC would be allowed to recover up to 50 per cent. of the revenue requirements associated with incremental capital expenditures during the balance of NMPC’s rate plan. After the expiration of the rate plan, NMPC will reset rates based on its total investment in transmission and distribution plant.

In New England, the Issuer’s transmission tariff allows for recovery of, and return on, capital expenditures as new investment enters service, bringing immediate revenue benefits. The distribution operations are covered by long term rate plans that include regular annual adjustments for MECo and a separate factor for incremental investment in New Hampshire. Narragansett also has a long term rate plan for electric operations, and intends to file for new gas distribution rates in 2008.

The electric distribution operations of NMPC, the Issuer’s upstate New York public utility, MECo in Massachusetts, and Narragansett in Rhode Island are subject to reliability penalties if the combined performance of National Grid USA’s electricity distribution and transmission networks in New York fails to meet targets associated with the number and duration of disturbances that impact customers. In addition, the rate plans for these companies are generally oriented around efficient operations. To the extent that the companies perform necessary activities and spend less than the forecast operating costs set in the rate plan, it equates to increased income for shareholders. Part of the rate plan deals with forecast energy delivery. To the extent that more energy is delivered, the Issuer increases revenue. Conversely, if the Issuer delivers less than forecast, its revenue goes down.

New York

With respect to the Issuer’s upstate New York subsidiary, the Issuer’s electricity delivery rates for NMPC under a rate plan filed with and approved by the NYPSC are governed by a 10 year rate plan that began on 1 February 2002. Under the rate plan, after reflecting the Issuer’s share of savings related to the acquisition of NMPC, the Issuer may earn a threshold return on equity for its electricity distribution business of 10.6 per cent. or 12.0 per cent. if certain customer outreach, education, competition-related and low income incentive targets are met. In the event NMPC earns more than 12 per cent., varying percentages of the excess are shared with customers. The return on equity is measured in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and calculated cumulatively from inception to 31 December 2005 and on a two year rolling basis thereafter. The earnings calculation used to determine the regulated

returns excludes half of the synergy savings from the NMPC acquisition, net of the cost to achieve them, that were assumed in the rate plan.

The NMPC rate plan also allows for subsequent recovery of specified costs and revenue items that have occurred since the rate plan was established, once these amounts involved exceed U.S.$100 million. These ‘deferral account’ items include changes from the levels of pension and post-retirement benefit expenses from levels specified in the rate plan, as well as various other items, including storms, environmental remediation costs, and certain rate discounts provided to customers, together with costs and revenues from changes in tax, accounting and regulatory requirements. In 2007, a stipulation of the parties was filed and approved by the NYPSC on 19 July 2007 in which NMPC agreed to a net reduction in the deferral account balances allowed under its rate plan of approximately U.S.$127 million excluding changes in actuals to that date. The NYPSC authorised the collection of U.S.$300 million in calendar year 2006 and 2007 already agreed to by the NYPSC, and the continued deferral of the balance above that amount. NMPC, in accordance with its rate plan filed its third deferral account filing on 1 August 2007 for deferral balances as of 30 June 2007 and projected deferrals through 31 December 2009. The deferral account recoveries proposed in the third deferral reset are approximately U.S.$136 million per year over the two years (approximately U.S.$272 million over the two year period). This represents a reduction of U.S.$64 million per year over the U.S.$200 million per year currently being collected under the second deferral reset. These deferral recoveries are subject to audit by the staff of the NYPSC and further updates and adjustments in the proceeding. Any differences in the deferrals from this approved recovery level would be reflected in the next deferral reset that takes effect after 2009.

As part of the NYPSC National Grid/KeySpan merger order dated 17 September 2007, there are new rate plans, which are being put into place for both KEDNY and KEDLI. Effective on 1 January 2008, the two KeySpan gas utility companies’ gas adjustment clauses would be increased to recover, on a prospective basis, estimated gas commodity-related costs of U.S.$68.6 million and U.S.$28.7 million, respectively, which would no longer be included in base rates. In addition, base delivery rates would be increased by U.S.$60 million for KEDLI and would be maintained at current levels for KEDNY. The base delivery rates would then be frozen for five years. The proposed rate plans contemplate an allowed return on equity of 9.6 per cent. for each entity. Cumulative earnings above 10.6 per cent. (including a 10 basis point incentive) would be shared between gas sales customers and the KeySpan companies over the rate plan period.

The Issuer owns the Ravenswood Facility, which operates in the New York City wholesale electricity market. The Issuer believes that the New York City market represents a strong capacity market due to, among other things, its local reliability rules, increasing demand and the time required for new resources to be constructed. The Issuer anticipates that demand will increase and that the high cost to construct capacity in New York City will result in favourable In-City Unforced Capacity prices. Therefore. on 18 January 2006, the Issuer, through its KeySpan subsidiary, entered into an International SWAP Dealers Association Master Agreement for a fixed for float unforced capacity financial swap (the “Capacity Swap Agreement”) with Morgan Stanley Capital Group Inc. (“Morgan Stanley Inc.”). The Capacity Swap Agreement has a three year term which commenced on 1 May 2006. The notional quantity is 1,800,000kW (the “Notional Quantity”) of In-City Unforced Capacity and the fixed price is $7.57/kW-month (the “Fixed Price”), subject to adjustment upon the occurrence of certain events. Cash settlement will occur on a monthly basis based on the In-City Unforced Capacity price determined by the relevant NYISO Spot Demand Curve Auction Market (the “Floating Price”). For each monthly settlement period, the price difference will equal the Fixed Price minus the Floating Price. If such price difference is less than zero, Morgan Stanley Inc. will pay KeySpan an amount equal to the product of (i) the Notional Quantity and (ii) the absolute value

of such price difference. Conversely, if such price difference is greater than zero (for example, if the demand is less than the Issuer’s estimates, additional resources enter the market, or costs are less than forecast) KeySpan will pay Morgan Stanley Inc. an amount equal to the product of (i) the Notional Quantity and (ii) the absolute value of such price difference.

The NYPSC, Consolidated Edison and other load serving entities (“LSEs”) complained to the NYISO that In-City capacity market clearing prices during the summer of 2006 did not decline as they had expected with the introduction of additional supply in the New York City market. The NYISO issued a letter to FERC indicating that no tariff violations occurred and that prices were as it expected. Nevertheless, the NYISO stated that if changes to the market are warranted, the NYISO would consider making revisions as necessary. In connection with this proceeding, in July 2007, KeySpan received notice that the FERC Office of Enforcement is conducting a formal investigation into matters regarding the offering practices of generating units serving New York City’s In-City capacity market. The Department of Justice is also conducting its own investigation of the competitive issues in the New York City electric energy capacity market. At this time, we are unable to predict the outcome of these proceedings and what effect, if any, they may have on the potential revenue that could be realized from physical sales of In-City capacity or on the Capacity Swap Agreement.

Massachusetts

Under the Issuer’s long-term rate plan in Massachusetts there is no cap on earnings and no earnings sharing rates mechanism until 2010. In addition, the Issuer will be allowed to include its share of earned savings, if any, in demonstrating the Issuer’s costs of providing service to customers from January 2010 until May 2020. From May 2000 until February 2005 rates were frozen. In March 2005, a settlement credit in the company’s rates expired, resulting in an increase of $10 million in income through to February 2006. From March 2006, rates are adjusted each 1 March until 2009 by the annual percentage change in average electricity distribution rates in the northeast of the U.S. Regulators approved annual increases in the amount of U.S.$20 million, effective 1 March 2006 and U.S.$9.4 million effective 1 March 2007. In 2009, actual earned savings will be determined and the Issuer will be allowed to retain 100 per cent. of annual earned savings up to U.S.$71 million and 50 per cent. of annual earned savings between U.S.$71 million and U.S.$109 million before tax. Earned savings represent the difference between a test year’s distribution revenue and the Issuer’s cost of providing service during the same test year, including a regional average authorised return.

Effective 1 November 2003, the Massachusetts Department of Telecommunications and Energy (“MDTE”), predecessor to the MDPU, approved a U.S.$25.9 million increase in base revenues for one of the Issuer’s KeySpan Massachusetts gas utility companies with an allowed return on equity of 10.2 per cent., reflecting an equal balance of debt and equity. On 27 January 2004, the MDTE issued its order on this entity’s Motion for Recalculation, Reconsideration and Clarification that granted an additional U.S.$1.1 million in base revenues, for a total of U.S.$27 million. The MDTE also approved a Performance Based Rate Plan (the “Plan”) for up to ten years. On 1 November 2006, the MDTE approved a base rate increase of U.S.$8.6 million under the Plan. In addition, an increase of U.S.$2.7 million in the local distribution adjustment clause was approved to recover pension and other postretirement costs. The MDTE also approved a true-up mechanism for pension and other postretirement benefit costs under which variations between actual pension and other postretirement benefit costs and amounts used to establish rates are deferred and collected from, or refunded to, customers in subsequent periods. This true-up mechanism allows for carrying charges on deferred assets and liabilities at this entity’s weighted-average cost of capital.

There is also a MADTA imposed 10 year base rate freeze for firm customers in place for the Issuer’s KeySpan Massachusetts gas utility companies that expire in 2009.

Rhode Island

The Issuer’s distribution rates in Rhode Island are also governed by a long-term rate plan. Between May 2000 and the end of October 2004, rates were frozen, and the Issuer was subject to an earnings sharing mechanism. Effective from November 2004 until December 2009 the Issuer has agreed to lower the Issuer’s rates by 10 million before tax per year.

From January 2005 onwards the Issuer is able to keep an amount equal to 100 per cent. of the Issuer’s earnings up to an allowed return on equity of 10.5 per cent., plus a specific before tax amount, which represents the Issuer’s share of demonstrated savings subsequent to the acquisition of Eastern Utilities Associates in 2000. Earnings above that amount up to an additional 1 per cent. return on equity are to be shared equally with the Issuer’s customers, while additional earnings will be allocated 75 per cent. to customers and 25 per cent. to the Issuer. The Issuer determines its earned return on equity based on a hypothetical capital structure of 50 per cent. common equity, 5 per cent. preferred equity and 45 per cent. debt.

New Hampshire

In New Hampshire, the Issuer’s electricity distribution network serves over 40,000 retail customers, whilst the Issuer also own transmission assets consisting of substations and interconnections with the Issuer’s other electricity operations in New England.

The Issuer has reached an agreement for a five year rate plan for the Issuer’s electricity distribution operations in New Hampshire. This was approved by the New Hampshire Public Utilities Commission on 12 July 2007. The rate plan includes a 9 per cent. reduction in electric distribution rates. Over the term of the plan, earnings in excess of the allowed return of 9.67 per cent. are retained by the Issuer up to 11 per cent. Any earnings over 11 per cent. would be shared with customers. In addition, the plan allows for incremental increases in rates for capital expenditure incurred under the Issuer’s reliability enhancement programme.

National Grid USA’s Keyspan New Hampshire gas distribution utility company base rates continue as set by the NHPUC in 1993.

Market and Regulatory developments

The recovery of historical investments and costs under commodity contracts following industry restructuring in New England and New York is done pursuant to applicable state legislation and approvals from the various utility commissions in the states in which the Issuer operates.

U.S. electricity transmission

In the United States, consistent with FERC’s transmission pricing policy, the Issuer has applied for an increased rate of return on the Issuer’s investment in transmission assets in New England. FERC approved this application in October 2006, but has yet to determine its response to several parties which have sought to appeal this approval.

The Issuer has been pursuing a regional planning process with the Independent System Operator in New York (“ISO – New York”) to identify regional reliability and economic transmission needs. Progress has been made and the ISO-New York is in the second year of its reliability planning process implementation. The Issuer has proposed a regulated transmission solution to reliability needs identified by the ISO-New York. In addition, as part of FERC’s recent open access transmission tariff reform, the ISO-New York is developing a process to address economic planning.

Other Market Developments

Energy Markets

Sharp increases in energy prices have renewed interest in the public policy debate about restructuring the nation’s electricity industry and increased the pressure on regulators and politicians to consider taking action to mitigate the effects on customers. As the debate continues, the Issuer has taken a leadership position by advocating a well-managed system as the key to enabling robust, competitive electricity markets that offer customers choice, savings and other benefits. State regulators continue to strongly support current recovery of power supply costs. The Issuer continues to collaborate with regulators, policy makers, and customers to advance the development of the competitive electricity marketplace.

Recent Developments

On 24 August 2007, KeySpan completed its merger (the “Merger”) with National Grid plc, as contemplated by the Agreement and Plan of Merger, dated as of 25 February 2006. The aggregate consideration paid by National Grid plc was approximately U.S.$7.4 billion. The voting securities of KeySpan were previously publicly held and traded on the New York Stock Exchange but are now held 100 per cent. indirectly by National Grid plc.

KeySpan has no independent operations and conducts substantially all of its operations through its subsidiaries. Prior to the Merger, KeySpan’s subsidiaries operated in the following four business segments: Gas Distribution, Electric Services, Energy Services and Energy Investments. Following is a summary of certain select net revenue information (in millions of dollars) for each of the KeySpan business segments for calendar years ended 31 December 2006, 2005 and 2004:


Segment	2006		2005		2004
	(Millions of Dollars)

Gas	U.S.$	1,665.6	U.S.$	1,717.3	U.S.$	1,669.3
Electric*	U.S.$	1,332.3	U.S.$	1,295.9	U.S.$	1,199.1
Energy Services*	U.S.$	213.0	U.S.$	202.0	U.S.$	193.9
Energy Investments	U.S.$	40.3	U.S.$	43.0	U.S.$	58.9

Note:

* Following the completion of the merger with KeySpan, the merchant electricity generation business in New York City and the communications operations were classified as discontinued operations in the interim financial statements of National Grid plc for the six months ended 30 September 2007. The revenues relating to these operations were U.S.$903m in 2006, U.S.$1,117m in 2005 and U.S.$820m in 2004.

KeySpan, through its gas distribution segment, operated as the fifth largest gas distribution company in the United States and the largest in the northeast of the United States. The gas distribution segment consists of six regulated gas distribution subsidiaries, which operate in New York, Massachusetts and New Hampshire and serve approximately 2.6 million customers within an aggregate service area covering 4,273 square miles. In New York, The Brooklyn Union Gas Company, doing business as KEDNY, provides gas distribution services to customers in the New York City Boroughs of Brooklyn, Queens and Staten Island; and KeySpan Gas East Corporation, doing business as KEDLI, provides gas distribution services to customers in the Long Island Counties of Nassau and Suffolk and the Rockaway Peninsula of Queens County. In Massachusetts, Boston Gas provides gas distribution services in eastern and central Massachusetts; Colonial Gas

provides gas distribution services on Cape Cod and in eastern Massachusetts; and Essex Gas provides gas distribution services in eastern Massachusetts. In New Hampshire, EnergyNorth provides gas distribution services to customers principally located in central New Hampshire. KeySpan’s New England gas companies all do business as KeySpan Energy Delivery New England (“KEDNE”).

In New York, there are two separate, but contiguous service territories served by KEDNY and KEDLI, comprising approximately 1,417 square miles and 1.68 million customers. In Massachusetts, Boston Gas, Colonial Gas and Essex Gas serve three service territories consisting of 1,934 square miles and approximately 792,000 customers. In New Hampshire, EnergyNorth has a service territory that is contiguous to Colonial Gas’ and ranges from within 30 to 85 miles of the greater Boston area. EnergyNorth provides service to approximately 80,000 customers over a service area of approximately 922 square miles. Collectively, KeySpan owns and operates gas distribution, transmission and storage systems that consist of approximately 23,336 miles of gas mains and distribution pipelines.

KeySpan, through its electric services segment, operated as the largest electricity generator in New York State. The electric services segment consists of subsidiaries that manage the T&D System owned by LIPA; provide generating capacity and, to the extent required, energy conversion services for LIPA from the approximately 4,200 MW of generating facilities located on Long Island; and manage fuel supplies for LIPA to fuel Long Island generating facilities. These subsidiaries own and operate 5 large generating plants and 13 smaller facilities which consist of 57 generating units in Nassau and Suffolk Counties on Long Island and the Rockaway Peninsula in Queens.

The electric services segment also includes subsidiaries that own, lease and operate the Ravenswood Facility, located in Queens County in New York City, and the Ravenswood Expansion which began full commercial operation in May 2004. The Ravenswood Generating Station is expected to be divested in accordance with the terms of the National Grid/KeySpan New York Public Service Commission merger order dated 17 September 2007 and is treated as discontinued operations for the purposes of the Issuer’s financial reporting.

The energy services segment includes companies that provide energy-related services to customers located primarily within the northeast of the United States, with concentrations in the New York City and Boston metropolitan areas. Subsidiaries in this segment provide residential and small commercial customers with service and maintenance of energy systems and appliances, as well as operation and maintenance, design, engineering, consulting and fibre optic services to commercial, institutional and industrial customers. KeySpan subsidiaries in this segment have over 200,000 service contracts in place to provide home energy services, completed over 240,000 service calls during 2006 and completed more than 16,000 installations during 2006.

The energy investments segment includes gas production and development activities, domestic pipelines, gas storage facilities and LNG facilities and operations. KeySpan is engaged in the production and development of domestic gas and oil through two wholly-owned subsidiaries.

Legal Proceedings

On 31 May 2007, KeySpan received a CID from the United States Department of Justice, Antitrust Division, requesting the production of documents and information relating to its investigation of competitive issues in the New York City electric energy capacity market. The CID is a request for information in the course of an investigation and does not constitute the commencement of legal proceedings, and no specific allegations have been made against KeySpan. KeySpan intends to fully co-

operate with this investigation. At this time Keyspan is unable to determine what effect, if any, the outcome may have on the Issuer and/or the Group’s financial position or profitability.

Executive Officers

The Executive Officers of the Issuer are as follows:


Name		Title
Colin Buck		Chief Financial Officer and Senior Vice-President

Robert Catell		Executive Chairman

John Cochrane		Executive Vice-President and Treasurer

Malcolm Cooper		Assistant Treasurer

Tom King		President

Cheryl LaFleur		Executive Vice-President

Kwong Nuey		Senior Vice-President

Richard Pettifer		Assistant Treasurer

Larry Reilly		Executive Vice-President and Secretary

Christopher Root		Chief Operating Officer and Senior Vice-President

Masheed Saidi		Senior Vice-President

Bob Seega		Assistant Treasurer

Board of Directors

The Directors of the Issuer and their principal activities outside National Grid USA, are as follows:


	Principal activities outside
	National Grid USA and the National
Name	Grid Group*	Business Address
Robert Catell	None	One MetroTech Center Brooklyn NY 11201 United States

John Cochrane	Director of Blue-ng Limited, Blue-ng (Holdings) Limited and Britned Development Limited	25 Research Drive Westborough MA 01582 United States

William Edwards	Director of the New York State Energy Research & Development Authority	Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse NY 13202 USA

Steve Holliday	Non-Executive Director of Marks and	1-3 Strand


	Principal activities outside
	National Grid USA and the National
Name	Grid Group*	Business Address
	Spencers Group plc	London WC2N 5EH United Kingdom

Tom King	None	25 Research Drive Westborough MA 01582 United States

Cheryl LaFleur	None	25 Research Drive Westborough MA 01582 United States

Steve Lucas	Non-Executive Director of Compass Group PLC and Director of American European Business Association Ltd.	1-3 Strand London WC2N 5EH United Kingdom

Larry Reilly	None	25 Research Drive Westborough MA 01582 United States

Masheed Saidi	None	25 Research Drive Westborough MA 01582 United States

Nick Winser	None	1-3 Strand London WC2N 5EH United Kingdom


*		The “National Grid Group” means National Grid plc and each of its subsidiary undertakings.

There are no potential conflicts of interest between the duties to National Grid USA of each of the Directors or Executive Officers listed above and his or her private interests or other duties.

TAXATION

United States Taxation

TO ENSURE COMPLIANCE WITH U.S. TREASURY DEPARTMENT CIRCULAR 230 (“CIRCULAR 230”), HOLDERS OF INSTRUMENTS ARE HEREBY NOTIFIED THAT: (A) ANY DISCUSSION OF FEDERAL TAX ISSUES IN THIS PROSPECTUS IS NOT INTENDED OR WRITTEN TO BE RELIED UPON, AND CANNOT BE RELIED UPON, BY HOLDERS OF INSTRUMENTS FOR THE PURPOSE OF AVOIDING PENALTIES THAT MAY BE IMPOSED ON HOLDERS OF INSTRUMENTS UNDER THE INTERNAL REVENUE CODE; (B) SUCH DISCUSSION IS INCLUDED HEREIN BY THE ISSUER IN CONNECTION WITH THE PROMOTION OR MARKETING (WITHIN THE MEANING OF CIRCULAR 230) BY THE ISSUER OF THE TRANSACTIONS OR MATTERS ADDRESSED HEREIN; AND (C) HOLDERS OF INSTRUMENTS SHOULD SEEK ADVICE BASED ON THEIR PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR.

* * * * *

Under current U.S. federal income and estate tax law, and subject to the discussion of backup withholding in the following section:

	(a)		Payments of principal, original issue discount (“OID”), and interest by the Issuer or any paying agent to any holder of an Instrument who is a United States Alien (as defined below) will not be subject to U.S. federal withholding tax, provided that, in the case of amounts treated as interest or OID with respect to Instruments with a maturity of more than 183 days, (i) the amount of the payment is not determined by reference to any receipts, sales or other cash flow, income or profits, change in value of any property of, or dividend or similar payment made by, the Issuer or a person related to the Issuer (a “Contingent Payment”), (ii) the holder does not actually or constructively own 10 per cent. or more of the total combined voting power of all classes of stock of the Issuer entitled to vote, (iii) the holder is not for U.S. federal income tax purposes a controlled foreign corporation related to the Issuer through stock ownership, and (iv) the holder is not a bank receiving interest described in Section 881(c)(3)(A) of the Internal Revenue Code of 1986, as amended (the “Code”).

	(b)		A United States Alien holder of an Instrument or coupon will not be subject to U.S. federal income tax on any gain or income realised upon the sale, exchange, retirement or other disposition of an Instrument or coupon, provided that (i) in the case of Instruments with a maturity of more than 183 days, the Instruments do not provide for any Contingent Payments, and (ii) neither the holder, nor a partner, fiduciary, settler or beneficiary of the holder if the holder is a partnership or an estate or trust, or a person holding a power over an estate or trust administered by a fiduciary holder, is considered as:

	(i)		being or having been present or engaged in a trade or business in the United States or having or having had a permanent establishment therein;

	(ii)		having a current or former relationship with the United States, including a relationship as a citizen or resident thereof;

	(iii)		being or having been for U.S. federal income tax purposes a personal holding company, a passive foreign investment company, a controlled foreign corporation or a corporation that has accumulated earnings to avoid U.S. federal income tax; or

(iv)

in the case of Instruments with a maturity of more than 183 days, (a) actually or constructively owning or having owned 10 per cent. or more of the total combined voting power of all classes of stock of the Issuer entitled to vote or (b) being a controlled foreign corporation related to the Issuer through stock ownership.

	(c)		An Instrument or coupon held by an individual who is a United States Alien at the time of death will not be subject to U.S. federal estate tax as a result of the individual’s death if (i) at the time of the individual’s death payments with respect to the Instrument would not have been effectively connected with a U.S. trade or business of the individual, and (ii) with respect to Instruments with a maturity of more than 183 days, (A) the holder does not own, actually or constructively, 10 per cent. or more of the total combined voting power of all classes of stock of the Issuer entitled to vote, and (B) the Instrument does not provide for any Contingent Payments.

	(d)		A beneficial owner of an Instrument or coupon that is a United States Alien will not be required to disclose its nationality, residence, or identity to the Issuer, a paying agent, or any U.S. governmental authority in order to receive payment on the Instrument or coupon from the Issuer or a paying agent outside the United States (although the beneficial owner of an interest in the temporary Global Instrument will be required to provide a Certificate of Non-U.S. Beneficial Ownership to Euroclear or Clearstream, Luxembourg in order to receive a beneficial interest in a Permanent Global Instrument or Definitive Instruments and coupons and interest thereon, as described in “Summary of Provisions Relating to the Instruments while in Global Form — Exchange”).

For purposes of this discussion, “United States Alien” means any corporation, partnership, individual or fiduciary estate or trust that, for U.S. federal income tax purposes, is (i) a foreign corporation, (ii) a foreign partnership all of whose partners are United States Aliens, (iii) a non-resident alien individual or (iv) a foreign estate or trust all of whose beneficiaries are United States Aliens .

Backup Withholding and Information Reporting

Payments of principal, OID and interest on Instruments made outside the United States to a United States Alien by a non-U.S. payer will not be subject to information reporting and backup withholding.

In addition, except as provided in the following sentence, if principal, OID or interest payments are collected outside the United States on behalf of a beneficial owner of an Instrument by a foreign office of a custodian, nominee or other agent who is not a U.S. Controlled Person, (as defined below), the custodian, nominee or other agent will not be required to apply backup withholding to these payments when remitted to the beneficial owner and will not be subject to information reporting. However, if the custodian, nominee or other agent is a U.S. Controlled Person, payments collected by its United States or foreign office may be subject to information reporting and backup withholding unless the custodian, nominee or other agent has in its records documentary evidence that the beneficial owner is not a U.S. person or is otherwise exempt from information reporting, and it has no actual knowledge or reason to know that any of the information or certifications associated with this documentation is incorrect.

Payments on the sale, exchange or other disposition of an Instrument made to or through a foreign office of a broker will generally not be subject to information reporting or backup withholding. However, if the broker is a U.S. Controlled Person, payments on the sale, exchange or other disposition of the Instrument made to or through a United States or foreign office of the broker will be subject to information reporting unless the beneficial owner has furnished the broker with documentation upon which the broker can rely to treat the payment as made to a beneficial owner that is a foreign person, and the broker has no actual knowledge or reason to know that any of the information or certifications associated with this documentation is incorrect.

For purposes of this discussion, a “U.S. Controlled Person” means (i) a U.S. person (as defined in the Code), (ii) a controlled foreign corporation for U.S. federal income tax purposes, (iii) a foreign person 50

per cent. or more of whose gross income was effectively connected with the conduct of a United States trade or business for a specified three-year period, or (iv) a foreign partnership, if at any time during its tax year, one or more of its partners are U.S. persons who, in the aggregate, hold more than 50 per cent. of the partnership’s income or capital interest or if, at any time during its tax year, it is engaged in the conduct of a trade or business in the United States.

Any amounts withheld under the backup withholding rules may be allowed as a credit against the holder’s U.S. federal income tax liability, and may entitle the holder to a refund, provided that the required information is furnished to the U.S. Internal Revenue Service.

Holders should consult their tax advisors regarding the application of information reporting and backup withholding to their particular situations, the availability of an exemption therefrom, and the procedure for obtaining an exemption, if available.

A holder of an Instrument with a maturity at issue of 183 days or less and a principal amount of at least U.S.$500,000 (or its foreign currency equivalent based on the spot rate on the date of issue), by accepting the Instrument, will be deemed to represent and warrant that it is not a United States person (other than an exempt recipient described in section 6049(b)(4) of the Code and the regulations thereunder), and is not acting for or on behalf of any such person.

THE SUMMARY OF U.S. FEDERAL INCOME AND ESTATE TAX SET FORTH ABOVE IS INCLUDED FOR GENERAL INFORMATION ONLY. ALL PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO THE PARTICULAR TAX CONSEQUENCES TO THEM OF OWNING INSTRUMENTS OR COUPONS, INCLUDING THE APPLICABILITY AND EFFECT OF STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND POSSIBLE CHANGES IN TAX LAW.

EU Savings Directive

Under EU Council Directive 2003/48/EC on the taxation of savings income, each Member State is required to provide to the tax authorities of another Member State details of payments of interest or other similar income paid by a person within its jurisdiction to, or collected by such a person for, an individual resident or to certain limited types of entity established in that other Member State; however, for a transitional period, Austria, Belgium and Luxembourg may instead apply a withholding system in relation to such payments, deducting tax at rates rising over time to 35 per cent. The transitional period is to terminate at the end of the first full fiscal year following agreement by certain non-EU countries to the exchange of information relating to such payments.

Also, a number of non-EU countries, and certain dependent or associated territories of certain Member States, have agreed to adopt similar measures (either provision of information or transitional withholding) in relation to payments made by a person within its jurisdiction to, or collected by such a person for, an individual resident or certain limited types of entity established in a Member State. In addition, the Member States have entered into reciprocal provision of information or transitional withholding arrangements with certain of those dependent or associated territories in relation to payments made by a person in a Member State to, or collected by such a person for, an individual resident or certain limited types of entity established in one of those territories.

PLAN OF DISTRIBUTION

Summary of Agreement

Subject to the terms and on the conditions contained in a dealer agreement dated 3 December 2007 (as amended or supplemented from time to time), between the Issuer, the Permanent Dealers and the Arranger (the “Dealer Agreement”), the Instruments will be offered on a continuous basis by the Issuer to the Permanent Dealers. However, the Issuer has reserved the right to issue Instruments directly on its own behalf to dealers which are not the Permanent Dealers. The Instruments may also be issued by the Issuer through the Dealers, acting as agents of the Issuer. The Dealer Agreement also provides for Instruments to be issued in syndicated Tranches which are jointly and severally underwritten by two or more Dealers. The commissions in respect of an issue of Instruments on a syndicated basis will be stated in the relevant Final Terms. The Issuer has agreed to indemnify the Dealers against certain liabilities in connection with the offer and sale of the Instruments.

Selling Restrictions

United States

The Instruments have not been and will not be registered under the Securities Act and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons except in certain transactions exempt from the registration requirements of the Securities Act. Terms used in this paragraph have the meanings given to them by Regulation S under the Securities Act.

Any Instruments having a maturity of more than one year are subject to U.S. tax law requirements and may not be offered, sold or delivered within the United States or its possessions or to a U.S. person, except in certain transactions permitted by U.S. tax regulations. Terms used in this paragraph have the meanings given to them by the U.S. Internal Revenue Code and regulations under it.

Each Dealer has agreed and each further Dealer appointed under the Programme will be required to agree that, except as permitted by the Dealer Agreement, it will not offer, sell or deliver the Instruments of any identifiable Tranche, (a) as part of their distribution at any time or (b) otherwise until 40 days after completion of the distribution of such Tranche as determined, and certified to the Issuer, by the Issuing and Paying Agent, or in the case of Instruments issued on a syndicated basis, the Lead Manager, within the United States or to, or for the account or benefit of, U.S. persons, and it will have sent to each dealer to which it sells Instruments during the distribution compliance period a confirmation or other notice setting forth the restrictions on offers and sales of the Instruments within the United States or to, or for the account or benefit of, U.S. persons.

Each issuance of Dual Currency Instruments will be subject to such additional United States selling restrictions as indicated in the applicable Final Terms. Each Dealer has agreed that it shall offer, sell and deliver such Instruments only in compliance with such additional U.S. selling restrictions.

In addition, until 40 days after the commencement of the offering of any identifiable Tranche, an offer or sale of Instruments within the United States by any dealer that is not participating in the offering may violate the registration requirements of the Securities Act.

Public Offer Selling Restriction under the Prospectus Directive

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each Dealer has represented, warranted and agreed, and each further Dealer appointed under the Programme will be required to represent, warrant and agree, that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”) it has not made and will not make an offer of Instruments which are the subject of the offering contemplated by the Prospectus as

completed by the Final Terms in relation thereto to the public in that Relevant Member State except that it may, with effect from and including the Relevant Implementation Date, make an offer of Instruments to the public in that Relevant Member State:

	(a)		if the Final Terms in relation to the Instruments specify that an offer of those Instruments may be made other than pursuant to Article 3(2) of the Prospectus Directive in that Relevant Member State (a “Non-Exempt Offer”), following the date of publication of a prospectus in relation to those Instruments which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, provided that any such prospectus has subsequently been completed by the Final Terms contemplating such Non-Exempt Offer, in accordance with the Prospectus Directive, in the period beginning and ending on the dates specified in such prospectus or Final Terms, as applicable;

	(b)		at any time to legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities;

	(c)		at any time to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than€43,000,000 and (3) an annual net turnover of more than€50,000,000, as shown in its last annual or consolidated accounts;

	(d)		at any time to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

	(e)		at any time in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of Instruments referred to in (b) to (e) above shall require the Issuer or any Dealer to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of Instruments to the public” in relation to any Instruments in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the Instruments to be offered so as to enable an investor to decide to purchase or subscribe the Instruments, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State.

United Kingdom

Each Dealer has represented, warranted and agreed, and each further Dealer appointed under the Programme will be required to represent, warrant and agree, that:

	(a)		in relation to any Instruments which have a maturity of less than one year, (i) it is a person whose ordinary activities involve it in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of its business and (ii) it has not offered or sold and will not offer or sell any Instruments other than to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or as agent) for the purposes of their businesses or who it is reasonable to expect will acquire, hold, manage or dispose of investments (as principal or agent) for the purposes of their businesses where the issue of the Instruments would otherwise constitute a contravention of Section 19 of the FSMA by the Issuer;

	(b)		it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning

			of Section 21 of the FSMA) received by it in connection with the issue or sale of any Instruments in circumstances in which Section 21(1) of the FSMA does not apply to the Issuer; and

	(c)		it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to any Instruments in, from or otherwise involving the United Kingdom.

Japan

The Instruments have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the “Financial Instruments and Exchange Law”). Accordingly, each of the Dealers has represented, warranted and agreed and each further Dealer appointed under the Programme will be required to represent, warrant and agree that it has not, directly or indirectly, offered or sold and will not, directly or indirectly, offer or sell any Instruments in Japan or to, or for the benefit of, any resident of Japan or to others for re-offering or re-sale, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan except pursuant to an exemption from the registration requirements of, and otherwise in compliance with the Financial Instruments and Exchange Law and other relevant laws and regulations of Japan. As used in this paragraph, “resident of Japan” means any person resident in Japan, including any corporation or other entity organised under the laws of Japan.

General

These selling restrictions may be modified by the agreement of the Issuer and the Dealers following a change in a relevant law, regulation or directive. Any such modification will be set out in the Final Terms issued in respect of the issue of Instruments to which it relates or in a supplement to this Prospectus.

No action has been or will be taken in any country or jurisdiction by the Issuer or the Dealers that would permit a public offering of Instruments, or possession or distribution of any offering material in relation thereto, in any country or jurisdiction where action for that purpose is required. Persons into whose hands this Prospectus or any Final Terms comes are required by the Issuer and the Dealers to comply with all applicable laws and regulations in each country or jurisdiction in or from which they purchase, offer, sell or deliver Instruments or have in their possession or distribute such offering material, in all cases at their own expense.

Each Dealer has agreed that it will comply with all relevant laws, regulations and directives in each jurisdiction in which it purchases, offers, sells or delivers Instruments or has in its possession or distributes this Prospectus, any other offering material or any Final Terms and neither the Issuer nor any other Dealer shall have responsibility for such material.

FORM OF FINAL TERMS

The Final Terms in respect of each Tranche of Instruments will be substantially in the following form, duly supplemented (if necessary), amended (if necessary) and completed to reflect the particular terms of the relevant Instruments and their issue. Text in this section appearing in italics does not form part of the form of the Final Terms but denotes directions for completing the Final Terms.

Final Terms dated [•]

NATIONAL GRID USA
Issue of [Aggregate Nominal Amount of Tranche] [Title of Instruments]
under the Euro 4,000,000,000 Euro Medium Term Note Programme

PART A – CONTRACTUAL TERMS

Terms used herein shall be deemed to be defined as such for the purposes of the Conditions set forth in the Prospectus dated 3 December 2007 [and the supplemental Prospectus dated [•]] which [together] constitute[s] a base prospectus for the purposes of the Prospectus Directive (Directive 2003/71/EC) (the “Prospectus Directive”). This document constitutes the Final Terms of the Instruments described herein for the purposes of Article 5.4 of the Prospectus Directive and must be read in conjunction with such Prospectus [as so supplemented]. Full information on the Issuer and the offer of the Instruments is only available on the basis of the combination of these Final Terms and the Prospectus. [The Prospectus [and the supplemental Prospectus] [is] [are] available for viewing [at [website] [and] during normal business hours at [address] [and copies may be obtained from [address]].

[Include whichever of the following apply or specify as “Not Applicable” (N/A). Note that the numbering should remain as set out below, even if “Not Applicable” is indicated for individual paragraphs or sub-paragraphs. Italics denote guidance for completing the Final Terms.]

[When completing final terms or adding any other final terms or information consideration should be given as to whether such terms or information constitute “significant new factors” and consequently trigger the need for a supplement to the Prospectus under Article 16 of the Prospectus Directive.]


1.	Issuer:		National Grid USA

2.	(i)	Series Number:	[ ]

	(ii)	Tranche Number:	[ ]

	(If fungible with an existing Series, details of that Series, including the date on which the Instruments become fungible).]

3.	Specified Currency or Currencies:		[ ]

4.	Aggregate Nominal Amount:		[ ]

	[(i)]	Series:	[ ]

	[(ii)]	Tranche:	[ ]

5.	Issue Price:		[ ] per cent of the Aggregate Nominal Amount [plus accrued interest from [insert date] (if applicable)]

6.	(i)	Specified Denominations:	[ ]^*


^*		Instruments which have a maturity of less than one year must have a minimum denomination of £100,000 (or it equivalent in other currencies)


	(ii)	Calculation Amount:	[If only one Specified Denomination, insert the Specified Denomination. If more than one Specified Denomination, insert the highest common factor] [Note: There must be a common factor in the case of two or more Specified Denominations]

7.	[(i)]	Issue Date:	[ ]]

	[(ii)]	Interest Commencement Date:	[Specify/Issue Date/Not Applicable]	A13.4.

8.	Maturity Date:		[specify date or (for Floating Rate Instruments) Interest Payment Date falling in or nearest to the relevant month and year]

9.	Interest Basis:		[[•] per cent. Fixed Rate] [[specify reference rate] +/- [•] per cent. Floating Rate] [Zero Coupon] [Other (specify)] (further particulars specified below)	A13.4.

10.	Redemption/Payment Basis:		[Redemption at par] [Dual Currency] [Partly Paid] [Instalment] [Other (specify)]	A13.4.

			[N.B. If the Final Redemption Amount is less than 100 per cent. of the nominal value, the Instruments will constitute derivative securities for the purposes of the Prospectus Directive and the requirements of Annex XII to the Prospectus Directive Regulation No. 809/2004 will apply and the Issuer will prepare and publish a supplement to the Prospectus.]

11.	Change of Interest or Redemption/Payment Basis:		[Specify details of any provision for convertibility of Instruments into another interest or redemption/ payment basis]

12.	Put/Call Options:		[Investor Put] [Issuer Call] [(further particulars specified below)]

13.	(i)	Status of the Instruments:	Senior

	(ii)	Date [Board] approval for issuance of Instruments obtained:	[ ] [and [ ], respectively]] (N.B Only relevant where Board (or similar) authorisation is required for the particular tranche of Instruments)]

14.	Method of distribution:		[Syndicated/Non-syndicated]

	PROVISIONS RELATING TO INTEREST (IF ANY) PAYABLE

15.	Fixed Rate Instrument Provisions		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Rate[(s)] of Interest:	[ ] per cent. per annum [payable [annually/semi-annually/quarterly/monthly] in arrear]


	(ii)	Interest Payment Date(s):	[ ] in each year

	(iii)	Fixed Coupon Amount[(s)]:	[•] per Calculation Amount

	(iv)	Broken Amount(s):	[•] per Calculation Amount, payable on the Interest Payment Date falling [in/on] [•]

	(v)	Day Count Fraction (Condition 3.11):	[30/360 / Actual/Actual ([ICMA]/ISDA)/other]

	(vi)	Determination Dates (Condition 3.11):	[ ] in each year (insert regular interest payment dates, ignoring issue date or maturity date in the case of a long or short first or last coupon. N.B. only relevant where Day Count Fraction is Actual/Actual ([ICMA]))

	(vii)	Other terms relating to the method of calculating interest for Fixed Rate Instruments:	[Not Applicable/give details]

16.	Floating Rate Instrument Provisions		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Interest Period(s):	[ ]

	(ii)	Specified Interest Payment Dates:	[ ]

	(iii)	Business Day Convention:	[Floating Rate Convention/ Following Business Day Convention/ Modified Following Business Day Convention/ Preceding Business Day Convention/ other (give details)]

	(iv)	First Interest Payment Date:	[ ]

	(v)	Business Centre(s) (Condition 3.11):	[ ]

	(vi)	Manner in which the Rate(s) of Interest is/are to be determined:	[Screen Rate Determination/ISDA Determination/other (give details)]

	(vii)	Interest Period Date(s):	(Not Applicable unless different from Interest Payment Date)

	(viii)	Party responsible for calculating the Rate(s) of Interest and Interest Amount(s) (if not the Calculation Agent):	[ ]

	(ix)	Screen Rate Determination (Condition 3.2.3(b)):

		– Reference Rate:	[ ]

		– Interest Determination Date(s):	[[ ][TARGET] Business Days in [specify city] for [specify currency] prior to [the first day in each Interest Accrual Period/each Interest Payment Date]]

		– Relevant Screen Page:	[ ]

		– Reference Banks (if Primary Source is “Reference Banks”):	[Specify five]

	(x)	ISDA Determination (Condition 3.2.3(a)):


		– Floating Rate Option:	[ ]

		– Designated Maturity:	[ ]

		– Reset Date:	[ ]

		– [ISDA Definitions: (if different from those set out in the Conditions)	[2000/2006]]

	(xi)	Margin(s):	[+/-][ ] per cent. per annum

	(xii)	Minimum Rate of Interest:	[ ] per cent. per annum

	(xiii)	Maximum Rate of Interest:	[ ] per cent. per annum

	(xiv)	Day Count Fraction (Condition 3.11):	[ ]

	(xv)	Fall back provisions, rounding provisions, denominator and any other terms relating to the method of calculating interest on Floating Rate Instruments, if different from those set out in the Conditions:	[ ]

17.	Zero Coupon Instrument Provisions		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Amortisation Yield (Condition 4.4):	[ ] per cent. per annum

	(ii)	Day Count Fraction (Condition 3.11):	[ ]

	(iii)	Any other formula/basis of determining amount payable:	[ ]

18.	Dual Currency Instrument Provisions		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Rate of Exchange/method of calculating Rate of Exchange:	[give details]

	(ii)	Calculation Agent, if any, responsible for calculating the principal and/or interest due:	[ ]

	(iii)	Provisions applicable where calculation by reference to Rate of Exchange impossible or impracticable:	[ ]

	(iv)	Person at whose option Specified Currency(ies) is/are payable:	[ ]

	(v)	Day Count Fraction (Condition 3.11):	[ ]

	PROVISIONS RELATING TO REDEMPTION

19.	Residual Holding Call Option		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Residual Holding Percentage:	[ ] per cent.

	(ii)	Party responsible for calculating the	[ ]


		Residual Holding Redemption Amount (if not the Calculation Agent):

	(iii)	Benchmark Security:	[Specify Government Security/swap benchmark]

	(iv)	Benchmark Spread:	[ ] per cent. per annum

	(v)	Benchmark Day Count Fraction:	[ ]

	(vi)	[Other relevant provisions:	[ ]]

20.	Call Option^†		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Optional Redemption Date(s):	[ ]

	(ii)	Optional Redemption Amount(s) of each Instrument and method, if any, of calculation of such amount(s):	[ ] per Calculation Amount

	(iii)	If redeemable in part:

		(a) Minimum nominal amount to be redeemed:	[ ] per Calculation Amount

		(b) Maximum nominal amount to be redeemed:	[ ] per Calculation Amount

	(iv)	Option Exercise Date(s):	[ ]

	(v)	Notice period (if other than as set out in the Conditions)	[ ]

21.	Put Option		[Applicable/Not Applicable] (If not applicable, delete the remaining sub-paragraphs of this paragraph)

	(i)	Optional Redemption Date(s):	[ ]

	(ii)	Optional Redemption Amount(s) of each Instrument and method, if any, of calculation of such amount(s):	[ ] per Calculation Amount

	(iii)	Option Exercise Date(s):	[ ]

	(iv)	Notice period (if other than as set out in the Conditions)	[ ]

22.	Final Redemption Amount of each Instrument:		[ ] per Calculation Amount

	(i)	Formula:	[give or annex details]

	(ii)	Calculation Agent responsible for calculating the Final Redemption Amount:	[ ]

	(iii)	Provisions for determining Final Redemption Amount where calculated by reference to Formula and/or other variable:	[give or annex details]


^†		This does not include the tax call in Condition 4.2 or the call option contained in Condition 4.5.1


	(iv)	Determination Date(s):	[ ]

	(v)	Provisions for determining Final Redemption Amount where calculation by reference to Index and/or Formula and/or other variable is impossible or impracticable or otherwise disrupted:	[ ]

	(vi)	Payment Date:

	(vii)	Minimum Final Redemption Amount:	[ ] per Calculation Amount

	(viii)	Maximum Final Redemption Amount:	[ ] per Calculation Amount

23.	Early Redemption Amount

	(i)	Early Redemption Amount(s) of each Instrument payable on redemption for taxation reasons (Condition 4.2) or on Event of Default (Condition 8) or other early redemption and/or the method of calculating the same (if required or if different from that set out in the Conditions):	[ ]

	(ii)	Redemption for taxation reasons permitted on days other than Interest Payment Dates (Condition 4.2)	[Yes/No]

	(iii)	Unmatured Coupons to become void upon early redemption (Condition 5.5)	[Yes/No/Not Applicable]

	GENERAL PROVISIONS APPLICABLE TO THE INSTRUMENTS

24.	Form of Instruments:		Bearer Instruments:

			[temporary Global Instrument exchangeable for a permanent Global Instrument which is exchangeable for Definitive Instruments in the limited circumstances specified in the permanent Global Instrument]

			[temporary Global Instrument exchangeable for Definitive Instruments in the limited circumstances specified in the temporary Global Instrument]

			[permanent Global Instrument exchangeable for Definitive Instruments in the limited circumstances specified in the permanent Global Instrument]

25.	New Global Note		[Yes] [No]

26.	Financial Centre(s) or other special provisions relating to Payment Dates (Condition 5.6):		[Not Applicable/give details. Note that this item relates to the date and place of payment, and not interest period end dates, to which item 16(iv) relates]

27.	Applicable TEFRA exemption:		[D Rules/Not Applicable]

28.	Talons for future Coupons or Receipts to be attached to Definitive Instruments (and		[Yes/No.If yes, give details]


	dates on which such Talons mature):

29.	Details relating to Partly Paid Instruments: amount of each payment comprising the Issue Price and date on which each payment is to be made and consequences (if any) of failure to pay, including any right of the Issuer to forfeit the Instruments and interest due on late payment:		[Not Applicable/give details]

30.	Details relating to Instalment Instruments:		[Not Applicable/give details]

	–	Amount of each instalment:	[ ]

	–	Date on which each payment is to be made:	[ ]

	–	Maximum Instalment Amount:

	–	Minimum Instalment Amount:	[ ]

31.	Redenomination, renominalisation and reconventioning provisions:		[Not Applicable/give details]

32.	Consolidation provisions:		[Not Applicable/give details]

33.	Other final terms:		[Not Applicable/give details] (When adding any other final terms consideration should be given as to whether such terms constitute a “significant new factor” and consequently trigger the need for a supplement to the Prospectus under Article 16 of the Prospectus Directive.)

	DISTRIBUTION

34.	(i)	If syndicated, names of Managers:	[Not Applicable/give names]

	(ii)	Stabilising Manager(s) (if any):	[Not Applicable/give name]

35.	If non-syndicated, name of Dealer:		[Not Applicable/give name]

36.	Additional selling restrictions:		[Not Applicable/give details]

[PURPOSE OF FINAL TERMS

These Final Terms comprise the final terms required to list and have admitted to trading the issue of Instruments described herein pursuant to the Euro Medium Term Note Programme of National Grid USA.]

RESPONSIBILITY

The Issuer accepts responsibility for the information contained in these Final Terms. [[•] has been extracted from [•]. The Issuer confirms that such information has been accurately reproduced and that, so far as it is aware, and is able to ascertain from information published by [•], no facts have been omitted which would render the reproduced information inaccurate or misleading.]

Signed on behalf of the Issuer:

By: .............................

Duly authorised

PART B – OTHER INFORMATION^*


1	Listing

	(i)	Listing:	[London/other (specify)/None]

	(ii)	Admission to trading:	[Application has been made for the Instruments to be admitted to trading on the London Stock Exchange plc’s Gilt-Edged and Fixed Interest Market with effect from [ ].] [Not Applicable.]

	(iii)	Estimate of total expenses related to admission o trading:	[ ]

2	Ratings

	Ratings:		The Instruments to be issued have been rated: [S & P: [ ]] [Moody’s: [ ]] [[Other]: [ ]] (The above disclosure should reflect the rating allocated to Instruments of the type being issued under the Programme generally or, where the issue has been specifically rated, that rating.)

3	[Notification

	The Financial Services Authority [has been requested to provide/has provided – include first alternative for an issue which is contemporaneous with the update of the Programme and the second alternative for subsequent issues] the [include names of competent authorities of host Member States] with a certificate of approval attesting that the Prospectus has been drawn up in accordance with the Prospectus Directive.]^**

4	[Interests of Natural and legal Persons involved in the Issue

	Need to include a description of any interest, including conflicting ones, that is material to the issue/offer, detailing the persons involved and the nature of the interest. May be satisfied by the inclusion of the following statement:

	“So far as the Issuer is aware, no person involved in the offer of the Instruments has an interest material to the offer.”]

	[(When adding any other description, consideration should be given as to whether such matters described constitute “significant new factors” and consequently trigger the need for a supplement to the Prospectus under Article 16 of the Prospectus Directive.)]


^*		If an issue of Instruments is (i) NOT admitted to trading on a regulated market within the European Economic Area and (ii) only offered in the European Economic Area in circumstances where a prospectus is not required to be published under the Prospectus Directive the Issuer may elect to amend and/or delete certain of the above paragraphs of Part B.

^**		Required for derivative securities to which Annex XII to the Prospectus Directive Regulation applies.


5	[Reasons for the Offer, Estimated Net Proceeds and Total Expenses

	(i)	[Reasons for the offer	[ ]

			(See [“Use of Proceeds”] wording in Prospectus – if reasons for offer different fromgeneral corporate purposeswill need to include those reasons here.)]

	(ii)	[Estimated net proceeds:	[ ]

			(If proceeds are intended for more than one use will need to split out and present in order of priority. If proceeds insufficient to fund all proposed uses state amount and sources of other funding.)

	(iii)	[Estimated total expenses:	[ ][Include breakdown of expenses.]

			([If the Instruments are derivative securities for which Annex XII of the Prospectus Directive Regulation applies it is] only necessary to include disclosure of net proceeds and total expenses at (ii) and (iii) above where disclosure is included at (i) above.)]^*

6	[Fixed Rate Instruments only – YIELD

	Indication of yield:		[ ]

			The yield is calculated at the Issue Date on the basis of the Issue Price. It is not an indication of future yield.]

7	[Dual Currency Instruments only – PERFORMANCE OF RATE[S] OF EXCHANGE

	Need to include details of where past and future performance and volatility of the relevant rate[s] can be obtained.]^*

	[(When completing this paragraph, consideration should be given as to whether such matters described constitute “significant new factors” and consequently trigger the need for a supplement to the Prospectus under Article 16 of the Prospectus Directive.)]

8	OPERATIONAL INFORMATION

	ISIN Code:		[ ]

	Common Code:		[ ]

	Any clearing system(s) other than Euroclear Bank S.A./N.V. and Clearstream Banking société anonyme and the relevant identification number(s):		[Not Applicable/give name(s) and number(s) [and address(es)]]
	Delivery:		Delivery [against/free of] payment

	Names and addresses of additional Paying Agent(s) (if any):		[ ]

	Intended to be held in a manner which would allow Eurosystem		[Yes][No] [Note that the designation “Yes” simply means that the Instruments are intended upon issue to be deposited with Euroclear or Clearstream, Luxembourg as Common Safekeeper and does not


^*		Required for derivative securities to which Annex XII to the Prospectus Directive Regulation applies.


	eligibility:	necessarily mean that the Instruments will be recognised as eligible collateral for Eurosystem monetary policy and intra-day credit operations by the Eurosystem either upon issue or at any or all times during their life. Such recognition will depend upon satisfaction of the Eurosystem eligibility criteria.][Include this text if “Yes” selected in which case the Instruments must be issued in NGN form]

9	General

	The aggregate principal amount of Instruments issued has been translated into Euro at the rate of [•], producing a sum of (for Instruments not denominated in Euro):	[Not Applicable/[[Euro]][•]]

	Additional steps that may only be taken following approval by an Extraordinary Resolution in accordance with Condition 10.1:	[Not Applicable/give details]

GENERAL INFORMATION

	1.		The admission of the Programme to listing on the Official List of the U.K. Listing Authority and to trading on the Market is expected to take effect on or about 6 December 2007. The listing of the Instruments on the Official List will be expressed as a percentage of their nominal amount (exclusive of accrued interest). Any Tranche of Instruments intended to be admitted to listing on the Official List of the U.K. Listing Authority and admitted to trading on the Market will be so admitted to listing and trading upon submission to the U.K. Listing Authority and the Market (in accordance with their rules and procedures) of the relevant Final Terms and any other information required by the U.K. Listing Authority and the Market, subject in each case to the issue of the relevant Instruments. Prior to official listing, dealings will be permitted by the Market in accordance with its rules. Transactions will normally be effected for delivery on the third working day in London after the day of the transaction.

			However, Instruments may be issued pursuant to the Programme which will not be admitted to listing and/or trading by the U.K. Listing Authority or the Market or any other listing authority, stock exchange and/or quotation system or which will be admitted to listing, trading and/or quotation by such listing authority, stock exchange and/or quotation system as the Issuer and the relevant Dealer(s) may agree.

	2.		The Issuer has obtained all necessary consents, approvals and authorisations in the United States of America in connection with the issue and performance of the Instruments.

	3.		The establishment of the Programme was authorised by a resolution of the Executive Committee of the Board of Directors of the Issuer passed on 14 November 2007.

	4.		The Instruments have been accepted for clearance through the Euroclear and Clearstream, Luxembourg. The appropriate common code and the International Securities Identification Number in relation to the Instruments of each Series will be specified in the Final Terms relating thereto. The relevant Final Terms shall specify any other clearing system(s) as shall have accepted the relevant Instruments for clearance together with any further appropriate information.

	5.		Neither the Issuer nor any of it subsidiaries is or has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Issuer is aware) during the 12 months preceding the date of this Prospectus which may have, or have in such period had, significant effects on the financial position or profitability of the Issuer or of the Group.

	6.		Save as disclosed in “Description of National Grid USA – Recent Developments”, there has been no significant change in the financial or trading position of the Issuer or the Group since 31 March 2007 and no material adverse change in the prospects of the Issuer since 31 March 2007.

	7.		PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm of 125 High Street, Boston, MA 02110 (members of the American Institute of Certified Public Accountants), have audited, and rendered unqualified audit reports on, the consolidated financial statements prepared under U.S. GAAP of the Issuer for the years ended 31 March 2007 and 31 March 2006.

	8.		Each Instrument having a maturity of more than one year, Receipt, Coupon and Talon will bear the following legend: “Any United States person who holds this obligation will be subject to limitations under the United States income tax laws, including the limitations provided in Sections 165(j) and 1287(a) of the Internal Revenue Code”.

	9.		For so long as the Programme remains in effect or any Instruments are outstanding, copies of the following documents may be inspected during usual business hours on any weekday (Saturdays,

Sundays and public holidays excepted), at the registered offices of the Issuer and the specified office in London of the Issuing and Paying Agent:

	(a)		a copy of this Prospectus together with any supplement to this Prospectus or further Prospectus;

	(b)		the constitutional documents of the Issuer; and

	(c)		the audited consolidated accounts of the Issuer for the financial years ended 31 March 2006 and 31 March 2007, respectively, and any consolidated interim accounts of the Issuer published subsequently to such accounts.

In addition, this Prospectus is and, in the case of Instruments to be admitted to the Official List and admitted to trading on the Market, the relevant Final Terms will be, available on the website of the Regulatory News Service operated by the London Stock Exchange atwww.londonstockexchange.com/en-gb/pricesnews/marketnews.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED FINANCIAL STATEMENTS OF NATIONAL GRID USA FOR THE TWO
YEARS ENDED 31 MARCH 2007 AND 31 MARCH 2006

2007


1	Report of Independent Registered Public Accounting Firm	F-2

2	Consolidated Statements of Income for the years ended 31 March 2007 and 2006	F-3

3	Consolidated Statements of Comprehensive Income for the years ended 31 March 2007 and 2006	F-4

4	Consolidated Statements of Retained Earnings for the years ended 31 March 2007 and 2006	F-4

5	Consolidated Balance Sheets as at 31 March 2007 and 2006	F-5

6	Consolidated Statements of Cash Flow for the years ended 31 March 2007 and 2006	F-8

7	Notes to the Consolidated Financial Statements	F-10

The following pages have been extracted from the audited annual report for 2007 for National Grid USA, which have been prepared in accordance with auditing principles generally accepted in the United States of America.

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of National Grid USA:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of National Grid USA and its subsidiaries at March 31, 2007 and March 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended March 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note F to the financial statements, the Company adopted a new principle of accounting pension and postretirement benefit plans in accordance with Financial Accounting Standards Board Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In accordance with the provision of FASB No. 158, the 2007 financial statements include the adjustment to initially apply this new accounting principle as of March 31, 2007.

PricewaterhouseCoopers LLP

July 12, 2007

F-2

NATIONAL GRID USA AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
(In thousands of dollars)


	For the years ended
	March 31,
	2007			2006
Operating revenues:
Electric	$	6,944,416		$	7,141,941
Gas		1,217,947			1,037,081

Total operating revenues		8,162,363			8,179,022

Operating expenses:
Purchased energy:
Electricity purchased		3,483,915			3,544,029
Gas purchased		814,868			741,419
Contract termination charges and nuclear unit shutdown charges		63,845			73,364
Other operation and maintenance		1,691,596			1,440,325
Depreciation and amortization		410,997			387,673
Amortization of stranded costs and rate plan deferrals		455,632			532,987
Other taxes		342,668			323,974
Income taxes		187,966			319,232

Total operating expenses		7,451,487			7,363,003

Operating income		710,876			816,019

Other deductions, net		(3,891	)		(13,542	)

Operating and other deductions		706,985			802,477

Interest (income) expense:
Interest on long-term debt		138,573			172,629
Interest income		(32,254	)		(14,476	)
Interest on debt to associated companies		96,479			58,676
Other interest		42,310			25,959

Total interest expense, net		245,108			242,788

Net income from continuing operations		461,877			559,689

Discontinued operations:
Income from discontinued operations, net of tax of $10,641 and $2,668		11,717			2,376
Goodwill impairment		(120,204	)		—

Net income (loss) from discontinued operations		(108,487	)		2,376

Net income	$	353,390		$	562,065

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

F-3

NATIONAL GRID USA AND SUBSIDIARY COMPANIES
Consolidated Statements of Comprehensive Income
(In thousands of dollars)


	For the years ended
	March 31,
	2007			2006
Net income	$	353,390		$	562,065
Other comprehensive income (loss):
Unrealized gains on securities, net of taxes		6,003			6,217
Hedging activity, net of taxes		(17,526	)		4,009
Change in additional minimum pension liability		(6,278	)		182,489
Reclassification adjustment for gains (losses) included in net income, net of taxes		18,464			(24,810	)

Total other comprehensive income		663			167,905

Comprehensive income	$	354,053		$	729,970

Adjustment to initially apply SFAS No. 158		(398,145	)		—

Change in accumulated other comprehensive income (loss)	$	(397,482	)	$	167,905

Consolidated Statements of Retained Earnings
(In thousands of dollars)


	For the years ended
	March 31,
	2007			2006
Retained earnings at beginning of period	$	1,484,597		$	980,101
Net income		353,390			562,065
Dividends on preferred stock		(2,096	)		(2,210	)
Dividends on common stock		(286,052	)		(55,000	)
Other		139			(359	)

Retained earnings at end of period	$	1,549,978		$	1,484,597

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

F-4

NATIONAL GRID USA AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


	March 31,
	2007			2006
ASSETS
Utility plant, at original cost:
Electric plant	$	11,518,971		$	10,921,706
Gas plant		2,145,412			1,568,845
Common plant		358,124			382,167
Construction work-in-process		259,825			339,644

Total utility plant		14,282,332			13,212,362
Less: accumulated depreciation and amortization		(4,593,150	)		(4,238,319	)

Net utility plant		9,689,182			8,974,043

Goodwill		3,338,791			3,076,752
Pension intangible		—			36,885
Other property and investments		316,252			321,273
Current assets:
Cash and cash equivalents		281,895			213,954
Restricted cash		63,051			80,265
Accounts receivable (less reserves of $165,242 and $149,492, respectively, including $10,388 and $11,571 from affiliates, respectively)		1,417,657			1,325,945
Materials and supplies, at average cost:
Gas storage		20,906			23,576
Other		59,686			48,363
Current portion of accumulated deferred income taxes		176,208			195,476
Current portion of regulatory assets		303,973			393,213
Assets of discontinued operations		305,120			252,964
Other		169,701			108,802

Total current assets		2,798,197			2,642,558

Other non-current assets:
Regulatory assets		5,101,370			5,264,789
Prepaid employee pension benefits		—			360,183
Other		67,764			49,967

Total non-current assets		5,169,134			5,674,939

Total assets	$	21,311,556		$	20,726,450

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

F-5

NATIONAL GRID USA AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


	March 31,
	2007			2006
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholder’s equity:
Common stock ($.10 par value)	$	—		$	—
Authorized - 3,000 shares
Issued and outstanding - 1,000 shares
Additional paid-in capital		7,599,045			7,099,046
Retained earnings		1,549,978			1,484,597
Accumulated other comprehensive loss		(401,738	)		(4,256	)

Total common stockholder’s equity		8,747,285			8,579,387
Minority interest in subsidiaries		16,397			17,712
Cumulative preferred stock		52,317			52,317
Long-term debt		1,968,528			2,125,241
Long-term debt to affiliates		1,200,000			1,200,000

Total capitalization		11,984,527			11,974,657

Current liabilities:
Accounts payable		698,433			614,725
Customers’ deposits		51,294			40,770
Accrued interest		75,136			50,506
Accrued taxes		33,197			169,998
Short-term debt due to affiliates		1,028,866			644,168
Current portion of long-term debt		218,873			302,320
Current portion of accrued Yankee nuclear plant costs		28,527			54,796
Current portion of derivatives and swap contracts		264,497			324,858
Current portion of purchased power obligations		10,949			13,559
Liabilities of discontinued operations		34,887			29,590
Current regulatory liabilities		129,286			67,921
Accrued wages and benefits		96,819			97,322
Other		86,513			55,954

Total current liabilities		2,757,277			2,466,487

Other non-current liabilities:
Accumulated deferred income taxes		1,988,880			2,223,355
Unamortized investment tax credits		61,347			67,593
Accrued Yankee nuclear plant costs		117,416			140,832

F-6


	March 31,
	2007		2006
Purchased power obligations		14,587		23,688
Derivatives and swap contracts		254,663		538,882
Accrued employee pension and other benefits		1,570,696		719,524
Additional minimum pension liability		—		127,351
Environmental remediation costs		582,787		569,319
Nuclear fuel disposal costs		158,195		150,642
Regulatory liabilities		1,491,118		1,355,595
Other		330,063		368,525

Total other non-current liabilities		6,569,752		6,285,306

Total capitalization and liabilities	$	21,311,556	$	20,726,450

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

F-7

NATIONAL GRID USA AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flow
(In thousands of dollars)


	For the years ended
	March 31,
	2007			2006
Operating activities:
Net income	$	353,390		$	562,065
Adjustments to reconcile net income to net cash provided by operating activities:		—			—
Impairment of goodwill of discontinued operations		120,204
Net income from discontinued operations		(11,717	)		(2,376	)
Depreciation and amortization		410,997			387,673
Amortization of stranded costs and rate plan deferrals		455,632			532,987
Provision for deferred federal and state income taxes and investment tax credits, net		108,579			34,880
Net operating activities from discontinued operations		18,166			13,779
Changes in operating assets and liabilities:
Accounts receivable, net		(19,051	)		(213,686	)
Materials and supplies		27,446			(25,989	)
Prepaids and other current assets		(59,129	)		(12,175	)
Accounts payable and accrued expenses		105,015			187,653
Accrued interest and taxes		(115,646	)		(18,003	)
Pension and postretirement regulatory assets		(117,671	)		(18,813	)
Purchased power obligations		(158	)		(9,697	)
Keypsan acquisition costs		(28,266	)		(942	)
Other, net		(78,420	)		(65,314	)

Net cash provided by operating activities		1,169,371			1,352,042

Investing activities:
Plant expenditures		(787,174	)		(679,785	)
Acquisition of gas assets		(496,720	)		—
Sale of assets		1,888			2,268
Change in restricted cash		17,214			(64,977	)
Other, net		64,812			(32,493	)
Net investing activities for discontinued operations		(176,916	)		(7,236	)

Net cash used in investing activities		(1,376,896	)		(782,223	)

Financing activities:
Dividends paid on preferred stock		(2,096	)		(2,210	)
Dividends paid on common stock		(286,052	)		(55,000	)
Dividends paid on common stock of minority interests		(2,202	)		(3,822	)

F-8


	For the years ended
	March 31,
	2007			2006
Capital contribution from parent for Rhode Island gas acquisition		500,000			—
Payment of long-term debt		(317,157	)		(632,725	)
Proceeds from long-term debt		—			28,000
Buyback of minority interest common stock		(1,670	)		(1,158	)
Net change in short-term debt to affiliates		384,698			(43,000	)
Capital contribution to discontinued operations		(158,750	)		—
Net financing activities for discontinued operations		158,750			—
Other, net		(55	)		(528	)

Net cash (used in) provided by financing activities		275,466			(710,443	)

Net increase (decrease) in cash and cash equivalents		67,941			(140,624	)
Cash and cash equivalents, beginning of period		213,954			354,578

Cash and cash equivalents, at end of period		281,895			213,954

Supplemental disclosures of cash flow information:

Interest paid	$	255,172		$	279,224
Taxes paid		252,831			157,250

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

F-9

		NOTE A – SIGNIFICANT ACCOUNTING POLICIES

1		Nature of Operations

		National Grid USA (the Company) is a public utility holding company with regulated subsidiaries engaged in the transmission, distribution, and sale of electricity and natural gas. The Company is a wholly owned subsidiary of National Grid plc. The Company’s electricity and gas distribution subsidiaries serve approximately 4.1 million customers in New York State, Massachusetts, Rhode Island and New Hampshire. The Company’s transmission subsidiaries provide electricity transmission in New York through Niagara Mohawk Power Corporation (Niagara Mohawk) and in New England principally through New England Power Company (NEP) and The Narragansett Electric Company (Narragansett). In August 2006, the Company acquired the Rhode Island gas assets of New England Gas Company (see Note L — Acquisitions). For unregulated subsidiaries engaged in construction and leasing of telecommunications infrastructures see Note M — “Discontinued Operations.”

2		Basis of Presentation

		The Company’s accounting policies conform to generally accepted accounting principles in the United States of America (US GAAP), including accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated subsidiaries), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities having jurisdiction (see below).

		The consolidated financial statements include the accounts of the Company and all of its wholly-owned subsidiaries and minority interests. All intercompany transactions and balances between consolidated subsidiaries have been eliminated.

		The Company owns approximately 53.7 percent of the outstanding common stock of both New England Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation (together, the Hydro-Transmission companies). The Hydro-Transmission companies own and operate an international transmission interconnection between Hydro-Quebec (a generation facility in Quebec, Canada) and New England. The consolidated financial statements include 100 percent of the assets, liabilities, and earnings of the Hydro-Transmission companies. Minority interests in the Hydro-Transmission companies, which represent the minority stockholders’ proportionate share of the equity, is separately disclosed on the Company’s consolidated balance sheet and the proportionate share of income is included in ‘Other deductions, net’ on the Company’s consolidated statements of income.

		NEP has a minority ownership interest in each of three regional nuclear generating companies which own generating facilities that are permanently shut down. NEP accounts for these ownership interests under the equity method.

3		Use of Estimates

		The preparation of financial statements in conformity with US GAAP requires management to make estimates that affect the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities as of the date of the balance sheets, and revenues and expenses for the period. These estimates may differ from actual amounts if future circumstances cause a change in the assumptions used to calculate these estimates.

4		Regulation

		The Company’s regulated subsidiaries must comply with the rules prescribed by the Federal Energy Regulatory Commission (FERC) and the applicable state utility commissions of New York, Massachusetts, Rhode Island and New Hampshire. See Note B – “Rates and Regulatory.” Niagara

F-10

Mohawk files reports with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended.

5		Goodwill

		National Grid plc’s acquisitions of the Company’s subsidiaries including the acquisitions by the Company of Eastern Utilities Associates (EUA), Niagara Mohawk, and the Rhode Island gas assets of New England Gas Company (see Note L – “Acquisitions”), were accounted for by the purchase method, the application of which includes the recognition of goodwill. Goodwill was approximately $3.3 billion and $3.1 billion at March 31, 2007 and 2006, respectively. In accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” the Company reviews its goodwill annually for impairment and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. During fiscal year 2007, goodwill increased by approximately $262 million. This amount primarily related to (i) an increase to Narragansett goodwill of $236 million due to the acquisition of the Rhode Island gas assets from Southern Union Company and (ii) an increase to Niagara Mohawk of $26 million due to an adjustment related to a tax contingency. Included in ‘Assets of discontinued operations’ is a decrease of $94 million of goodwill composed of a $26 million increase related to acquisitions offset by a $120 million write-down due to impairment of goodwill.

6		Electric and Gas Utility Revenue

		The Company’s regulated subsidiaries charge customers for electric and gas service in accordance with rates approved by the FERC and the applicable state regulatory commissions.

		All of the Company’s distribution subsidiaries, except for Granite State Electric, follow the policy of accruing the estimated amount of base rate revenues for electricity delivered but not yet billed (unbilled revenues), to match costs and revenues. The unbilled revenue included in accounts receivable at March 31, 2007 and 2006 was approximately $351 million and $291 million, respectively. The distribution subsidiaries record revenues in amounts management believes to be recoverable pursuant to provisions of approved settlement agreements and state legislation. The distribution subsidiaries normalize the difference between revenue and expenses from energy conservation programs, commodity purchases, transmission service and contract termination charges (CTCs).

		The Company recognizes changes in unbilled revenues in its results of operations with the exception of Niagara Mohawk’s unbilled gas revenue. Pursuant to Niagara Mohawk’s 2000 multi-year gas settlement (which ended December 2004, and remains effective until Niagara Mohawk requests a change in rates), changes in accrued unbilled gas revenues are deferred. At March 31, 2007 and 2006, approximately $18 million and $6 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. Management cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.

7		Utility Plant

		The cost of additions to utility plant and replacements of retired units of property are capitalized. Costs include direct material, labor, overhead and allowance for funds used during construction (AFUDC) (see below). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

8		AFUDC

		The Company capitalizes AFUDC as part of construction costs in amounts equivalent to the cost of funds devoted to plant under construction for its regulated businesses. AFUDC represents the composite

F-11

interest and equity costs of capital funds used to finance that portion of construction costs not yet eligible for inclusion in rate base. AFUDC is capitalized in “Utility plant” with offsetting cash credits to “Other interest” and non-cash credits to “Other income (deductions), net.” This method is in accordance with an established rate-making practice under which a utility is permitted to earn a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFUDC rates were approximately 3.2% and 2.4% for the years ended March 31, 2007 and 2006, respectively.

9		Depreciation and Amortization

		Depreciation expense is determined using the straight-line method. The depreciation rates for the regulated subsidiaries are based on periodic studies of the estimated useful lives of the assets and the estimated cost to remove them net of salvage value. The regulated subsidiaries use composite depreciation rates that are approved by the respective federal and state utility commissions. The provision for depreciation as a percentage of weighted average depreciable property (excluding construction work-in-progress) was 3.03% and 3.04% for the fiscal years ended March 31, 2007 and 2006, respectively.

		Regulatory assets, including those covered by CTCs, are amortized in accordance with the provisions of the regulated subsidiaries’ rate settlement agreements and, therefore, are not necessarily amortized on a straight-line basis. NEP and Niagara Mohawk had deferred certain costs related to deregulation, including purchased power contract buyouts, and losses on the sale of generation assets as a regulatory asset (See Note B — “Rates and Regulatory”). Niagara Mohawk’s costs are being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates.

10		Cash Equivalents

		The Company classifies short-term investments with an original maturity of three months or less as cash equivalents.

11		Restricted Cash

		Restricted cash consists of margin accounts for commodity and interest rate hedging activity, health care claims deposits, New York State Department of Conservation securitization for certain site cleanup, and workers’ compensation premium deposits.

		Under the Loan and Trust Agreement for the Massachusetts Development Finance Agency Tax Exempt Electric Utility Revenue Bonds (Nantucket Electric Company Issue), Series 2004A (the Bonds), the Company established a Construction Fund with the Trustee in which the proceeds from the Bonds were deposited. In total, $38 million was deposited to fund the Second Nantucket Cable Project costs. Disbursements from the Construction Fund may be made by the Trustee to pay directly or to reimburse the Company for eligible project costs as directed by requisitions signed by the Company. This requisition process is the only manner in which project costs may be paid from Bond proceeds. As of March 31, 2007, the Company used the entire $38 million of the funds deposited. The project was completed at the beginning of the 2007 fiscal year.

12		Federal and State Income Taxes

		Federal and state income taxes are recorded under the provisions of SFAS No. 109 “Accounting for Income Taxes.” Income taxes have been computed utilizing the asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences. It does this by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

F-12

		Deferred investment tax credits are amortized over the useful life of the underlying property (see Note G – “Income Taxes”).

13		Derivatives

		The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. All derivatives except those qualifying for the normal purchase/normal sale exception are recognized on the balance sheet at their fair value. Fair value is generally determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 125% of the changes in fair value or cash flows of the hedged item. The Company also has purchase power agreements with non-affiliates for the purchase of power and capacity for resale to its retail customers. These agreements generally have no notional amounts and do not meet the definition of a derivative under SFAS No. 133.

14		Comprehensive Income (Loss)

		Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is net income, the other components relate to additional minimum pension liability recognition, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale (see Note D — “Accumulated Other Comprehensive Income (Loss)”).

15		New Accounting Standards

		SFAS No. 123R In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The adoption of SFAS No. 123R on April 1, 2006 did not have a material impact on the Company’s results of operations or its financial position.

		SFAS No. 154 In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement.

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		SFAS No. 154 becomes effective for fiscal years ending after December 15, 2005. The Company adopted it as of its March 31, 2006 fiscal year and the adoption did not have a material impact on the Company’s results of operations or its financial position.

		FASB Interpretation No. 48 In July 2006, the FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting and reporting for uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the provision of this interpretation is required to be reported separately as an adjustment to the opening balance of retained earnings in the year of adoption. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the Company in its 2008 fiscal year. The Company is currently evaluating the impact the adoption of FIN 48 will have on its financial statements and is not yet in a position to determine such effects.

		SFAS No. 157 In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value measurements in financial reporting. While the standard does not expand the use of fair value in any new circumstance, it has applicability to several current accounting standards that require or permit entities to measure assets and liabilities at fair value. This standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The Company is currently evaluating SFAS No. 157 and at this time cannot determine impact, if any, that the potential requirements may have on its financial statements.

		SFAS No. 158 In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or postretirement benefit plan other than pensions to recognize an asset or liability on its balance sheet for the over funded or under funded status of the plan as defined by SFAS No. 158. The Company adopted SFAS No. 158 on March 31, 2007. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For postretirement benefit plans other than pensions (PBOPs), the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation as of year end. At March 31, 2007, the Company recorded a combined liability of $1.2 billion in connection with the adoption of SFAS No. 158. While the offset to this entry would normally be a charge to accumulated other comprehensive income (OCI), certain Company subsidiaries have recorded regulatory assets because they will fully recover their costs. See Note F – “Employee Benefits” for the impact of the adoption of the new standard on the Company’s consolidated financial statements.

		Staff Accounting Bulletin No. 108 In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 requires companies to quantify the impact of correcting misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach. If the misstatement of prior year expense is material to the current year, after all of the relevant quantitative and qualitative factors are considered, the prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. The new standard had no impact on the Company’s consolidated financial statements.

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16		Reclassifications

		Certain amounts from prior years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2007 presentation.

		NOTE B – RATES AND REGULATORY

		The Company’s regulated subsidiaries generally use the same accounting policies and practices for financial reporting purposes as non-regulated companies under US GAAP. However, actions by the FERC and the state utility commissions can result in accounting treatment that is different from that used by non-regulated companies. The Company applies the provisions of the SFAS No. 71, “Accounting for Certain Types of Regulation.” In accordance with SFAS No. 71, the Company’s regulated subsidiaries record regulatory assets (expenses deferred for future recovery from customers) and regulatory liabilities (amounts provided in current rates to cover costs to be incurred in the future) on their balance sheets. This permits the regulated subsidiaries to defer certain costs (because they are expected to be recovered through customer billings) and revenues (because they are expected to be refunded to customers), which would otherwise be charged to expense or revenue, when authorized to do so by the regulator. The Company is earning a return on most of its regulatory assets under its rate plans.

		The following table details the various categories of regulatory assets and liabilities:


	At March 31
	2007			2006
	(In thousands)
Regulatory assets included in accounts receivable:
Rate adjustment mechanisms	$	12,665		$	53,777
Regulatory liabilities included in other accrued expenses:
Rate adjustment mechanisms		(129,286	)		(67,921	)
Current portion of regulatory assets:
Derivative and swap contracts (Note E)		264,497			324,858
Purchase power obligations		10,949			13,559
Yankee nuclear decommissioning costs (Note C)		28,527			54,796

Total net regulatory assets current		187,352			379,069

Regulatory assets:
Stranded costs		2,273,238			2,478,018
Purchase power obligations		119,944			114,829
Derivative and swap contracts (Note E)		254,663			506,328
Regulatory tax asset		139,792			148,678
Deferred environmental restoration costs (Note C)		633,630			563,871
Pension and post-retirement benefit plans other than pension costs (Note F)		1,248,708			550,179
Additional minimum pension liability		—			79,923
Yankee nuclear decommissioning costs (Note C)		117,416			140,832
Loss on reacquired debt		69,223			78,966
Long-term portion of standard offer under-recovery		49,864			46,803
Other		194,892			556,362

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	At March 31
	2007			2006
	(In thousands)
Regulatory liabilities:
Cost of removal reserve		(642,198	)		(537,526	)
Stranded costs and CTC related		(125,113	)		(123,105	)
Pension and post-retirement plans fair value deferred gain (Note F)		(266,485	)		(234,754	)
Interest savings deferral		(92,534	)		(92,534	)
Environmental response fund and insurance recoveries (Note C)		(91,287	)		(81,673	)
Storm costs reserve		(45,551	)		(39,391	)
Other		(227,950	)		(246,612	)

Total net regulatory assets non-current		3,610,252			3,909,194

Net regulatory assets	$	3,797,604		$	4,288,263

		Stranded costs

		Certain regulatory assets, referred to as stranded costs, resulted from major fundamental changes occurring in the public utility industry, most notably the divestiture of generation assets pursuant to deregulation. Under deregulation, the generation segment of the utility business was opened to competition in that consumers could choose their generation supplier. Public utilities continued to control the transmission and distribution of electricity and were encouraged to dispose of generation assets such as power plants. The net unrecovered costs from the sale of these generation assets, along with the costs to terminate, restate or amend existing purchase power contracts were deferred for recovery in rates over future periods. A large portion of these stranded costs are being recovered through a special rate being charged to customers. Similarly, the recovery of costs outside of customer rate recovery, but that nevertheless relate to the former generation business, are credited back to customers as well to offset stranded costs. For the New England regulated subsidiaries, this mechanism is called the Contract Termination Charge and for Niagara Mohawk in New York, it is called the Competitive Transition Charge (in both cases, these charges are called the CTC).

		Management believes that future cash flows from charges for electric service under existing rate plans, including the CTC, will be sufficient to recover the Company’s regulatory assets over the planned amortization period. This assumes that there will be no unforeseen reduction in demand and no bypass of the CTC or exit fees. In the event of revenues that are lower than expected and (or) costs that are higher than expected, if the Company determines that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company’s subsidiaries could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

		Rate Agreements

		NEP New England Regional Transmission Organization (RTO) and Rate Filing:NEP is a participating transmission owner (PTO) in New England’s RTO which commenced operations effective February 1, 2005. ISO New England, Inc. has been authorized by FERC to exercise the operations and system planning functions required of RTOs and will be the independent regional transmission provider under the ISO Open Access Transmission Tariff (ISO-OATT). The ISOOATT is designed to provide non-discriminatory open access transmission services over the transmission facilities of the PTOs and

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		recover their revenue requirements. FERC issued two orders in 2004 and two in 2005 that approved the establishment of the RTO and resolved certain issues concerning the proposed return on common equity (ROE) for New England PTOs. Other return issues were set for hearing. A number of parties, including NEP, have filed appeals from one or more of those orders with the U.S. Court of Appeals for the District of Columbia Circuit.

		Effective on the RTO operations date of February 1, 2005, NEP’s transmission rates began to reflect a proposed base ROE of 12.8 percent, subject to refund, plus an additional 0.5 percent incentive return on regional network service (RNS) rates that FERC approved in March 2004. Approximately 70 per cent. of the Company’s transmission costs are recovered through RNS rates. An additional 1.0 per cent. incentive adder was also applicable to new RNS transmission investment, subject to refund.

		NEP and the other New England Transmission Owners (NETOs) participated in FERC proceedings to determine outstanding ROE issues, including base return on ROE and the proposed 1 percent ROE incentive for new transmission investment. On May 27, 2005, a FERC administrative law judge (ALJ) issued an initial decision which concluded that the base ROE should be 10.72 percent and that NEP and other NETOs are not entitled to the proposed 1 per cent. ROE incentive.

		On October 31, 2006, FERC issued an order establishing the ROE for the NETOs, including NEP. Over the dissent of two Commissioners and overturning the initial decision by the ALJ, FERC approved, as an incentive to build new transmission infrastructure, the proposed 1 percent ROE adder for all new transmission investment approved through the regional system planning process. Although FERC lowered the base ROE recommended by the ALJ by 0.5 percent, it also increased the ROE by 0.7 per cent. on a going-forward basis to reflect changing markets since the time that hearings were held in 2005. Thus, the ROE approved by the order differs for the locked-in period (February 2005 to October 2006) and for the prospective period (November 2006 going forward). The ROE also varies depending on whether costs are recovered through RNS rates or local network service (LNS) rates, and whether the costs are for existing or new facilities. For the locked-in period, the resulting ROEs are 10.7 percent (including a 0.5 percent RTO participation adder) for recovery of existing transmission through RNS rates; 11.7 percent (including 0.5 percent and 1 percent adders) for new transmission costs recovered through RNS; and 10.2 percent (base ROE only) for LNS. For the prospective period beginning November 1, 2006, those ROEs increased to 11.4 percent, 12.4 percent and 10.9 percent respectively. Overall, the ROEs approved by FERC represent an increase from NEP’s last authorized ROE of 10.25 percent.

		The NETOs and opposing parties to the NETOs have requested rehearing of various aspects of the Commission’s order. The NETOs have argued that FERC made an error in its analysis, the correction of which would increase transmission owners’ base return on equity by 0.3 percent. The opposing parties have challenged the Commission’s approval of the 0.7 percent increase on a going forward basis and the additional 1 percent return incentive premium that was approved for new investment.

		Niagara Mohawk Under its Merger Rate Plan (MRP) for electric rates, the Company is authorized to recover actual amounts deferred under the plan for each two-year period, as well as deferrals projected to accrue over the subsequent two-year period that are in excess of a $100 million threshold. The deferrals are subject to regulatory review and approval. On July 29, 2005, the Company made its biannual deferral account recovery filing for balances in the deferral account as of June 30, 2005 plus projected deferrals. On December 27, 2005, the New York State Public Service Commission (PSC) approved recovery of deferral account amounts of $100 million in calendar year 2006 and $200 million in calendar year 2007, and established a timeline for the Department of Public Service Staff (Staff) to perform its audit of the deferral account. For 2006, the deferral surcharge was included in rates beginning in April and the $100 million was collected over the last nine months of the 2006 calendar year. The Staff filed testimony on August 2, 2006, proposing in excess of $200 million of initial adjustments to the deferral balance and projected deferrals. After replies from the Staff and the Company, an evidentiary hearing was held on October 5, 2006. Upon the conclusion of the evidentiary hearings, the Company and the Staff agreed to

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enter into non-binding mediation discussions before an ALJ from the PSC in an attempt to resolve some or all of the amounts remaining in dispute.

Through the mediation process, the Company, the Staff, and Multiple Intervenors (Parties), reached a resolution of the disputed issues presented in the deferral account case as well as other cases pending before the Commission regarding pension costs, the costs of enhanced inspections of the transmission and distribution system, and the sale of the Nine Mile Point nuclear generating facilities. A Stipulation of the Parties (Stipulation) setting forth the resolution of these issues was executed and filed with the Commission on March 23, 2007. A hearing on the Stipulation of the parties was held before the PSC’s ALJ on May 17, 2007.

Under the Stipulation, the Company has agreed to a net reduction of the deferral account balance of approximately $127.0 million. This includes reclassifications from the deferral account to other balance sheet accounts of approximately $64 million. It also includes a reduction to the deferral account balance as of February 28, 2007 and decrease to earnings before income taxes of approximately $63 million. The significant issues resolved under the Stipulation include:

	-		The Company will cease seeking to recover most disputed station service lost revenues. This resulted in a reduction to the deferral account and pre-tax earnings as of February 28, 2007 of $68 million. The impact of the settlement on future revenues depends on the usage by generators and prospective adjustments to delivery rates that are dependent in part on commodity prices. The Company estimates a reduction in revenues of about $9 million to $12 million per year through December 31, 2011 which is the end of the MRP.

	-		The Parties agreed to the method of determining incremental major storm costs related primarily to the treatment of third party contractor costs and costs incurred by affiliates during storm restoration efforts. The definition of a major storm was also clarified under the Stipulation. Storm related adjustments resulted in a reduction of $10 million to the deferral account and pre-tax earnings.

	-		The Parties agreed to the method of determining deferrable incremental costs associated with the Company’s ongoing stray voltage inspection and testing program resulting in a reduction to the deferral account and pre-tax earnings of $4 million.

	-		The Parties agreed to the method for capitalizing fringe benefit overhead costs associated with the Company’s fixed asset construction activities. This resulted in a decrease to utility plant of $17 million, an increase to the deferral account of $11 million, and a reduction in pre-tax earnings of $6 million.

	-		The Company is allowed to reflect 50 percent of pension settlement losses that it incurred in fiscal years 2007 and 2004. This resulted in an increase to the deferral account and pretax earnings of $23 million related to fiscal 2007 and 2004 pension settlement losses, respectively.

	-		Although it has no impact on past or future rates, the Company will exclude goodwill from any future earnings sharing filings and other filings made with the PSC.

Certain deferral account balances as of June 30, 2005 remain subject to audit by the Staff. The Stipulation also clarifies going forward procedures for recording, reporting and auditing of certain other deferrals authorized for recovery. The next biannual deferral account filing will be made by August 1, 2007 for deferral balances as of June 30, 2007 and projected deferrals through December 31, 2009. The Staff will audit future biannual deferral account filings made pursuant to the MRP, however the Parties have agreed that the amount of deferral recoveries in calendar year 2008 and 2009 will not exceed the $200 million level currently being collected in rates. Any deferrals in excess of this recovery level would be subject to recovery after 2009.

Massachusetts Electric Company and Nantucket Electric Company
Rates for services rendered by the Company for the most part are subject to approval by the Massachusetts Department of Public Utilities (DPU). In March 2000, the DPU approved a long-term rate plan for the Company, which became effective on May 1, 2000. As part of the rate plan, the Company

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instituted a $10 million settlement credit that terminated on March 1, 2005. During this period, known as the Rate Freeze Period, distribution rates (after the reduction for the $10 million settlement credit) were frozen. During the period from March 1, 2005 through December 31, 2009, the Rate Index Period, subsequent to the increase in distribution rates resulting from the termination of the $10 million settlement credit, the Company’s distribution rates are adjusted annually, upward or downward, based upon the movement of a distribution index rate (in cents per kilowatt-hour) of similarly unbundled distribution utilities in New England, New York, Pennsylvania and New Jersey. The Company determined that its initial relative position against this index of utilities established using distribution rates in effect July 1, 2004 was less than 90 percent, which allowed it to reflect in distribution rates the effect of terminating the entire $10 million settlement credit. On July 1 of each succeeding year, the Company updates the regional index rate and, based upon the movement, upward or downward, of this regional index rate, adjusts its own distribution rates accordingly effective March 1 of the following year. In the first two such adjustments the Company implemented a 3.5 percent and a 1.6 percent increase in distribution rates pursuant to this mechanism effective March 1, 2006 and March 1, 2007, respectively. During 2009, the Company will file a distribution cost of service to determine the share of earned savings, if any, that it will be able to include in this and future cost of service studies for the purpose of establishing distribution rates to be in effect from January 2010 through May 2020, in accordance with a sharing mechanism defined in the rate plan. The Company will be allowed to retain 100 percent of annual earned savings up to $70 million and 50 percent of annual earned savings between $70 million and $145 million (all figures pre-tax). Earned savings represent the difference between annual distribution revenue based on rates in effect on March 1, 2009 and the Company’s cost of providing service, including a regional average authorized return. These efficiency incentive mechanisms provide an opportunity to achieve returns in excess of traditional regulatory allowed returns.

Nantucket Electric’s distribution rates are linked to Massachusetts Electric’s rates. In addition, Nantucket Electric owns and operates two 46 kilovolt submarine cables that interconnect Nantucket Island to the transmission system on Cape Cod, the costs of which are recovered through a special surcharge to its customers.

The Narragansett Electric Company
Electric segment:In Rhode Island, Narragansett Electric’s distribution rates are governed by a long-term rate plan. Under its rate plan, effective from November 2004 until December 2009, Narragansett Electric agreed to reduce its distribution rates by $10.2 million (pre-tax) per year. Beginning in January 2005, Narragansett has been able to keep an amount equal to 100 percent of its earnings up to an allowed ROE of 10.5 percent, plus $4.65 million (pre-tax), which represents its share of demonstrated savings subsequent to the acquisition of EUA in 2000. Earnings above that amount up to an additional 1 percent ROE are to be shared equally between Narragansett and its customers, while additional earnings will be allocated 75 percent to customers and 25 percent to Narragansett. This regulatory mechanism offers the potential to achieve returns in excess of traditional regulatory allowed returns.

In addition, Narragansett has implemented a customer credit totalling $27.6 million on most of its customers’ bills from November 2004 through December 2005. This credit was designed to return customers’ share of the excess earnings accrued under the merger rate plan approved and implemented in 2000 governing the merger of Narragansett with Blackstone Valley Electric Company and Newport Electric Corporation.

Gas segment:In May 2002, the Rhode Island Public Utility Commission approved a settlement agreement between the New England Gas Company and the Rhode Island Division of Public Utilities and Carriers (the Division). The settlement agreement resulted in a $3.9 million decrease in base revenues for the New England Gas Company, a unified rate structure (“One State; One Rate”) and an integration /merger savings mechanism. The settlement agreement also allows New England Gas Company to retain $2 million of merger savings and to share incremental earnings with customers when the return on equity exceeds 11.25 percent. Included in the settlement agreement was a conversion to therm billing and the approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows New England Gas Company to continue its low income assistance and weatherization programs and to

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recover environmental response costs over a ten year period, establishes a new weather normalization clause and allows for the sharing of non-firm margins (which is margin earned from interruptible customers with the ability to switch to alternative fuels). The weather normalization clause is designed to mitigate the impact of weather volatility on customer billings, which assists customers in paying bills and stabilize the revenue stream. New England Gas Company defers the margin impact of weather that is greater than two percent colder-than-normal and will recover the margin impact of weather that is greater than two percent warmer-than-normal. The non-firm margin incentive mechanism allows New England Gas Company to retain 25 percent of all non-firm margins earned in excess of $1.6 million. In August 2006, National Grid completed the acquisition of the Rhode Island gas assets of New England Gas Company. Pursuant to the Division order approving the acquisition, National Grid agreed to honour the provisions of the former New England Gas Company rate settlement and committed to file a new rate plan within one year of the acquisition date.

Granite State Electric Company
In May 2007, Granite State entered into a settlement agreement with the staff of the New Hampshire Public Utility Commission and the New Hampshire Office of Consumer Advocate related to issues surrounding the merger of National Grid USA and KeySpan Corporation (the 2007 Settlement). Among other things, the 2007 Settlement provides for a $2.2 million reduction in the Company’s base distribution rates in two steps, the first $1.1 million reduction effective 30 days from the NHPUC approval of the merger and the second $1.1 million reduction effective January 1, 2008. The 2007 Settlement also contains a distribution rate plan spanning 10 years effective January 1, 2008 (Rate Plan). In the first five years of the Rate Plan distribution rates are frozen except for rate adjustments in the event of certain uncontrollable exogenous events and moderate annual rate adjustments related to specific Reliability Enhancement and Vegetation Management Plans (REP/VMP). The Rate Plan also includes an earnings sharing mechanism based on an imputed capital structure of 50 percent debt and 50 percent equity and a ROE sharing threshold of 11 percent, equal to an allowed ROE of 9.67 percent plus an allowance for merger synergy savings of 1.33 percent. Earnings above 11 percent ROE are shared equally between customers and the Company. The Rate Plan also establishes a storm contingency fund and customer service commitments by the Company. The 2007 Settlement is subject to the approval of the NHPUC and contingent on the closing of the merger. However, the $2.2 million distribution rate reduction, REP/VMP, storm contingency fund and customer service commitments are subject only to NHPUC approval of the merger and are not contingent on the closing of the Merger.

NOTE C – COMMITMENTS AND CONTINGENCIES

Environmental issues
The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like most other industrial companies, the Company’s transmission and distribution companies use or generate a broad range of hazardous materials. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

Federal and state environmental regulators, as well as private parties, have alleged that the Company’s transmission and distribution companies are potentially responsible parties under Superfund laws for the remediation of over 180 contaminated sites in New England and New York. The Company’s greatest potential Superfund liabilities relate to manufactured gas plant, or MGP, facilities formerly owned or operated by the Company’s subsidiaries or their predecessors. MGP by-products included fuel oils, hydrocarbons, coal tar, purifier waste and other waste products that may pose a risk to human health and the environment. The Company is investigating or remediating these sites, or both, as appropriate.

Management believes that ongoing operations and the Company’s response to the impact of the Company’s historic operations are in substantial compliance with environmental laws, and that the obligations imposed are not likely to have a material adverse impact on the Company’s financial

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condition or results of operations because the Company recovers a majority of these costs under the Company’s rate plans. The Company is pursuing claims against insurance carriers and potentially responsible parties to recover investigation and remediation costs, but management cannot predict the success of such claims. To the extent that prudently incurred costs cannot be recovered through insurance or otherwise, these are recoverable under applicable rate plans. As of March 31, 2007 and 2006, the Company has recorded an obligation of $583 million and $569 million, respectively, along with an offsetting regulatory asset, on its balance sheet. The potential high end of the range at March 31, 2007 is presently estimated at approximately $703 million.

Decommissioning Nuclear Units
NEP has minority interests in three nuclear generating companies: Yankee Atomic Electric Company (Yankee Atomic), Connecticut Yankee Atomic Power Company (Connecticut Yankee), and Maine Yankee Atomic Power Company (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 three units are as follows:

Future

Estimated

NEP’s Equity Investment as of

Billings to

Nuclear Unit

March 31, 2007

Date Retired

NEP

% Ownership

$ (millions)

Yankee Atomic

34.5

0.4

February 1992

Connecticut Yankee

19.5

2.7

December 1996

Maine Yankee

24.0

2.9

August 1997

With respect to each of the units, NEP recorded a liability and a regulatory asset ($117.4 million long-term and $28.5 million current) reflecting the estimated future decommissioning billings from the Yankees. 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 Yankees collect the approved costs from their purchasers, including the Company. NEP’s share of the decommissioning costs is accounted for in “Electricity purchased” on the income statement. Under settlement agreements, NEP is permitted to recover prudently incurred decommissioning costs through CTCs.

The Yankees are periodically required to file rate cases, presenting the Yankees’ estimated future decommissioning costs for FERC approval. Yankee Atomic and Maine Yankee are currently collecting decommissioning and other costs under FERC Orders issued in their respective rate cases. Connecticut Yankee is also collecting costs, subject to refund under a rate case now pending at the FERC, as described below.

Future estimated billings from the Yankees are based on decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission (NRC), dismantling the units, security, liability and property insurance and other costs. They also include costs for interim spent fuel storage facilities, which the Yankees have constructed during litigation they brought to enforce the U.S. Department of Energy’s (DOE) obligation to remove the fuel as required by the Nuclear Waste Policy Act of 1982. Following a trial at the U.S. Court of Federal Claims to determine the level of damages, on October 6, 2006, the Court awarded the three companies approximately $143 million for spent fuel storage costs that had been incurred through 2001 and 2002. The three companies had requested $176 million. On December 4, 2006, the DOE filed a notice of appeal. The Yankees have selected an appeals counsel and will begin the appeals process. If the order is upheld, the damages received by the Yankees, net of litigation expenses and taxes, will be applied to

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reduce the decommissioning and other costs collected from their purchasers. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially.

Connecticut Yankee rate filing, prudence challenge and other proceedings
On July 1, 2004, Connecticut Yankee asked FERC for a rate increase to reflect increased costs for decommissioning, pensions and other employment benefits, increased security and insurance costs and other expenses. In aggregate, the increase amounts to approximately $396 million through 2010, NEP’s share of which is included in the future estimated billings shown in the table above. The rate case also reflects the impact of the termination of a fixed price contract with Bechtel Power Corporation to perform decommissioning operations and projects a substantial increase in costs over and delay in completion compared with those previously projected.

The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel (together, the Department) intervened at the FERC requesting that the FERC reject Connecticut Yankee’s rate filing, or in the alternative, disallow a portion of the requested rate increase on the ground that $205 million to $235 million of these costs were imprudently incurred. Bechtel and three New England states have also intervened, asserting that these costs are imprudent and should be disallowed. FERC authorized Connecticut Yankee to begin charging the proposed new rates effective February 1, 2005, subject to refund. On November 22, 2005, the FERC ALJ found that Connecticut Yankee was prudent in its administration of the decommissioning contract, its termination of Bechtel and its ongoing decommissioning of the plant. The parties have filed exceptions with the FERC.

Prior to Connecticut Yankee’s filing, the Department petitioned the FERC to determine that Connecticut Yankee’s purchasers, including NEP, were obliged to pay for all of Connecticut Yankee’s decommissioning costs, whether or not prudent, and could not pass on any imprudent costs to their retail customers. The FERC denied the petition on August 30, 2005, on the ground that it has no jurisdiction over retail rates. The Department and Bechtel requested clarification and rehearing. FERC denied their requests on October 30, 2005. The Department appealed FERC’s determination in the federal court.

Connecticut Yankee and Bechtel litigated the termination of the decommissioning contract in Connecticut state court, with each party seeking substantial damages. On March 21, 2006, the parties agreed to settle the case for a payment by Bechtel to Connecticut Yankee of $15 million, and Bechtel withdrew its intervention in Connecticut Yankee’s rate filing.

In July 2006, Connecticut Yankee and the Department reached a settlement in principle to the rate case, which FERC approved on November 16, 2006. The settlement provides for the resolution of all outstanding issues and objections between the parties, including the matters described above. The settlement extends the decommissioning collection period from 2010 to 2015 at a lower annual collection rate. The settlement also includes a provision from the 2000 FERC settlement which stipulated that if decommissioning expenses exceeded a spending cap, Connecticut Yankee (through the sponsors’ equity) was to absorb the overage up to a maximum of $10 million through reduced decommissioning collections. Decommissioning costs exceeded the cap. Under the terms of the settlement, Connecticut Yankee’s liability is reduced to $5 million if the project receives its NRC license termination before the end of 2007. If the license termination is delayed, the amount increases over time to the $10 million maximum. The settlement provides that Connecticut Yankee may resume payment of dividends to return equity to sponsors. After January 1, 2008, Connecticut Yankee will not earn a return on more than $10 million in equity.

Nuclear Contingencies
As of March 31, 2007 and 2006, the Company has a liability of $158 million and $151 million, respectively, in other non-current liabilities for the disposal of nuclear fuel irradiated prior to 1983 at Niagara Mohawk’s former nuclear facilities. In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the DOE for the disposal of nuclear fuel

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irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation Energy Group Inc., which purchased the Niagara Mohawk’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.

Long-Term Contracts for the Purchase of Electric Power
The Company’s subsidiaries have several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2007, are as follows:


Fiscal Year Ended March 31,	Amount
	(In millions of dollars)

2008	$	2,061
2009		1,274
2010		966
2011		397
2012		359
Thereafter		2,361

Total	$	7,418

If the Company’s subsidiaries need any additional energy to meet load requirements, they can purchase the electricity from other independent power producers (IPPs) other utilities, other energy merchants or the open market through the New York Independent System Operator (NYISO) or the New England Independent System Operator (ISO – NE) at market prices.

Gas Supply, Storage and Pipeline Commitments
In connection with its regulated gas business, Niagara Mohawk and Narragansett have long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.

The table below sets forth the Company’s estimated commitments at March 31, 2007, for the next five years, and thereafter.


Fiscal Year Ended March 31,	Amount
	(In millions of dollars)

2008	$	513
2009		136
2010		85
2011		80
2012		29
Thereafter		45

Total	$	888

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With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration to the minimum take provisions. Commodity prices are based on New York Mercantile Exchange (NYMEX) quotes and reservation charges, when applicable. Storage and pipeline capacity commitment amounts are based upon volumes specified in the contracts, and represent demand charges priced at currently filed tariffs. At March 31, 2007, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is March 2009. The majority of the gas storage and transportation commitments have varying expiration dates between 2010 and 2012 with the latest being October 2022.

Plant Expenditures

The Company’s utility plant expenditures are estimated to be approximately $749 million in fiscal 2008. At March 31, 2007, substantial commitments had been made relative to future planned expenditures. Generally construction expenditure levels are consistent from year to year, however, the Company is currently in the second year of a five-year Reliability Enhancement Program, to improve performance and reliability, which will result in increased capital expenditures.

Legal Matters by Entity

Niagara Mohawk
Station Service Cases:A number of generators complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they were permitted to bypass its retail charges. The FERC issued two orders on complaints filed by the Company’s station service customers in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. Subsequent to December 2003, FERC issued a third order that involved affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the orders of the PSC on station service rates. The effect of these orders is to permit these generators to bypass the Company’s state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. Under those state-approved tariffs, the Company was owed in aggregate approximately $62 million as of December 31, 2006. The Company appealed the FERC orders to the U.S. Court of Appeals for the District of Columbia Circuit, and the matters were consolidated for appeal. On June 23, 2006, the Court issued a decision upholding the FERC’s orders, and on October 23, 2006, the Court denied the Company’s request for rehearing. On January 22, 2007, the Company filed a joint petition for certiorari to the United States Supreme Court requesting the Court to review and reverse the decision of the Court of Appeals. The Supreme Court denied certiorari and thus the FERC orders have become final.

Under those orders, FERC allows generators to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO if the amount of power produced by a generator over a 30-day period exceeds the amount of power taken over the power grid. As discussed under the deferral audit section of Note B, the Company is not recovering the lost revenues associated with the FERC orders through its deferral account and recorded a charge to expense of $68 million in the fourth quarter of fiscal year 2007 related to this matter.

New England Power
Town of Norwood Dispute:From 1983 until 1998, NEP was the wholesale power supplier for Norwood, Massachusetts. 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 monthly CTC of $0.6 million, plus interest on unpaid balances at 18 percent per year. As of March 31, 2007, the charges assessed Norwood but not paid amount to $68 million. NEP and Norwood are engaged in litigation at the FERC and in state court, as follows.

FERC 206 Proceeding:In December 2002, Norwood challenged the CTC rate with the FERC under Section 206 of the Federal Power Act, which permits the FERC to make prospective adjustments to filed rates. On June 9, 2004, the FERC ALJ issued an initial decision recommending that FERC revise the

F-24

CTC formula to reduce the CTC amount that was previously calculated under the formula which the FERC accepted and approved in 1998. NEP challenged this initial decision, arguing that no reduction is appropriate. Norwood and the FERC staff challenged the initial decision, arguing that the reduction is insufficient.

On July 22, 2005, the FERC ruled that NEP correctly calculated the CTC payable by Norwood at approximately $0.6 million per month from April 1998 through October 2008. FERC also reduced the late payment interest rate applicable to the unpaid CTC from 18 percent to 8 percent. In response to requests for rehearing filed by both sides, on February 22, 2006, FERC reaffirmed the validity of the CTC, and ruled that the late payment interest rate should be a simple interest rate of 18 percent. The FERC calculated the amount owed by Norwood for past and future CTC payments to be $89 million through December 2005. On March 14, 2006, Norwood asked FERC to reconsider the interest portion of its decision, and on March 17, moved to stay the effectiveness of the decision pending FERC’s consideration of its rehearing request. On June 30, FERC denied Norwood’s motion for rehearing and its motion for a stay.

On April 18, 2006, Norwood petitioned the US Court of Appeals for the First Circuit to review the FERC’s orders. On July 14, 2006, Norwood petitioned the First Circuit for a stay. On August 21, 2006, the Court entered a limited stay, holding that Norwood need not pay its past debt until after the Court rules on the merits but that Norwood must pay monthly CTC amounts when due in the meantime.

On February 2, 2007, the First Circuit affirmed the FERC’s denial of Norwood’s challenge to the principal CTC amount, affirmed the FERC’s order insofar as it required late payment interest charges at least at the prime rate, and remanded to FERC only as to whether more than the prime rate is properly due. The First Circuit ruled further that issuance of the Court’s mandate would lift its stay order of August 21, 2006. The mandate was issued on March 26, 2007. On May 3, 2007, Norwood filed a petition for certiorari with the US Supreme Court seeking review of the First Circuit’s February, 2007 Order. NEP’s response to that petition is currently due to be filed in July 2007.

On May 17, 2007, the FERC ruled that the interest rate should be at prime, but did not address the effective date of the reduced late payment interest rate. On June 14, 2007, NEP filed a motion for clarification and alternative request for rehearing, asking FERC to clarify this issue, arguing that the rate should apply only to bills rendered after June 30, 2006. NEP also made a compliance filing indicating that through May 2007, Norwood owes NEP approximately $68.4 million. Norwood filed a protest on June 29, 2007.

State Collection Action:NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC. 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. Following unsuccessful appeals by Norwood, the Superior Court entered judgment for NEP on June 9, 2004 in the amount of approximately $43 million, based on amounts owed through January 31, 2001. Norwood appealed again to the Massachusetts Appeals Court, arguing that the CTC did not bind Norwood until the FERC’s July 22, 2005 order confirmed the calculation for Norwood that NEP made in 1998, and that the Appeals Court should, in any event, await final resolution of the CTC by FERC and any subsequent judicial review. On May 17, 2006, the Appeals Court denied Norwood’s appeal. The court remanded the case back to the trial court to increase its January 2001 judgment consistent with the amount in FERC’s February 2006 order. Norwood filed an appeal with the Massachusetts Supreme Judicial Court, and on June 28, 2006, the appeal was denied. On July 24, 2006, NEP moved the Superior Court to bring the judgment current as of the date that it is entered. The motion was continued in light of the FERC’s August 21 grant of a limited stay, which was lifted when the First Circuit’s mandate was issued, as discussed above. Through March 31, 2007, Norwood has paid NEP approximately $39 million, including its last payment of approximately $15 million made in March 2007. On March 14, 2007 the Norwood Town Meeting voted to bond the remainder of its obligations to NEP, and has informed the Company that the process could take a year to complete.

F-25

NOTE D – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table details the components of accumulated other comprehensive income (loss) for the fiscal years ended March 31, 2007 and 2006:


	Unrealized									Total
	Gains and									Accumulated
	(Losses) on			Pension						Other
	Available-for-			Liability			Cash Flow			Comprehensive
	Sale Securities			Adjustment			Hedges			Income (Loss)
	(In thousands)

March 31, 2005	$	3,868		$	(188,841	)	$	12,812		$	(172,161	)

Other comprehensive income (loss), net of taxes Unrealized gains on securities		6,217									6,217
Change in additional minimum pension liability					182,489						182,489
Hedging activity								4,009			4,009
Reclassification adjustment for loss included in net income		(3,236	)					(21,574	)		(24,810	)

March 31, 2006	$	6,849		$	(6,352	)	$	(4,753	)	$	(4,256	)

Other comprehensive income (loss), net of taxes Unrealized gains on securities		6,003									6,003
Change in additional minimum pension liability					(6,278	)					(6,278	)
Adjustment for the adoption of SFAS No. 158					(398,145	)					(398,145	)
Hedging activity								(17,526	)		(17,526	)
Reclassification adjustment for gain (loss) included in net income		(3,570	)					22,034			18,464

March 31, 2007	$	9,282		$	(410,775	)	$	(245	)	$	(401,738	)

NOTE E – DERIVATIVE CONTRACTS AND HEDGING ACTIVITIES

Niagara Mohawk

In the normal course of business, the Company is a party to derivative financial instruments (derivatives) that are principally used to manage commodity prices associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall Financial Risk Management Policy. At the core of the policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for according to SFAS No. 133 as amended, which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. Changes in the fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased electricity or gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased electricity or gas expense in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.

Niagara Mohawk has eight indexed swap contracts, expiring in fiscal year 2009 (June 2008), which resulted from the Master Restructuring Agreement. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2007 and 2006, the Company had recorded liabilities at net present value of $268 million and $537 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over

F-26

the remaining term of the swaps as nominal energy quantities are settled and they are adjusted as periodic reassessments are made of energy price forecasts.

At March 31, 2007, Niagara Mohawk projects that it will make the following payments in connection with its swap contracts for the fiscal years 2008 through 2009 and thereafter, subject to changes in market prices and indexing provisions:


	Projected
Year Ended March 31,	Payment
	(In thousands
	of dollars)

2008	$	221,540
2009		46,500
Thereafter		—

	$	268,040

Niagara Mohawk uses NYMEX gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS No. 133. Cash flow hedges that qualify under SFAS No. 133 are as follows: NYMEX gas futures for the purchases of natural gas and NYMEX electric swap contracts hedging the purchases of electricity.

The following table represents the open positions at March 31, 2007 and 2006 and the results on operations of these instruments for the year ended March 31, 2007 and 2006.


	Balances as of March 31, 2006
									Accumulated			Gain Reclass
						Accumulated			Deferred			to
				Regulatory		OCI^**, net of			Income Tax			Commodity
Derivative Instrument	Asset*			Deferral		tax			on OCI^**			Costs
	(In thousands of dollars)

*Qualified for Hedge Accounting*
NYMEX futures - gas supply	$	(5,358.8	)	$	—	$	4,943.0		$	(3,296.0	)	$	35,956.6
NYMEX electric swaps - electric supply	$	317.5		$	—	$	(190.5	)	$	127.0		$	3,260.2
*Non-qualified for Hedge Accounting*
NYMEX futures - IPP swaps/non-MRA IPP	$	(27,195.9	)	$	31,718.1	$	—		$			$	59,464.9


Notes:

*		Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.

**		Other comprehensive income (OCI)


	Balances as of March 31, 2007
							Accumulated			Loss Reclass
					Accumulated		Deferred			to
			Regulatory		OCI, net of**		Income Tax			Commodity
Derivative Instrument	Asset*		Deferral		tax		on OCI**			Costs
	(In thousands of dollars)

*Qualified for Hedge Accounting*
NYMEX futures - gas supply	$	2,533.7	$	—	$	214.9	$	(143.3	)	$	(36,722.9	)
NYMEX electric swaps - electric supply	$	783.9	$	—	$	30.1	$	(20.1	)	$	(4,644.7	)

F-27

Balances as of March 31, 2007

Accumulated

Loss Reclass

Accumulated

Deferred

Regulatory

OCI**, net of

Income Tax

Commodity

Derivative Instrument

Asset*

Deferral

tax

on OCI**

Costs

(In thousands of dollars)

Non-qualified for Hedge Accounting

NYMEX futures – IPP swaps/non-MRA IPP

4,627.0

2,272.1

—

(101,132.4

)


Notes:

*		Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.

**		Other comprehensive income (OCI)

The gains and losses on the derivatives that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2007, the realized net loss of $37 million from hedging instruments, as shown in the table above, was recorded to gas purchases and was offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2006, a realized net gain of $36 million was recorded to gas purchases and was offset by a corresponding decrease in the cost of a comparable amount of gas.

The actual amounts to be recorded in purchased energy expense are dependent on future changes in the contract values. The majority of these deferred amounts will be reclassified to expense within the next twelve months. A nominal amount of the hedging instruments extend into April 2008. There were no gains or losses recorded during the fiscal year ended March 31, 2007 from the discontinuance of gas futures or electricity swap cash flow hedges.

The deferred gain on NYMEX electric swap contracts to hedge electricity purchases was $0.8 million and $0.3 million for the fiscal years ended March 31, 2007 and 2006, respectively.

NEP

As a result of a USGen bankruptcy settlement agreement (Bankruptcy Settlement), the Company resumed the performance and payment obligations under power supply contracts that had been transferred to USGen when the Company divested its generating business. As of March 31, 2007 and 2006, the Company had recorded a derivative liability of approximately $251 million and $294 million, respectively, for the above-market portion of the Contracts with an equal offset to a corresponding regulatory asset. The performance and payment obligations will not affect the results of operations, as the Company will recover the above-market cost of the Contracts from customers through the CTC. In accordance with the Bankruptcy Settlement, the Company received proceeds of approximately $196 million in June 2005 from USGen. That amount relates in part to the Contracts and the Company is crediting that amount to customers through a reduction in rates through December 31, 2009.

NOTE F – EMPLOYEE BENEFITS

Summary

The Company and its subsidiaries have non-contributory defined benefit pension plans and postretirement benefit plans other than pensions (the Plans) covering substantially all employees. With the exception of New England-based union-represented employees, employees hired on or after July 15, 2002 participate under a non-contributory defined benefit cash balance pension plan design. Under that design, pay-based credits are applied based on service time, and interest credits are applied based on

F-28

an average annual 30-year Treasury bond yield. Non-union employees hired by New England-based companies prior to July 15, 2002 and New England-based union employees generally participate in the historic final average pay pension plan designs. In addition, a large number of employees hired by Niagara Mohawk prior to July 1998 are cash balance design participants who receive a larger benefit if so yielded under pre-cash balance conversion final average pay formula provisions. Employees hired by Niagara Mohawk following the August 1998 cash balance design conversion participate under cash balance design provisions only.

Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.

The Company and its subsidiaries provide postretirement benefits other than pensions (PBOPs). PBOPs include health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

Funding Policy
Following the inception of the Pension Protection Act of 2006 (the PPA), the Company’s funding policy is to contribute amounts sufficient to reach 100 percent of the Funding Target under the PPA by 2010. In New York, the funding policy is determined largely by the Company’s settlement agreements with the PSC and the amounts recovered in rates. However, the contribution in New England and New York for any one year will not be less than the minimum amount required under the PPA.

Plan Assets
The target asset allocations for the benefit plans at March 31 are:


	Pension Benefits						Non-Union PROP						Union PROP
	2007			2006			2007			2006			2007			2006
U.S. equities		43	%		42	%		33	%		33	%		50	%		51	%
Global equities (including U.S.)		6	%		6	%		0	%		0	%		0	%		0	%
Non-U.S. equities		12	%		12	%		17	%		17	%		23	%		23	%
Fixed income		36	%		35	%		50	%		50	%		27	%		26	%
Private equity and other		3	%		5	%		0	%		0	%		0	%		0	%

		100	%		100	%		100	%		100	%		100	%		100	%

The percentage of the fair value of total plan assets at March 31 is:


	Pension Benefits						Non-Union PROP						Union PROP
	2007			2006			2007			2006			2007			2006
U.S. equities		45	%		45	%		34	%		33	%		50	%		51	%
Global equities (including U.S.)		6	%		8	%		0	%		0	%		0	%		0	%
Non-U.S. equities		12	%		13	%		18	%		18	%		24	%		24	%
Fixed income		34	%		32	%		48	%		49	%		26	%		25	%
Private equity and other		3	%		2	%		0	%		0	%		0	%		0	%

		100	%		100	%		100	%		100	%		100	%		100	%

The Company manages benefit plan investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study

F-29

which analyzes the Plans’ liabilities and funded status and results in the determination of the allocation of assets across equity and fixed income. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity with the objective of enhancing long-term returns while improving portfolio diversification. For the PBOP plan, since the earnings on a portion of the assets are taxable, those investments are managed to maximize after tax returns consistent with the broad asset class parameters established by the asset allocation study. Investment risk and return is reviewed by the investment committee on a quarterly basis.

The estimated rate of return for various passive asset classes is based on both analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of the long-term assumption. A small premium is added for active management and rebalancing of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the plans’ target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.

Assumptions Used for Benefits Accounting
The following weighted average assumptions were used to determine the pension and PBOP benefit obligations and net periodic benefit costs for the fiscal years ending March 31.


	Pension Benefits
	Benefit obligation						Net periodic benefit
	2007			2006			2007			2006
Discount rate		6.00	%		6.00	%		6.00	%		5.75	%
Rate of compensation increase
- New England		4.30	%		4.30	%		4.30	%		4.30	%
- New York		3.90	%		3.90	%		3.90	%		3.90	%
Expected long-term rate of return on assets		8.00	%		8.00	%		8.00	%		8.25	%


	PBOP
	Benefit obligation						Net periodic benefit
	2007			2006			2007			2006
Discount rate		6.00	%		6.00	%		6.00	%		5.75	%
Expected long-term rate of return on assets		7.80	%		7.80	%		7.80	%		8.05	%
Health care cost trend rate Initial		n/a			n/a			n/a			10.00	%
Pre 65*		9.50	%		10.00	%		10.00	%		n/a
Post 65*		10.50	%		11.00	%		11.00	%		n/a
Ultimate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate rate reached		n/a			n/a			n/a			2010
Pre 65*		2012			2011			2011			n/a

F-30

PBOP

Benefit obligation

Net periodic benefit

2007

2006

2007

2006

Post 65*

2013

2012

n/a


Note:

*		At March 31, 2006, the healthcare cost trend assumption was updated to include rates for the pre 65 and post 65 groups.

The expected contributions to the Company’s pension and PBOP plans during fiscal year 2008 are expected to be $371 million and $54 million, respectively.

Adoption of SFAS No. 158
The Company adopted SFAS No. 158 on March 31, 2007. This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or other postretirement plan to recognize an asset or liability on its balance sheet for the over funded or under funded status of the plan as defined by SFAS No. 158. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For PBOPs, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation as of the year end. The offset of this asset or liability is a charge to AOCI or a regulatory asset. The following table illustrates the effect on individual financial statement line items of applying this standard to the Company’s plans, relating to pension and PBOP:


	Before						After
	application of						application of
March 31, 2007	SFAS No. 158			Adjustment			SFAS No. 158
	(In thousands)
Intangible asset	$	33,431		$	(33,431	)	$	—
Regulatory asset		39,430			460,848			500,278
Deferred tax asset		166,126			340,325			506,451
Current liability		—			(9,047	)		(9,047	)
Non-current liability		(407,842	)		(1,156,840	)		(1,564,682	)
AOCI, net of tax		12,630			398,145			410,775

AOCI, pre tax		19,627			660,292			679,919

Pension Benefits
The Company’s net periodic benefit cost for the fiscal years ended March 31, 2007 and 2006 included the following components:


	2007			2006
	(In thousands)
Service cost	$	55,351		$	55,412
Interest cost		163,067			155,779
Expected return on plan assets		(174,537	)		(161,944	)
Amortization of unrecognized prior service cost		4,913			4,913

F-31


	2007		2006
	(In thousands)
Amortization of unrecognized loss		58,341		64,067

Net periodic benefit costs before settlements and curtailments		107,135		118,227
Settlement and curtailment loss		25,555		—

Net periodic benefit cost	$	132,690	$	118,227

The following table provides the changes in the pension plans’ accumulated benefit obligation, funded status and the amounts recognized in the balance sheet at March 31:


	2007			2006
	(In thousands)
Accumulated benefit obligation	$	(2,603,473	)	$	(2,470,161	)
Reconciliation of benefit obligation:
Benefit obligation at beginning of period	$	(2,748,465	)	$	(2,808,396	)
Service cost		(55,351	)		(55,412	)
Interest cost		(163,067	)		(155,779	)
Actuarial gain (loss)		(87,045	)		66,137
Benefits paid		156,703			204,985
Settlements		165,928			—
Acquisition of Rhode Island gas pension obligation*		(165,906	)		—

Benefit obligation at end of period		(2,897,203	)		(2,748,465	)

Fair value of plan assets at beginning of period		2,147,611			1,960,624
Actual return on plan assets		220,848			257,056
Company contributions		295,354			134,916
Benefits paid		(156,703	)		(204,985	)
Settlements		(165,928	)		—
Acquisition of Rhode Island gas pension assets*		153,603			—

Fair value of plan assets at end of period		2,494,785			2,147,611

Funded status		(402,418	)		(600,854	)

Unrecognized actuarial loss		—			629,266
Unrecognized prior service cost		—			48,847

Net amount (accrued) prepaid cost	$	(402,418	)	$	77,259


Note:

*		On August 24, 2006, the Company acquired the Rhode Island gas distribution assets of New England Gas Company from Southern Union Company. In connection with this acquisition, four small pension plans merged with the existing pension plan, resulting in an increase in the assets and benefit obligation of the plan in the amounts of $154 million and $166 million, respectively.

F-32


	2007			2006
	(In thousands)
Amounts recognized on the balance sheet consist of:
Intangible asset	$	—		$	36,885
Prepaid benefit cost		—			360,183
Regulatory assets		214,788			79,923
Current pension liability		(9,047	)		—
Non-current pension liability		(393,371	)		(410,275	)
Accumulated other comprehensive income, before taxes		415,250			10,543

Net amount recognized	$	227,620		$	77,259


	2007
	(In
	thousands)
Amounts recognized in regulatory assets and AOCI consist of:
Net actuarial loss	$	586,105
Prior service cost		43,933

Net amount recognized	$	630,038

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI and regulatory assets into net periodic benefit cost during fiscal year 2008 are $58 million and $4 million, respectively.

The following pension benefit payments, which reflect expected future services, as appropriate, are expected to be paid:


	Pension
	Benefits
	(In
	thousands)
2008	$	203,047
2009	$	202,615
2010	$	205,645
2011	$	208,947
2012	$	214,086
2013-2017	$	1,052,184

Additional Minimum Liability (AML)
The Company recognized AML, as prescribed under SFAS No. 87, “Employers’ Accounting for Pensions,” prior to recording the entries to recognize the funded status of the pension plans under SFAS No. 158. The Company recognized an AML of $92 million which was subsequently eliminated under SFAS No. 158. At March 31, 2006, the Company recorded an AML of approximately $127 million. While the offset to this entry would normally be a charge to other comprehensive income, certain Company

F-33

subsidiaries, had recorded regulatory assets in the amount of $80 million at March 31, 2006 because they fully recover all pension costs.

Defined Contribution Plan

The Company also has several defined contribution pension plans primarily (section 401(k) employee savings fund plans) that cover substantially all employees. Employer matching contributions of approximately $19 million and $11 million were expensed in fiscal year 2007 and 2006, respectively.

Settlement Losses

The Company’s pension plans have losses that have yet to be recognized in the income statement as a result of changes in the value of the projected benefit obligation and the plan assets due to expenses different from that assumed and from changes in actuarial assumptions. Under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, a company must recognize a portion of its loss immediately when payouts from a plan exceed a certain amount. Niagara Mohawk recognized a settlement loss of approximately $26 million during the fiscal year ended March 31, 2007 due to plan payouts that exceeded the threshold as prescribed in SFAS No. 88. During fiscal year 2007, Niagara Mohawk and the PSC staff reached an agreement to recover approximately 50% of this pension settlement loss.

Postretirement Benefits Other than Pensions

The Company’s total net periodic benefit cost of PBOPs for the fiscal years ended March 31, 2007 and 2006 included the following components:


	2007			2006
	(In thousands)
Service cost	$	28,178		$	28,293
Interest cost		121,538			112,407
Expected return on plan assets		(76,743	)		(73,782	)
Amortization of prior service cost		13,331			13,330
Amortization of net loss		43,896			45,648

Net periodic benefit cost	$	130,200		$	125,896

The following table provides a reconciliation of the PBOP plans’ funded status and the amounts recognized in the balance sheet at March 31:


	2007			2006
	(In thousands)
Benefit obligation at beginning of period	$	(2,124,767	)	$	(2,019,009	)
Service cost		(28,178	)		(28,293	)
Interest cost		(121,538	)		(112,407	)
Actuarial loss		(6,852	)		(71,103	)
Benefits paid		118,341			106,045
Medicare subsidy		(5,392	)		—
Acquisition of Rhode Island gas PBOP obligation*		(47,640	)		—

Benefit obligation at end of period		(2,216,026	)		(2,124,767	)

Fair value of plan assets at beginning of period		988,189			922,173

F-34


	2007			2006
	(In thousands)
Actual return on plan assets		100,881			113,920
Company contributions		53,230			53,700
Benefits paid		(110,606	)		(101,604	)
Acquisition of Rhode Island gas PBOP assets^*		13,021			—

Fair value of plan assets at end of period		1,044,715			988,189

Funded status		(1,171,311	)		(1,136,578	)

Unrecognized actuarial loss		—			583,073
Unrecognized prior service cost		—			119,775

Net amount accrued cost	$	(1,171,311	)	$	(433,730	)


Note:

*		On August 24, 2006, the Company acquired the Rhode Island gas distribution assets of New England Gas Company from Southern Union Company. In connection with this acquisition, the Company’s assets and benefit obligation of the PBOP plan increased by $13 million and $48 million, respectively.


	2007
	(In thousands)
Amounts recognized on the balance sheet consist of:
Regulatory asset	$	285,490
PBOP liability		(1,171,311	)
Accumulated other comprehensive income, before taxes		264,669
Net amount recognized	$	(621,152	)
Amounts recognized in regulatory assets and AOCI consist of:
Net actuarial loss	$	521,892
Prior service cost		106,445
Net amount recognized	$	628,337

The estimated net actuarial loss and prior service cost for the PBOP plans that will be amortized from AOCI and regulatory assets into net periodic benefit cost during fiscal year 2008 are $49 million and $13 million, respectively.

As a result of the Medicare Act of 2003, the Company receives a federal subsidy for sponsoring a retiree healthcare plan that provides a benefit that is actuarially equivalent to Medicare Part D.

The following benefit payments and subsidies under Medicare Part D, which reflect future services, as appropriate, are expected to be:


	Payments		Subsidies
	(In thousands)
2008	$	117,654	$	7,063

F-35


	Payments		Subsidies
	(In thousands)
2009	$	127,008	$	7,676
2010	$	132,042	$	8,268
2011	$	137,022	$	8,708
2012	$	140,849	$	9,015
2013-2017	$	742,438	$	48,356

The assumptions used in health care cost trends have a significant effect on the amounts reported. A one percent change in the assumed rates would have the following effects:


	2007
Increase 1%
Total of service cost plus interest cost	$	28,270
Postretirement benefit obligation	$	333,616
Decrease 1%
Total of service cost plus interest cost	$	(23,241	)
Postretirement benefit obligation	$	(289,647	)

NOTE G – INCOME TAXES

The following is a summary of the components of federal and state income tax and reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory level.

Total income taxes in the consolidated statements of income are as follows:


	For the Year Ended
	March 31,
	2007			2006
	(In thousands)
Income taxes charged to operations	$	187,966		$	319,232
Income taxes credited to “Other deductions”		(3,924	)		(2,032	)

Total income taxes	$	184,042		$	317,200

Total income taxes, as shown above, consist of the following components:


	For the Year Ended
	March 31,
	2007		2006
	(In thousands)
Current income taxes	$	75,463	$	282,320

F-36


	For the Year Ended
	March 31,
	2007			2006
	(In thousands)
Deferred income taxes		114,825			41,619
Investment tax credits, net		(6,246	)		(6,739	)

Total income taxes	$	184,042		$	317,200

Previously recognized investment tax credits (ITC) related to the transmission and distribution facilities of the Company’s regulated subsidiaries are amortized over their estimated productive lives.

Total income taxes, as shown above, consist of federal and state components as follows:


	For the Year Ended
	March 31,
	2007		2006
	(In thousands)
Federal income taxes	$	152,189	$	272,705
State income taxes		31,853		44,495

Total income taxes	$	184,042	$	317,200

With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences.

Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows:


	For the Year ended
	March 31,
	2007			2006
	(In thousands)
Computed tax at statutory rate	$	226,133		$	307,322
Increases (reductions) in tax resulting from:
Amortization of ITC, net		(6,246	)		(6,739	)
State income tax, net of federal income tax benefit		19,334			28,336
Tax return true-ups		(52,888	)		(16,563	)
Rate recovery of deficiency in deferred tax reserves		764			11,159
Book/tax depreciation not normalized		13,536			10,156
Unamortized debt discount not normalized		(33	)		3,298
Cost of removal		(6,861	)		(7,298	)
Medicare act		(12,713	)		(11,385	)
All other differences		3,016			(1,086	)

F-37


	For the Year ended
	March 31,
	2007		2006
	(In thousands)

Total income taxes	$	184,042	$	317,200

The Company applies SFAS No. 109, “Accounting for Income Taxes,” which requires recognition of deferred income taxes using the liability method for temporary differences that are reported in different years for financial reporting and tax purposes. Under the liability method, deferred tax liabilities or assets are computed using the tax rates that will be in effect when temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be immediately recognized in operating results because of rate-making treatment and provisions in the Tax Reform Act of 1986.

The following is the detail of the Company’s accumulated deferred income taxes:


	At March 31,
	2007			2006
	(In thousands)
Deferred tax assets:
Plant related	$	53,193		$	112,757
Alternative minimum tax		381			119,294
Unbilled revenues		21,987			17,070
Liability for environmental costs		224,069			191,307
Voluntary early retirement program		0			42,089
Bad debts		65,687			62,210
Pension and other post-retirement benefits		762,038			248,446
Investment tax credit		9,255			10,560
Other		560,914			414,343

Total deferred tax assets		1,697,524			1,218,076

Deferred tax liabilities:
Plant related		(1,481,242	)		(1,429,641	)
Equity AFUDC		(65,337	)		(63,668	)
Deferred environmental restoration costs		(185,897	)		(186,842	)
Merger rate plan stranded costs		(758,235	)		(795,184	)
Merger fair value pension and OPEB adjustment		(90,768	)		(109,478	)
Bond redemption and debt discount		(25,215	)		(30,009	)
Pension and other post-retirement benefits		(266,144	)		(61,784	)
Other		(637,358	)		(569,349	)

Total deferred tax liabilities		(3,510,196	)		(3,245,955	)

Net accumulated deferred income tax liability		(1,812,672	)		(2,027,879	)
Current portion (net deferred tax asset)		176,208			195,476

Net accumulated deferred income tax liability (non-current)	$	(1,988,880	)	$	(2,223,355	)

F-38

The Company and other related subsidiaries participate with National Grid Holdings, Inc. (NGHI), a wholly owned subsidiary of National Grid plc, in filing consolidated US federal income tax returns. The Company’s tax provisions and tax accounts are calculated on a separate company basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service (IRS) and the NGHI consolidated filing group through March 31, 2002. The IRS is currently reviewing the March 31, 2003 and March 31, 2004 tax returns of the NGHI consolidated filing group. The IRS has issued a preliminary notice of deficiency disallowing certain tax deductions taken in these consolidated US federal income tax returns. These adjustments are being appealed. The Company has joint and several liability for any potential assessments against the consolidated group. Management believes that the positions taken by the Company and its related subsidiaries and parent company are appropriate and the resolution of the tax matters will not have a material effect on the Company’s financial position, results of operations or cash flows.

There were no valuation allowances for deferred tax assets deemed necessary at March 31, 2007 or 2006.

NOTE H – LONG-TERM DEBT

Long-term debt consists of the following:

Narragansett Electric


			At March 31
Series	Rate %	Maturity	2007			2006
			(In thousands)
First Mortgage Bonds:
U(93-3)	6.650	June 30, 2008	$	5,000		$	5,000
M (Formerly Providence Gas)	10.250	July 31, 2008		544			—
S (Formerly Providence Gas)	6.820	April 1, 2018		14,464			—
N (Formerly Providence Gas)	9.630	May 30, 2020		10,000			—
O (Formerly Providence Gas)	8.460	September 30, 2022		12,500			—
P (Formerly Providence Gas)	8.090	September 30, 2022		10,000			—
R (Formerly Providence Gas)	7.500	December 15, 2025		14,250			—
W(97-l)	7.390	September 30, 2027		3,000			3,000
W(97-2)	7.390	October 1, 2027		7,000			7,000
Unamortized discounts				(212	)		(237	)

Total long-term debt			$	76,546		$	14,763

Long-term debt due within one year				11,648			—

Total long-term debt, excluding current portion			$	64,898		$	14,763

Substantially all of the properties and franchises of the Company are subject to the lien of mortgage indentures under which the first mortgage bonds have been issued.

In connection with the acquisition of the Rhode Island gas assets of Southern Union Gas and assumption of $77 million of first mortgage bonds, the Company has deposited $17 million with its first mortgage trustee to provide for the redemption of the Company’s pre-acquisition first mortgage bonds. The principal amount is $15 million and the additional $2 million would satisfy all interest and premium due on

F-39

the bonds through maturity or first call date. This assumed debt may not exceed 60 percent of total capitalization or the rates on the debt will increase by 0.20 percent, and the debt may not exceed 70 percent of total capitalization or the bondholders may declare bonds due and payable. At March 31, 2007, total debt was approximately 11 percent of total capitalization. Narragansett will continue to comply with all requirements under the first mortgage indenture until all bonds have been redeemed or mature.

Massachusetts Electric


			At March 31
Series	Rate %	Maturity	2007			2006
			(In thousands)
First Mortgage Bonds:
V(96-l)	6.780	November 20, 2006	$	—		$	20,000
T(93-7)	6.660	June 23, 2008		5,000			5,000
T(93-8)	6.660	June 30, 2008		5,000			5,000
T(93-10)	6.110	September 8, 2008		10,000			10,000
T(93-ll)	6.375	November 17, 2008		10,000			10,000
V(98-3)	5.720	November 24, 2008		25,000			25,000
V(97-l)	7.390	October 1, 2027		15,000			15,000
V(98-l)	6.910	January 12, 2028		20,000			20,000
V(98-2)	6.940	January 12, 2028		5,000			5,000
Pollution Control Revenue Bonds:
2004	Variable	August 1, 2008		20,000			20,000
2004	Variable	August 1, 2014		20,000			20,000
Unamortized discounts				(485	)		(587	)

Total long-term debt				134,515			154,413
Long-term debt due within one year				—			20,000

Total long-term debt, excluding current portion			$	134,515		$	134,413

Substantially all of the properties and franchises of the Company are subject to the lien of mortgage indentures under which the first mortgage bonds have been issued.

Granite State Electric


			At March 31
Series	Rate %	Maturity	2007		2006
			(In thousands)
Note	7.370	November 1, 2023	$	5,000	$	5,000
Note	7.940	July 1, 2025		5,000		5,000
Note	7.300	June 15, 2028		5,000		5,000

Total long-term debt			$	15,000	$	15,000

F-40

debt becomes greater than 70 percent of total capitalization. At March 31, 2007 and 2006, the total long-term debt was 18 percent of total capitalization.

Niagara Mohawk


			At March 31
Series	Rate %	Maturity	2007			2006
			(In thousands)
First Mortgage Bonds:
7 3/4%	7.750	May 15, 2006	$	—		$	275,000
Senior Notes:⁽¹⁾
8 7/8%	8.875	May 15, 2007		200,000			200,000
7 3/4%	7.750	October 1, 2008		600,000			600,000
Tax Exempt:
2013	Variable	October 1, 2013		45,600			45,600
2015	Variable	July 1, 2015		100,000			100,000
2023	Variable	December 1, 2023		69,800			69,800
5.15%⁽²⁾	5.150	November 1, 2025		75,000			75,000
2025	Variable	December 1, 2025		75,000			75,000
2026	Variable	December 1, 2026		50,000			50,000
2027	Variable	March 1, 2027		25,760			25,760
2027	Variable	July 1, 2027		93,200			93,200
2029	Variable	July 1, 2029		115,705			115,705
Notes Payable:⁽¹⁾
NM Holdings Note	3.720	July 31, 2009		350,000			350,000
NM Holdings Note	3.830	June 30, 2010		350,000			350,000
NM Holdings Note	5.800	November 1, 2012		500,000			500,000
Unamortized discounts				(871	)		(1,133	)

Total long-term debt				2,649,194			2,923,932
Long-term debt due within one year				200,000			275,000

Total long-term debt, excluding current portion			$	2,449,194		$	2,648,932


Notes:

(1)		Currently callable with make-whole provisions.

(2)		Fixed rate pollution control revenue bonds first callable November 1, 2008 at 102%.

Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt. Several series of First Mortgage Bonds were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $575 million of such securities bear interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate) which averaged 3.41 percent for the year ended March 31, 2007and 3.20 percent for the year ended March 31, 2006. The bonds are currently in the auction rate mode and are backed by bond insurance. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of

F-41

financing the construction of certain pollution control facilities at the Company’s generation facilities (which the Company subsequently sold) or to refund outstanding tax-exempt bonds and notes.

New England Hydro Finance


			At March 31
Series	Rate %	Maturity	2007		2006
			(In thousands)
Series B	9.260	April 17, 2007	$	590	$	6,350
Series C	9.410	October 17, 2015		46,270		46,270

Total long-term debt				46,860		52,620
Long-term debt due within one year				5,650		5,760

Total long-term debt, excluding current portion			$	41,210	$	46,860

The Company’s long-term debt covenants provide for certain restrictive covenants and acceleration clauses. These covenants stipulate that note holders may declare the debt to be due and payable if total debt becomes greater than 70 percent of total capitalization. At March 31, 2007 and 2006, the total long-term debt was 61 percent and 59 percent of total capitalization, respectively.

New England Power


			At March 31
Series	Rate %	Maturity	2007			2006
			(In thousands)
Pollution Control Revenue Bonds:⁽¹⁾
CDA⁽²⁾	Variable	October 15, 2015	$	38,500		$	38,500
MIFA 1⁽³⁾	Variable	March 1, 2018		79,250			79,250
BFA 1⁽⁴⁾	Variable	November 1, 2020		135,850			135,850
BFA 2⁽⁴⁾	Variable	November 1, 2020		50,600			50,600
MIFA 2⁽³⁾	Variable	October 1, 2022		106,150			106,150
Unamortized discounts				(34	)		(40	)

Total long-term debt			$	410,316		$	410,310


Notes:

(1)		At March 31, 2007, interest rates on NEP’s variable rate bonds ranged from 3.64 percent to 3.68 percent.

(2)		CDA – Connecticut Development Authority

(3)		MIFA – Massachusetts Industrial Finance Authority (now known as Massachusetts Development Finance Agency)

(4)		BFA – Business Finance Authority of the State of New Hampshire

F-42

Nantucket Electric


			At March 31
Series	Rate %	Maturity	2007			2006
			(In thousands)
2006 Series 1996 MIFA Tax Exempt	5.600	July 1, 2006	$	—		$	1,400
2007 Series 1996 MIFA Tax Exempt	5.600	July 1, 2007		1,400			1,400
2008 Series 1996 MIFA Tax Exempt	5.750	July 1, 2008		1,400			1,400
2009 Series 1996 MIFA Tax Exempt	5.750	July 1, 2009		1,400			1,400
2017 Series 1996 MIFA Tax Exempt	5.875	July 1, 2017		10,500			10,500
2004 $3.5 Million MIFA Tax-Exempt.	Variable	March 16, 2016		2,335			2,495
2004 $10 million MIFA Tax-Exempt	Variable	March 1, 2039		10,000			10,000
2005 $28 million MIFA Tax-Exempt	Variable	December 1, 2040		28,000			28,000
Unamortized discounts				(66	)		(72	)

Total long-term debt				54,969			56,523
Long-term debt due within one year				1,575			1,560

Total long-term debt, excluding current portion			$	53,394		$	54,963

The Company has filed an application with the Massachusetts Development Finance Agency to refinance the $13 million 1996 MIFA tax exempt bonds which will remain outstanding after July 2, 2007. The Company intends to reissue the bonds as variable rate debt during the second quarter of fiscal year 2008.

Totals — National Grid USA


	At March 31
	2007			2006
	(In thousands)
Total long-term debt	$	3,389,068		$	3,629,630
Unamortized Discount on Debt		(1,667	)		(2,069	)
Long-term debt due within one year		218,873			302,320

Total long-term debt, excluding current portion	$	3,168,528		$	3,325,241

As of March 31, 2007, the aggregate payments to retire maturing long-term debt are as follows


Fiscal Year	Amount
2008	$	218,873
2009		688,761
2010		358,505
2011		358,525
2012		508,545
Thereafter		1,255,859

F-43


Fiscal Year	Amount
	$	3,389,068

At March 31, 2007, the Company’s subsidiaries’ long-term debt, excluding intercompany debt, had a carrying value of $2.2 billion and a fair value of $2.2 billion. The fair value of debt that reprices frequently at market rates approximates carrying value. The fair market value of the Company’s subsidiaries’ long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company and its subsidiaries for debt of the same remaining maturity.

NOTE I – SHORT-TERM DEBT

NEP

At March 31, 2007 and 2006, NEP had lines of credit and standby bond purchase facilities with banks totaling $440 million, which is available to provide liquidity support for $410 million of NEP’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The agreement with banks that provide NEP’s line of credit and standby bond purchase facility expires on November 29, 2009. There were no borrowings under these lines of credit at March 31, 2007.

Inter-company money pool

The Company and certain subsidiaries 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 third-party 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. The Company has the ability to borrow up to $2 billion from its parent (through intermediary entities), National Grid plc, and certain other subsidiaries of National Grid plc, including for the purpose of funding the money pool, if necessary. At March 31, 2007 and 2006, the Company had borrowed $1 billion and $644 million, respectively, under this arrangement.

NOTE J — CUMULATIVE PREFERRED STOCK

A summary of cumulative preferred stock at March 31, 2007 and 2006 is as follows (in thousands except for share data and call price):


		March 31,		March 31,		March 31,		March 31,
		2007		2006		2007		2006
		Shares				Amount				Call
	Company	Outstanding				(in 000’s)				Price
$100 par value - 3.40% Series	Niagara Mohawk		57,536		57,536	$	5,754	$	5,754	$	103.500
3.60% Series	Niagara Mohawk		137,139		137,139		13,714		13,714		104.850
3.90% Series	Niagara Mohawk		94,967		94,967		9,496		9,496		106.000
4.10% Series	Niagara Mohawk		52,830		52,830		5,283		5,283		102.000
4.44% Series	Mass Electric		22,585		22,585		2,259		2,259		104.068
4.76% Series	Mass Electric		24,680		24,680		2,468		2,468		103.730
4.85% Series	Niagara Mohawk		35,128		35,128		3,513		3,513		102.000
5.25% Series	Niagara Mohawk		34,115		34,115		3,410		3,410		102.000
6.00% Series	New England Power		11,117		11,117		1,112		1,112		(a	)
$50 par value - 4.50% Series	Narragansett		49,089		49,089		2,454		2,454		55.000

F-44

March 31,

2007

2006

2007

2006

Shares

Amount

Call

Company

Outstanding

(in 000’s)

Price

4.64% Series

Narragansett

57,057

2,854

52.125

Total

576,243

52,317

(a) Noncallable

NOTE K – COST OF REMOVAL AND ASSET RETIREMENT OBLIGATION

SFAS No. 143, “Accounting for Asset Retirement Obligations” provides the accounting requirements for retirement obligations associated with tangible long-lived assets. The Company does not have any material asset retirement obligations arising from legal obligations as defined under SFAS No. 143. However, under the Company’s current and prior rate plans, it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the SFAS No. 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation. These collections have been recorded to a regulatory liability account to reflect future use. The Company estimates it has collected over time approximately $642 million and $538 million for cost of removal through March 31, 2007 and 2006, respectively. Of the $642 million balance at March 31, 2007, $83 million represents the cost of removal recorded as a result of the acquisition of the Rhode Island gas assets of New England Gas Company.

In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of SFAS No. 143, and which was adopted by the Company for the fiscal year ended March 31, 2006. FIN 47 clarifies that the term “conditional asset retirement obligation” used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. The Company continues to monitor such contingencies, which do not have a material impact on the Company’s results of operations or its financial position for the periods ended March 31, 2007 and 2006.

NOTE L – ACQUISITIONS

Pending Acquisition of Keyspan Corporation (Keyspan)

In 2006, National Grid plc, the ultimate parent of the Company, announced the proposed acquisition of KeySpan for $7.3 billion together with the assumption of approximately $4.5 billion of debt. This would significantly expand its operations in the northeastern US as KeySpan is the fifth largest distributor of natural gas in the US and the largest in the northeast US, serving 2.6 million customers in New York, Massachusetts and New Hampshire. KeySpan also operates an electricity transmission and distribution network serving 1.1 million customers in New York under a long-term contract with the Long Island Power Authority. KeySpan’s other interests include 6.6 GW of generation capacity, together with a small portfolio of non-regulated, energy-related services, and strategic investments in certain gas pipeline, storage and liquefied natural gas assets. The planned combination of its current US operations with those of KeySpan would result in National Grid plc becoming the third largest energy utility in the US.

Acquisition of Rhode Island Gas Assets

On August 24, 2006, the Company acquired the Rhode Island gas assets of New England Gas Company from Southern Union Company for approximately $574 million which consisted of $497 million in cash and the assumption of $77 million of debt. The Company received a contribution from the parent company (National Grid plc) in the amount of $500 million to finance the acquisition, which is reflected in

F-45

‘Additional paid in capital.’ As part of this transaction, the Company also acquired four small non-regulated businesses.

On the date of the acquisition, the Rhode Island gas business served approximately 245,000 customers through a distribution network of over 3,000 miles of mains. The network substantially overlaps the Company’s existing electricity distribution service area in Rhode Island. This strong overlap is expected to create opportunities for savings. The rates for the Rhode Island gas distribution business are set by the same state regulators that set the Company’s electricity distribution rates in Rhode Island.

The acquisition was accounted for using the purchase method of accounting under the guidance of SFAS No. 141 “Business Combinations”, with the purchase price paid by the Company allocated to the Company’s net assets as of the acquisition date based on their fair values. The assets acquired and liabilities assumed have been recorded in the Company’s balance sheet beginning August 24, 2006 at their fair values and the results of operations have been included in the Company’s statement of operations since August 24, 2006. Therefore, the balance sheet and statements of operations for the periods subsequent to the acquisition are not comparable to the same periods in prior years.

The following table summarizes the fair values of New England Gas Company’s assets and liabilities assumed by the Company at the date of acquisition.


	At August 24, 2006
	(in thousands)
Net utility plant	$	357,667
Goodwill		235,800
Other property and investments		4,536
Cash and cash equivalents		16
Accounts receivable		72,453
Materials and supplies		36,099
Prepaid and other current assets		423
Regulatory assets		92,745
Deferred charges and other assets		422

Total assets acquired		800,161

Long-term debt		76,051
Long-term debt due in one year		544
Accounts payable		29,392
Other accrued expenses		39,491
Customer deposits		3,270
Accrued pension and other post-retirement benefits		46,922
Other reserves and deferred credits		107,753

Total liabilities assumed		303,423

Net assets acquired	$	496,738

F-46

NOTE M – DISCONTINUED OPERATIONS

National Grid Wireless (Wireless), a subsidiary of the Company, owns, operates and manages towers and other communications structures. Wireless also manages a fibre optic telecommunications system in the Northeastern United States.

As part of the Company’s strategy of focusing on energy markets, it committed during fiscal year 2007 to exit our wireless infrastructure operations. Subsequent to the end of fiscal year 2007, in April 2007, the Company agreed to the sale of the wireless infrastructure operations with completion expected in the summer of 2007 for proceeds of approximately $290 million. Our wireless infrastructure operations were expanded during fiscal year 2007 with acquisitions at a cost of $160 million.

Following the guidance of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company has reported Wireless as a discontinued operation for all periods presented. Below is financial information for Wireless (in thousands of dollars): The amounts disclosed above include balances and activity with National Grid USA subsidiaries that are eliminated in the consolidated financial statements.

Income Statement Data


	For the year ended
	March 31
	2007			2006
Total operating revenues	$	74,008		$	51,358
Total operating expenses		62,074			46,217

Operating income		11,934			5,141

Total other expense		(109,780	)		(97	)

Income before income taxes		(97,846	)		5,044

Income tax provision		10,641			2,668

Net Income	$	(108,487	)	$	2,376

Balance Sheet Data


	For the years ended
	March 31,
	2007		2006
ASSETS
Total current assets	$	23,090	$	17,297
Total assets		309,205		253,451
LIABILITIES AND STOCKHOLDER’S EQUITY
Total current liabilities		288,323		119,286
Total liabilities		305,650		136,451
Total stockholder’s equity		3,555		117,000

Total liabilities and stockholder’s equity		309,205		253,451

F-47

NOTE N – SUBSEQUENT EVENTS

On June 11, 2007, the Board of Directors approved a stock repurchase of 56 shares at a price of $13 million per share to be made on June 27, 2007.

F-48

REGISTERED OFFICE OF THE ISSUER

National Grid USA
25 Research Drive
Westborough
MA 01582
United States of America

THE ARRANGER AND DEALER

HSBC Bank plc
8 Canada Square
London E14 5HQ
United Kingdom

LEGAL ADVISERS

To the Dealers as to English law and United States law and to the Trustee as to English law

Clifford Chance LLP
10 Upper Bank Street
London E14 5JJ
United Kingdom

To the Issuer as to English and United States law

Linklaters LLP
One Silk Street
London EC2Y 8HQ
United Kingdom

THE TRUSTEE

The Law Debenture Trust Corporation p.l.c.
Fifth Floor
100 Wood Street
London EC2V 7EX
United Kingdom

ISSUING AND PAYING AGENT

The Bank of New York
One Canada Square
London E14 5AL
United Kingdom

PAYING AGENT

Kredietbank S.A. Luxembourgeoise
43 Boulevard Royal
L-2955 Luxembourg
Luxembourg

REGISTERED AUDITORS TO THE ISSUER

PricewaterhouseCoopers LLP
125 High Street
Boston MA 02110
United States of America

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National Grid (NGG) 20-F2008 FY Annual report (foreign)

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