Edgar Filing: BRITISH ENERGY PLC

Date: September 23, 2003

/s/ MIKE ALEXANDER

Mike Alexander

Title:

Chief Executive Officer

Form 20-F

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)

Annual report pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934 (Fee required)

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended March 31, 2003 (No Fee required)

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from N/A to N/A (No Fee required)

Commission file number 1-14990

BRITISH ENERGY PLC

(Exact Name of Registrant as Specified in Its Charter)

Scotland

(Jurisdiction of Incorporation or Organization)

3 Redwood Crescent, Peel Park, East Kilbride, G74 5PR

(Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered

Ordinary shares of 44 28/43p each (“ordinary shares”)		New York Stock Exchange*

American Depositary Shares (“ADSs”) each of which represents 75 ordinary shares		New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Ordinary shares of 44 28/43p each		620,362,444 shares
A shares of 60p each		80,908,247 shares
Non voting deferred shares of 60p each		74,752,351 shares
Non-voting special rights redeemable Preference share of £1		1 share

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

(1) x (2) x

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ¨ Item 18 x

Not for trading but only in connection with the registration of ADSs pursuant to the requirements of the Securities and Exchange Commission.

TABLE OF CONTENTS

		Page
Introduction		3

Exchange Rates		3

Technical Terms		3

Information Regarding Forward-looking Statements		3

Item 3.	Key Information	4

Item 4.	Information On The Company	20

Item 5.	Operating And Financial Review And Prospects	46

Item 6.	Directors, Senior Managers And Employees	73

Item 7.	Major Shareholders And Related Party Transactions	80

Item 8.	Financial Information	82

Item 9.	The Offer And Listing	83

Item 10.	Additional Information	84

Item 11.	Quantitative And Qualitative Disclosures About Market Risk	107

Item 13.	Dividend Arrearages And Delinquencies	110

Item 14.	Material Modifications To The Rights Of Security Holders And Use Of Proceeds	111

Item 15.	Controls And Procedures	111

Item 16.	[Reserved]	111

Item 17.	Financial Statements	111

Item 18.	Financial Statements	111

Item 19.	Exhibits	112

PLEASE NOTE: ITEMS 1, 2, 12, 16 AND 17 ARE NOT APPLICABLE.

Introduction

In this annual report, except as otherwise specified, “British Energy”, the “British Energy Group”, the “Company”, “we”, “us” or “our” refer to British Energy plc and its subsidiaries and any of their respective predecessors in business, as the context may require. We were incorporated under the Companies Act 1985, as amended (the “Companies Act”) on December 13, 1995.

Our registered office is located at 3 Redwood Crescent, Peel Park, East Kilbride, G74 5PR, Scotland, and our telephone number is 011 44 1355 262000. Our website address is www.british-energy.com. The information on our website is not a part of this annual report.

Exchange Rates

We publish our financial statements in pounds sterling. In this annual report, references to “pounds sterling”, “£”, “pence” or “p” are to UK currency, references to “US dollars”, “US$” or “$” are to US currency and reference to “Canadian dollars”, or “C$” are to Canadian currency. Amounts in this annual report stated in US dollars, unless otherwise indicated, have been translated from pounds sterling solely for convenience and should not be construed as representations that the pound sterling actually represent such US dollar amounts or could be converted into US dollars at the rate indicated or any other rate. The Noon Buying Rate for pounds sterling on September 5, 2003 was £1.00 = $1.59. For certain information about exchange rates between pounds sterling and US dollars, see “Item 3. Key Information—Exchange Rates”.

Technical Terms

This annual report refers to certain technical terms used to measure output of electricity and the production of electricity over time. The basic unit for the measurement of electricity output is a kilowatt (“kW”). The basic unit for the measurement of electricity production is a kilowatt-hour (“kWh”); that is, one hour of electricity production at a constant output of one kilowatt. One thousand kilowatts are a megawatt (“MW”) or, in terms of production, a megawatt-hour (“MWh”). One thousand megawatts are a gigawatt (“GW”) or, in terms of production, a gigawatt-hour (“GWh”). One thousand gigawatts are a terawatt (“TW”) or, in terms of production, a terawatt-hour (“TWh”).

Information Regarding Forward-looking Statements

This annual report contains certain “forward-looking” statements as defined in Section 21E of the US Securities Exchange Act of 1934. Such forward-looking statements include, among others:

•

statements concerning our proposed restructuring and the effect of our proposed restructuring on our business and financial condition or results of operations,

•

the anticipated development of the UK electricity industry, the future development of regulation of the UK electricity industry, the effect of these developments on our business, financial condition or results of operations, and

•

other matters that are not historical facts concerning our business operations, financial condition and results of operations.

These forward-looking statements involve known and unknown risks, uncertainties and other factors which are in some cases beyond our control and may cause our actual results or performance to differ materially from those expressed or implied by such forward-looking statements. For a discussion of some of the risks associated with these forward-looking statements, see the section entitled “Item 3. Key Information—Risk Factors”. Due to the uncertainties and risks associated with these forward-looking statements, which speak only as of the date hereof, we are claiming the benefit of the safe harbor provision referred to above.

ITEM 3. KEY INFORMATION

Risk Factors

Some of the significant risks that could affect our business are set out below. Additionally, some risks may be unknown to us and other risks, which we currently consider to be immaterial, could in fact be material. All of these risks could adversely affect our business, turnover, profits, assets, liquidity and capital resources. You should consider these factors in connection with the forward-looking statements in this document and the warnings on such forward-looking statements.

Risks Associated with our Restructuring

If our proposed restructuring is not completed, or if the results of our proposed restructuring are insufficient to allow us to meet our financial obligations as they fall due, we may have to initiate appropriate insolvency proceedings.

In September 2002, we announced that, following the review by our board of directors of the long-term prospects for British Energy, we had initiated discussions with the UK Government seeking immediate financial support to enable a longer-term restructuring of our business. On February 14, 2003, we announced that we had entered into a binding standstill agreement and a non-binding agreement on the principles of our proposed restructuring with certain of our most significant creditors. Our proposed restructuring is comprised of the following elements:

•

We expect to issue new bonds in an aggregate principal amount of up to £275 million, together with new shares representing substantially all of the ordinary shares of the restructured British Energy Group, to our most significant creditors, in exchange for the extinguishment of existing obligations we owe them;

•

We expect to enter into an agreement with the bank syndicate that provided financing for our Eggborough coal-fired power station, or the Eggborough Banks, for a new capacity and tolling agreement, or CTA, under which payments will be made as if they had been issued a further £150m of our New Bonds;

•

The existing Nuclear Generation Decommissioning Fund Limited, the Decommissioning Fund, will be enlarged into a new Nuclear Liabilities Fund, the NLF, to address the British Energy Group’s uncontracted nuclear liabilities and decommissioning costs. In addition to periodic contributions to the NLF, we will make an initial contribution of up to £275 million of new bonds to the NLF. The UK Government will assume responsibility for liabilities associated with historic spent fuel, as well as the uncontracted nuclear liabilities and decommissioning costs of our nuclear power stations that are not otherwise met by the NLF;

•

We have entered into new contracts with BNFL intended to vary the agreements under which BNFL currently provides front- and back-end fuel related services to our AGR stations. We announced on May 16, 2003, that we had exchanged contracts covering front-end and back-end fuel services with BNFL. See “Item 4 – Proposed Restructuring – The BNFL Contracts”; and

•

We were required to sell our interests in AmerGen in the United States and Bruce Power in Canada. On February 14, 2003, we announced the completion of the sale of our interest in Bruce Power LP. On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen. See “Item 4 – Proposed Restructuring – The Sale of Bruce Power and AmerGen”.

We believe that the proposed restructuring will: reduce our exposure to wholesale electricity prices and reduce our fixed and variable costs associated with the front and back-end fuel cycle services for our AGR power stations through our revised contracts with BNFL; reduce our exposure to long-term nuclear liabilities through the proposed NLF and new arrangements with the UK Government; and restructure our indebtedness and certain other contracts through arrangements with our most

significant creditors and the sale of our interests in AmerGen and Bruce Power. However, we cannot assure you that we will complete the proposed restructuring in the form set out above, or, if we do complete it, that the proposed restructuring will produce the benefits we expect, or that those benefits will be sufficient to allow us to meet our financial obligations as they fall due. As discussed in greater detail in the risk factors set out below, the completion of our proposed restructuring is dependent on a number of factors over which we have little or no control. These factors include the approval of the proposed restructuring by the UK Government, the approval of our proposed restructuring by our most significant creditors, the European Commission and, where required, our shareholders. If the restructuring is not completed we may not be able to meet our financial obligations as they fall due. In that event, we may have to initiate appropriate insolvency proceedings. If we were to commence insolvency proceedings, distributions, if any, to unsecured creditors may represent only a small fraction of our unsecured liabilities, and it is highly unlikely that our current shareholders would receive any return on their investment.

If we complete the proposed restructuring, our shareholders will suffer a very significant dilution of their interests in British Energy plc.

Under the proposed restructuring, we will undertake a court sanctioned scheme or schemes of arrangement, referred to as a Scheme of Arrangement, to restructure our obligations with respect to the holders of our bonds due 2003, 2006 and 2016 (referred to collectively as the Bondholders) and the Royal Bank of Scotland plc, or RBS, as provider of a letter of credit to the bank syndicate that provided financing for our Eggborough coal-fired power station (referred to collectively as the Eggborough Banks). We will also enter into other arrangements with the Eggborough Banks and our significant trade creditors; Teesside Power Limited, Total Gas & Power Limited and Enron Capital & Trade Europe Finance LLC (Teesside Power Limited, Total Gas & Power Limited and Enron Capital & Trade Europe Finance LLC are referred to collectively as the Significant Creditors) to restructure our obligations to them. As a result of these arrangements, the new shares issued to the Bondholders, RBS, the Eggborough Banks and the Significant Creditors will represent substantially all of the share capital of the restructured British Energy Group. We expect that our current shareholders will receive only a very small fraction of the issued share capital of the restructured group, if any. Consequently, if the proposed restructuring is completed, our current shareholders will suffer a very significant dilution of their interests.

Certain elements of our proposed restructuring constitute State Aid under European Union law, and consequently must be approved by the European Commission.

The UK Government has applied to the European Commission for its consent to the proposed restructuring, because the UK Government’s proposed role with respect to the NLF upon completion of the restructuring, and the assumption of responsibility for British Energy’s liabilities under historic spent fuel contracts with BNFL constitutes State Aid as defined by European Union law. We cannot assure you that the European Commission will consent to the restructuring as proposed, or that the European Commission will not impose conditions to their approval that would affect the financial terms or even the viability of the proposed restructuring.

Furthermore, while a decision by the European Commission to approve our proposed restructuring would allow us to proceed with its implementation, the decision of the European Commission would be subject to appeal to the European Court of First Instance. If the European Court of First Instance were to annul the European Commission’s decision, the European Commission would have to revisit the matter and issue another decision (which would be subject to the contents of the European Court of First Instance’s judgment). We cannot assure you that an affirmative decision by the European Commission would not be appealed, and if it were appealed, that the Court of First Instance would uphold the European Commission’s decision. We also cannot assure you that a Court of First Instance decision would not be appealed to the European Court of Justice. Such an appeal process may take several years.

The proposed Scheme of Arrangement requires the approval of the relevant UK court; without such approval, our proposed restructuring will not be able to proceed.

To become effective, the Scheme of Arrangement requires the approval of the relevant UK court that supervises the scheme. Before the court gives its approval, the court must satisfy itself that the proposed arrangements are fair to the creditors whose claims are being compromised pursuant to the Scheme of Arrangement. We cannot assure you that the court will determine that the restructuring arrangements contemplated by the Scheme of Arrangement are fair to such creditors, or that the court will not conclude that there are other reasons why it should not approve the Scheme of Arrangement. If the relevant UK court does not approve the Scheme of Arrangement, we may not be able to complete our proposed restructuring as envisaged.

The continued financial support from the UK Government is subject to the approval of the UK Secretary of State for Trade and Industry.

Since September 9, 2002, the UK Government has extended a credit facility, the Credit Facility, to us in order to provide working capital and cash collateral in support of our electricity trading contracts in the United Kingdom and certain contracts for the supply of goods and services. As at September 19, 2003, the aggregate principal amount of the Credit Facility was £200 million, of which we had drawn down approximately £20.8 million, principally to meet trading and other cash collateral requirements. The Credit Facility will mature on the earlier of September 30, 2004, or the date on which our proposed restructuring is completed. However, under the terms of the Credit Facility, the UK Secretary of State for the Department of Trade and Industry, the UK Secretary of State, is entitled to require the immediate repayment of the Credit Facility if, in his or her opinion, we cannot implement the proposed restructuring in the time or manner envisaged. We cannot assure you, therefore, that the UK Government will continue to make the Credit Facility available to us prior to September 30, 2004, or that if the Credit Facility is not available to us at any time, we will have sufficient resources to meet our working capital needs or to provide sufficient cash collateral to allow us to continue to maintain our electricity trading contracts. Furthermore, to the extent the UK Government continues to make the Credit Facility available to us, we cannot assure you that the aggregate principal amount of the Credit Facility will be sufficient to provide the amount of working capital and cash collateral in support of our electricity trading contracts and procurement contracts necessary to allow us to continue our business prior to the completion of the proposed restructuring. For further information, you should also read the risk factor entitled “Risks Related to our Business – Our bilateral trading contracts and certain of our other contracts may be subject to credit support obligations. If we are unable to provide such credit support where required, our exposure to both fluctuations in wholesale electricity prices and potential disruptions to the business may increase. Furthermore, given the current circumstances of the Company and its subsidiaries, certain contracts entered into by them may be capable of being terminated.”

We have reached a non-binding agreement on the principles of our restructuring with the Bondholders, the Eggborough Banks, RBS, and the Significant Creditors. If they withdraw their support for our proposed restructuring, the restructuring may not proceed and it is likely that we will be required to initiate insolvency proceedings.

On February 14, 2003, we announced that we had reached a non-binding agreement on the principles of our restructuring with the Bondholders, the Eggborough Banks, RBS, and the Significant Creditors. Although some of the Bondholders, the Eggborough Banks, RBS, and the Significant Creditors participated in the negotiations that produced the agreement on the principles of our restructuring, neither those creditors nor the UK Government are obligated to support the restructuring process or approve the restructuring, and we cannot assure you that they will do so. In addition, our proposed restructuring requires the support of the UK Government in order to implement the

arrangements with respect to the NLF, and the assumption of British Energy’s liabilities under historic spent fuel contracts with BNFL. If any or all of the Bondholders, the Eggborough Banks, RBS, the Significant Creditors or the UK Government withdraw their support for the restructuring process, it is likely that we would not be able to complete the proposed restructuring. If we do not complete the proposed restructuring, we may not be able to meet our financial obligations as they fall due, in which case, we may have to initiate appropriate insolvency proceedings. If we were to commence insolvency proceedings, distributions, if any, to unsecured creditors may represent only a small fraction of our unsecured liabilities, and it is highly unlikely that our current shareholders would receive any return on their investment.

The non-binding agreement on the principles of our restructuring is conditional upon the sale of our interest in AmerGen. If we do not manage to dispose of our interest in AmerGen in a timely manner, we may not be able to proceed with the proposed restructuring.

The non-binding agreement on the principles of our restructuring is conditional, among other things, on the sale of our 50% interest in AmerGen, our joint venture with Exelon Generation Company LLC, or Exelon, which owns and operates three nuclear power stations in the United States. Pursuant to the terms of the agreement, we must have completed the sale of our interest in AmerGen before the restructuring proposals can become effective.

On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy Nuclear Mid-Atlantic LLC, a wholly-owned subsidiary of FPL Group for approximately US$277 million. The proposed sale of our interest in AmerGen is subject, however, to a number of conditions, including satisfaction of Exelon’s right of first refusal as well as approvals and authorisations from various regulatory agencies in the United States including the Nuclear Regulatory Commission, or NRC, the Federal Energy Commission, or FERC, and the Federal Communications Commission.

We cannot assure you, however, that we will be able to complete the sale of our interest in AmerGen within the timescales envisaged, or that, if we do not complete the sale of our interest by that date, all or any of the Bondholders, RBS, the Eggborough Banks, the Significant Creditors or the UK Government will continue to support our proposed restructuring or that the UK Government will continue to make the credit facility available to us. For further information regarding the proposal to dispose of our 50% interest in AmerGen, see “Item 4. Information on the Company – Proposed Restructuring – The Sale of Bruce Power and AmerGen.”

Our standstill agreements are subject to a number of conditions precedent. If we do not meet these conditions, the restructuring may not proceed and we may have to initiate insolvency proceedings.

On February 14, 2003, we announced that we had entered into a binding standstill agreement among the Bondholders, the Eggborough Banks, RBS, the Significant Creditors and BNFL. Under the terms of the standstill agreements, these creditors agreed they would not take any steps to initiate any administration proceedings or demand or accelerate any amounts due and payable to them by us during the period commencing February 14, 2003 and ending at the earlier of September 30, 2004 (subject to a termination event (as described below)) or the successful completion of our proposed restructuring prior to that date. Termination events include:

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Certain insolvency events with respect to British Energy plc, our operating subsidiaries, British Energy Generation Limited (or BEG), British Energy Generation (UK) Limited (or BEG UK), British Energy Power & Energy Trading Limited (or BET) or Eggborough Power Limited;

•

Acceleration of payment by the UK Secretary of State of amounts borrowed under the Credit Facility;

•

The failure to achieve certain targets, including the execution of definitive documentation regarding our proposed restructuring, on or before September 30, 2003.

We cannot assure you that one or all of the events described above will or will not occur in the time specified or at all. If the standstill agreement is terminated for any reason, the creditors who are parties thereto may accelerate and demand payment of our obligations to them. Furthermore, termination of the standstill agreement will entitle the UK Secretary of State to demand the immediate repayment of the Credit Facility in accordance with its terms. In that event, we may be unable to meet our financial obligations as they fall due and we may have to initiate appropriate insolvency proceedings. If we were to commence insolvency proceedings, distributions, if any, to unsecured creditors may represent only a small fraction of their unsecured liabilities, and it is highly unlikely that our current shareholders would receive any return on their investment.

Our financial statements have been prepared on the basis that British Energy is a going concern. If British Energy ceases to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities.

Our financial statements have been prepared on the basis that British Energy is a going concern. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption depends upon a number of factors that are beyond our control, including those discussed above. If for any reason we are unable to complete our proposed restructuring and cease to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities. Such adjustments, reassessments and reclassifications may result in a material adverse change to the statement of our financial condition from that currently set forth in our financial statements.

Risks Related to our Business

We currently do not and may not, in the future, comply with the minimum listing criteria of the New York Stock Exchange Inc., and we may, therefore, lose our listing on the New York Stock Exchange.

On August 28, 2003 we announced that we had been notified by the New York Stock Exchange, Inc., or NYSE, that we did not currently comply with the NYSE’s continued listing standard relating to minimum market capitalisation and shareholders’ equity. The NYSE has also said it will consider our continuing suitability for listing in the light of any allocations of value between the existing creditors and the equity holders. We are currently in discussions with the NYSE with respect to our ability to meet the minimum market capitalisation and shareholders’ equity listing standard going forward and we are reviewing our options with respect to our listing on the New York Stock Exchange. We expect to supply materials to the NYSE for its evaluation demonstrating our ability to meet the minimum continued listing standards. There can be no assurance however, that we will meet the NYSE’s listing standard or that we will do so in a time period that is acceptable to the NYSE. If we do not meet the NYSE’s listing standards in time or at all, the NYSE may decide to de-list our American Depository Shares, or ADSs, representing beneficial interests in our ordinary shares, from the New York Stock Exchange. If our ADSs are not listed on the New York Stock Exchange, there may not be sufficient liquidity to allow our ADSs to trade efficiently which may, in turn, cause the price of our ADSs to fall.

Assuming that our proposed restructuring is completed, our future profitability is dependent upon several factors outside our control.

Assuming our proposed restructuring is completed, our future profitability is subject to our ability to reduce and maintain our operating costs at levels that are lower than the price we achieve for our output of electricity. However our ability to reduce and maintain our operating costs at that level and to maximize output is limited by several factors outside our control, including:

•

The level of future electricity prices depends upon a number of factors, including the price of fossil fuels, the margin between available capacity and demand, the level of demand and demand growth and the amount of new electricity generating capacity that becomes available. Demand and available capacity are uncertain and, in the short term, electricity prices can be highly volatile. To the extent that our output is not covered by fixed price sales contracts, a substantial decline in the wholesale market price for electricity can have a serious adverse effect on our ability to trade profitability; and

•

We may be subject to increased costs that result from changes in our industry or operations, including new or enhanced safety or regulatory requirements.

Therefore, we cannot assure you that, even if our proposed restructuring is completed, we will be able to trade profitably, or to meet our financial obligations as they fall due.

A significant engineering fault or a design flaw at one of our power stations or which is generic to a class of nuclear plants could decrease our revenues and increase our costs.

A major engineering fault at one of our power stations could result in the closure of that station ahead of its expected closure date for either commercial or safety reasons. Furthermore, engineering faults or safety risks arising from a design problem that is generic to a particular type of nuclear plant could result in the closure of all our nuclear power stations using that nuclear plant design ahead of their expected closure dates. The early closure of one or all of any one type of our nuclear power stations would result in a loss of planned future output and result in additional costs associated with the closure of the affected power station or stations.

We have comprehensive inspection and testing programs in place in order to evaluate the physical condition of our nuclear power stations. These programs periodically identify certain technical issues. We cannot assure you that the identification of technical issues with respect to our power stations will not require us to incur significant expenditure for repairs or replacements as well as lost output as a result of outages necessary to effect such repairs.

A change in the extensive regulation to which we are subject could adversely affect our profitability.

We are subject to extensive regulation by, among others, the European Union, the United Kingdom and the United States in relation to, among other things, the electricity market and nuclear safety. Decisions by regulators in each jurisdiction could adversely affect our financial condition and results of operations. Changes in the regulations governing the electricity markets in the United Kingdom, may affect electricity sales prices or the competitive market. For example, following the introduction of the New Electricity Trading Arrangements, or NETA, in 2001, there has been a substantial decrease in wholesale electricity prices in England and Wales. Further changes to the regulatory environment in the UK market, and the proposed extension of NETA to the Scottish electricity market, could also result in lower wholesale electricity prices. The UK Government has proposed to establish a unified Great Britain electricity market by April 2005. However, if this unified market is not implemented by April 2006, when the current sales contract for British Energy’s

generation from its two Scottish nuclear power stations expires, we may be unable to find sufficient willing buyers for our Scottish output at an acceptable price. Changes in regulations governing nuclear safety in each of the United Kingdom and the United States may result in the modification, suspension or revocation of our licenses to operate nuclear power stations, or require us to incur substantial additional cost for capital expenditure and/or services and labor. In the United Kingdom, we must obtain the approval of the nuclear safety regulator at specified intervals for the continued operation of our nuclear power stations, including their approval to restart a power station after any statutory, refueling or other outage. The refusal of the relevant regulator to approve, or any delay in gaining approval from the relevant regulator to continue or restart operation of any of our nuclear power stations, would adversely affect future revenues and reduce our ability to trade profitably.

A failure to comply with, or the incurrence of liabilities under, environmental, health and safety laws and regulations to which we are subject, or a failure to obtain or maintain required environmental, health and safety regulatory approvals, could adversely affect our business or our ability to trade profitably.

We are subject to various environmental protection, health and safety laws and regulations governing, among other things, (i) the generation, storage, handling, release, use, disposal and transportation of hazardous and radioactive materials; (ii) the emission and discharge of hazardous materials into the ground, air or water and (iii) decommissioning and decontamination of our facilities and the health and safety of the public and our employees. Regulators in the United Kingdom and the United States, including in the UK, the Nuclear Installations Inspectorate, Environment Agency and the Scottish Environment Protection Agency, and, in the US, the Environmental Protection Agency, administer these laws and regulations. In the United Kingdom, we are also subject to European Community law, and some international treaties are relevant to us. In the United States, we are additionally subject to extensive state and local regulation. See “Item 4. Information on the Company—Business Overview—Safety and Environmental Standards” and “Item 4. Information on the Company—Regulation—Safety and the Environment” for more information.

We are also required to obtain environmental and safety permits from various governmental authorities for our operations. Certain permits require periodic renewal or review of their conditions; we cannot predict whether we will be able to renew such permits or whether material changes in permit conditions will be imposed. We cannot assure you that we have been, or will at all times in the future be, in complete compliance with such laws, regulations and permits. Violations of these laws, regulations or permits could result in plant shutdowns, fines or other sanctions. Other liabilities under environmental laws, including clean-up of radioactive or hazardous substances, can be costly to discharge. Environmental liabilities or failure to comply with environmental laws could also lead to negative publicity and significant reputational damage.

While we cannot predict with any certainty the nature of developments in environmental regulation and control, we anticipate that the direction of future changes will be toward stricter controls. In view of the age and history of many sites we own or operate, we may incur liability in respect of sites that are found to be contaminated, together with increased costs of managing or cleaning up such sites. Site values could be affected and potential liabilities and clean-up costs may make disposal of potentially contaminated sites more difficult. We cannot assure you that any clean-up costs will not have an adverse effect on our business or our financial condition or results of operations.

Environmental, health and safety laws are complex, change frequently and have tended to become more stringent over time. While we have budgeted for future capital and operating expenditures to comply with current environmental, health and safety laws, we cannot assure you that environmental, health and safety laws will not change or become more stringent in the future. Therefore, we cannot assure you that our costs of complying with current and future environmental and

health and safety laws, and our liabilities arising from past or future releases of, or exposure to, radioactive or hazardous substances, will not adversely affect our business, result of operations or financial condition.

The potential hazards of nuclear operations could expose us to the risk of material liabilities, lost revenues, increased expenses or reputational damage.

Our operations use and generate radioactive and hazardous substances that have the potential for serious impact on human health and the environment. There are particular risks associated with the operation of nuclear power stations. These include accidents, the breakdown or failure of equipment or processes or human performance, including our safety controls, and other catastrophic events that could result in the dispersal of radioactive material over large areas, thereby causing injury or loss of life and extensive property or environmental damage. Certain of these events, including those arising as a result of third party acts such as acts of terrorism or war, are not wholly within our control. Liabilities we may incur, and interruptions in the operation of a facility caused by these events or associated with any of the radioactive or hazardous materials involved, could significantly reduce our revenues and increase our expenses and result in negative publicity and significant reputational damage. Insurance proceeds may not be adequate to cover all liabilities incurred, lost revenue or increased expenses.

Plant reliability at our UK nuclear power stations has fallen significantly behind world performance standards. Any further deterioration in reliability will adversely affect our operations and consequently, our results of operations. Plant unreliability also reduces our revenues as making good shortfalls in electricity which has been pre-sold can require us to buy electricity at times of very high prices.

Our future profitability is subject to our ability to maintain output at levels sufficient to ensure that our operating costs are lower than the price we achieve for our electricity. During the year ended March 31, 2003 our UK nuclear output was 63.8TWh as compared to 67.6TWh in the previous year. We believe that a proportion of the generation losses resulting from these unplanned outages was caused by deficiencies in equipment reliability, human performance and organisational effectiveness.

We are implementing a major performance improvement programme to enhance human performance, equipment reliability and organisational effectiveness, based on the experience of leading US nuclear operators. Nevertheless, there can be no assurance that we will achieve the necessary operational improvements to reduce generating losses and thereby improve output and reliability. A failure to improve output and reliability would have an adverse effect on our results of operation and future profitability.

Unreliability of plant can lead to the Company incurring significant system imbalance charges. Most of the Company’s output is pre-sold and it is committed to supply contracted volumes. If the plants fail to produce predicted volumes, we may have to enter the imbalance market to make good any shortfall. Prices in the imbalance market may be very high particularly in periods of tight capacity margins for generating plant in the UK and the unplanned outages of our stations may raise demand and therefore prices in the imbalance markets. We cannot therefore assure you that we will not, in addition to lost revenue and output from plant, incur significant imbalance costs if there are unplanned outages to plant.

Proposed arrangements governing the cost of electricity transmission in the United Kingdom could reduce our ability to trade profitably in the future.

In May 2001, the Gas and Electricity Markets Authority, or GEMA, proposed a number of possible reforms to the market arrangements governing electricity transmission system access and losses in

England and Wales. Transmission losses occur from the electricity that is lost to the network in the form of heat as it is transmitted. If GEMA were to implement the proposals in their present form, they would result in a significant redistribution of transmission costs between electricity market participants. Under the proposals, some generators would pay for a proportion of transmission losses for which they were not previously responsible. The proposals would be unfavorable to generating plants located in the North of England and Scotland, which make up a significant portion of our generating capacity. On January 17, 2003, GEMA directed that a modification should be implemented to the Balancing and Settlement Code, to introduce zonal marginal transmission losses, with effect from April 2004. On January 30, 2003, the Government issued a consultation paper on whether these changes were appropriate for Great Britain as a whole, and concluded on June 27, 2003 that they were not. It is now uncertain whether the changes will still be introduced only in England and Wales, or whether they will subsequently be considered again for Great Britain as a whole once the British Electricity Transmission and Trading Arrangements (BETTA) are introduced.

GEMA has also required National Grid Transco, as operator of the transmission system, to review the charging arrangements for access to and use of the transmission network. This review is not yet complete, but could result in changes which would adversely affect the amount of charges payable by British Energy from April 2004, given the disparate geographical distribution of our plant.

If the NLF does not become effective, we may be required to make substantial payments to meet the long-term post-closure costs of decommissioning our existing nuclear power stations in the United Kingdom. Separately, and in addition, we may be required to make substantial payments to meet revised projected costs of decommissioning of the AmerGen stations.

In the United Kingdom we established the Decommissioning Fund to accumulate funds to meet certain long-term post-closure costs of decommissioning our UK nuclear assets. We made, and until the NLF is operational, will continue to make, quarterly contributions to the Decommissioning Fund that are subject to adjustment for inflation. However, there is no certainty that the Decommissioning Fund will be sufficient to cover all the liabilities to which it relates. In addition, other substantial decommissioning liabilities are currently unfunded. As part of the proposed restructuring, the Decommissioning Fund will be enlarged into a new NLF to which we will make fixed contributions as well as an initial contribution of up to £275 million aggregate principal amount by way of new bonds. Additionally we will contribute £150,000 (indexed to RPI) for every tonne of uranium loaded into Sizewell B our Pressurised Water Reactor nuclear power station, or PWR, after completion of the proposed restructuring, and payments amounting (initially and subject to adjustment) to 65% of our consolidated annual cash flow net of tax, financing costs, cash reserves and a forecast expenditure reserve. However, we expect that as part of the establishment of the NLF, the UK Government will assume responsibility for liabilities associated with our historic spent fuel as well as the uncontracted nuclear liabilities and decommissioning costs of our nuclear power stations to the extent that the assets of the NLF, funded by our historic contributions to the Decommissioning Fund and our future contributions to the NLF are insufficient to meet those liabilities as they fall due. Furthermore, as a condition of the NLF, we will be required to continue to operate our nuclear power stations in compliance with applicable law and the practices and the procedures acceptable to the safety and environmental regulatory authorities. If we fail to do so, we may in certain circumstances incur additional liabilities over and above those which we currently expect to bear under the NLF.

If the NLF does not become effective, we will be required to continue to make contributions to the Decommissioning Fund pursuant to our obligations under our nuclear site licenses, and will be required to meet other historic unfunded liabilities and certain decommissioning liabilities, which may in turn significantly reduce our ability to trade profitably.

In the United States, the US Nuclear Regulatory Commission, or NRC, requires nuclear site operators, such as AmerGen, to establish a segregated decommissioning fund to meet the costs of a plant’s decommissioning. The NRC requires an annual review of both the forecast cost of decommissioning and the adequacy of the fund to accumulate the required money. Thus, the required

size of a plant’s decommissioning fund is adjusted periodically to take account of changes in the cost of labor, energy, waste disposal and the impact of technological advances. Each of the decommissioning funds for AmerGen’s three nuclear stations is currently deemed to be fully funded. However, we cannot assure you that a future review of the cost of decommissioning will not result in AmerGen being required to invest substantial additional amounts in the decommissioning funds to meet the revised projected future cost of decommissioning its plants. Under the terms of the AmerGen joint venture agreement, we would be required to contribute 50% of that additional amount.

On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy Nuclear Mid-Atlantic LLC, a wholly-owned subsidiary of FPL Group for approximately US$277 million. The proposed sale of our interest in AmerGen is subject, however, to a number of conditions, including satisfaction of Exelon’s right of first refusal as well as approvals and authorisations from various regulatory agencies in the United States including the Nuclear Regulatory Commission, the Federal Energy Commission, and the Federal Communications Commission. See “Item 4 – Information on the Company — Proposed Restructuring — The Sale of Bruce Power and AmerGen.”

Our revised contracts with BNFL are contingent upon completion of the restructuring, and our reliance on BNFL as our single supplier for AGR fuel and spent fuel management services could lead to increased costs and decreased profitability upon termination of the revised contracts if the restructuring is not completed.

We currently rely on BNFL (a company wholly owned by the UK Government), to supply fuel fabrication and spent fuel management services for our Advanced Gas Cooled Reactor, or AGR, stations. BNFL is currently the sole supplier of AGR fuel worldwide. On May 16, 2003, we announced that we had entered into a series of contracts with BNFL, replacing our then current contracts covering the fabrication of fuel for our AGR power stations, known as front-end fuel cycle services, and the disposal of AGR fuel used by our AGR power stations, known as back-end fuel cycle services. The front-end fuel cycle contracts became effective as of April 1, 2003, but, with the exception of the new arrangements for the supply of uranics, may be terminated if, among other things, the proposed restructuring is not completed. The back-end fuel cycle contracts are conditional upon completion of the restructuring, although, in accordance with the terms of the standstill agreement, our payments to BNFL for back-end fuel cycle services are made as if the back-end contracts had become effective on April 1, 2003.

Under these new contracts, prices for a certain proportion of front-end and back-end fuel cycle services are linked to the prevailing market price for electricity, thereby reducing our exposure to downward fluctuations in market price, conversely if market prices rise above certain levels, a proportion of our costs under the revised BNFL contracts will also increase.

If we do not complete the proposed restructuring, and our revised contracts with BNFL are terminated (or do not take effect), we would be required to rely upon our prior front-end and back-end fuel cycle contracts with BNFL. Consequently, we would be unable to realise the operating cost benefits associated with our revised contracts with BNFL. Furthermore, our current contract with BNFL for the supply of front-end fuel cycle services for the majority of our AGR stations expires in 2006. If the revised contracts with BNFL are terminated (or do not take effect) and if BNFL is unable or unwilling to continue to supply fuel to our AGR stations, we would need to seek a new source of supply for AGR fuel. A new supplier of fuel for our AGR stations would need to retool its production systems in order to be able to produce AGR fuel. The costs of such a retooling would probably be passed on to us resulting in significantly increased operating costs.

Our bilateral trading contracts and certain of our other contracts may be subject to credit support obligations. If we are unable to provide such credit support where required, our exposure to both fluctuations in wholesale electricity prices and potential disruptions to the

business may increase. Furthermore, given the current circumstances of the Company and its subsidiaries, certain contracts entered into by them may be capable of being terminated.

We sell a substantial percentage of our output pursuant to fixed price bilateral trading contracts and are party to various other contractual arrangements. However, as our credit rating is currently below investment grade, we are required to establish alternative credit support to a parent company guarantee in respect of our obligations under certain of those contracts. In the case of bilateral trading contracts the financial obligations to be covered by the alternative credit support are related to the prevailing wholesale price of electricity. Our ability to provide alternative credit support for our trading operations is, and will, until the completion of our proposed restructuring, be subject to our continued access to funds under the Credit Facility. We have retained a trading relationship with a high proportion of our existing contracted counterparties during the period since our announcement of September 5, 2002, although in most cases we have been required to provide alternative credit support to a parent company guarantee. Given the current circumstances of the Company and its subsidiaries, certain contracts may be capable of being terminated, and such termination may result in termination payments being payable as well as having an adverse effect on our cash flows. We cannot assure you that the Credit Facility will continue to be available to us, or that if the Credit Facility is available to us, the sums available thereunder will be sufficient to provide alternative credit support for all of our bilateral trading contracts or other contractual arrangements that require such security. Following completion of our restructuring, we anticipate that we will be required to obtain access to alternative credit facilities or use our own cash reserves to meet these alternative credit support requirements.

We have entered into a hedging strategy that reduces the price risk associated with our electricity generation. However, this has reduced our ability to benefit from increasing market prices in the medium term and may also result in an increase in collateral requirements as market prices rise. In addition, should various other unforeseen events occur which place demands on cash flow, our financial resources may prove to be insufficient.

We have entered into short-term and medium-term power-sale contracts with market counterparties and with other industrial and commercial customers to hedge a significant proportion of our output against downward movements in market price. However, as a result of this strategy, the cash flow benefits to British Energy of market price increases are reduced while the level of collateral calls made by trading counterparties increases to cover their mark to market exposure. The potential combination of these factors and the possible effects of the market price linkage on the costs incurred by us for fuel services under the new BNFL contracts (as described in “Item 3 – Risk Factors – Our revised contracts with BNFL are contingent upon completion of the restructuring, and our reliance upon BNFL as our single supplier of AGR fuel could lead to increased costs and decreased profitability upon termination of the revised contracts if the restructuring is not completed”) may, and has recently, resulted in a need to drawdown on the Credit Facility to support our ongoing working capital requirements. The amount of any future drawdowns will fluctuate depending on requirements to fund working capital and collateral needs and, as at September 19, 2003, we had drawn down £20.8 million from the Credit Facility.

We are reviewing our trading strategy to attempt to maintain an appropriate balance between the importance to us at the time of maintaining a high degree of certainty of our revenues and collateral requirements, as well as continuing to take steps to identify and manage cash flow risks and manage cash resources. We cannot therefore assure you that the level of funding available to us will be sufficient to meet our future needs.

A substantial portion of the further proceeds we expect to receive as a result of the Bruce Power disposal are contingent upon the occurrence of certain events.

On January 17, 2003 we entered into a master purchase agreement to dispose of our 82.4% interest in Bruce Power and our 50% interest in Huron Wind to a consortium made up of Cameco

Corporation, BPC Generation Infrastructure Trust and TransCanada PipeLines Limited. Under the terms of the master purchase agreement, approximately C$120 million is deferred compensation, of which C$20 million relates to warranty claims (if any).

The remaining deferred amount of approximately C$100 million is contingent upon the successful restart of two of the Bruce A reactors. The master purchase agreement provided that if the restart of the two reactors were to be delayed beyond June 15, 2003 and August 1, 2003, respectively, the consideration of C$50 million per reactor will be reduced on a sliding scale falling to zero after nine months. Bruce Power did not succeed in restarting the two reactors by the dates specified, consequently, while work continues to restart the reactors as soon as possible, we cannot assure you that the amount of deferred compensation we receive will not be further reduced owing to any further delays in restarting the reactors.

In addition, it was agreed that a further C$80 million of compensation from the sale of Bruce Power would be held in an escrow account to cover estimated outstanding tax liabilities of Bruce Power. In the event that the sums held in the escrow account are not sufficient to cover the outstanding tax liabilities, we would be required to repay the amount of such excess tax liabilities to the purchasers. To date, some C$3 million has been released to British Energy from these funds. These amounts, however, remain subject to further adjustment.

The cost of providing pensions benefits to eligible former employees is subject to changes in pension fund values and changing demographics, and might have a material adverse effect on our financial results.

We operate two pension schemes that provide defined benefits to eligible recipients. The cost of providing these benefits is subject to changes in pension fund values and changing demographics, including longer life expectancy of the schemes’ beneficiaries. Recent sustained declines in equity markets and reductions in bond yields have and may continue to have a material adverse effect on the value of our pension funds. We may be required to recognize a charge to our profit and loss account to the extent that the pension fund values are less than the total anticipated liability under the plan. In addition, we may be required to contribute additional amounts to our pension funds to address any difference between pension fund values and accrued liabilities. We cannot assure you that such charges or payments will not have an adverse effect on our financial condition.

Selected Financial Data

The following summary consolidated financial information for British Energy, insofar as it relates to profit and loss and cash flow for the fiscal years ended March 31, 2003, 2002 and 2001, and balance sheets as of March 31, 2003 and 2002 is derived from the audited financial statements appearing elsewhere in this annual report. On November 28, 2002, we announced proposals for the restructuring of British Energy. See “Item 4. Information on the Company – Our Proposed Restructuring”. Our financial statements have been prepared on the basis that British Energy is a going concern. See “Item 3 – Risk Factors – Risks Related to our Restructuring – Our Financial Statements Have Been Prepared on the Basis that British Energy is a Going Concern”.

Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United Kingdom, or UK GAAP, which differs in certain significant respects from generally accepted accounting principles in the United States, or US GAAP. In particular, the treatment under US GAAP of future liabilities associated with back-end fuel cycle costs and the estimated costs of decommissioning that are not covered by contractual arrangements result in significant differences between our reported financial condition and results of operations under US GAAP as compared with UK GAAP. A full description of the significant differences between UK GAAP and US GAAP as they apply to us and a reconciliation of (loss)/profit after tax (or net (loss)/income) and equity shareholders’ funds (or deficit on equity shareholders funds) under UK GAAP to those under US GAAP

are set out in Note 37 to our consolidated financial statements and in “Item 5. Operating and Financial Review and Prospects – Critical Accounting Policies”.

You should read the following summary consolidated financial information in conjunction with our audited consolidated financial statements and the notes thereto appearing elsewhere in this annual report as well as the section entitled “Item 4. Information on the Company – Our Proposed Restructuring” and the section entitled “Item 5. Operating and Financial Review and Prospects”.

	Year ended March 31,
	2003⁽¹⁾			2003			2002			2001			2000			1999
	(restated)⁽²⁾
	(in millions, except earnings and dividends per share and per ADS and weighted average shares)
Profit and Loss Account Information:
*UK GAAP*
Turnover	$	3,026		£	1,903		£	2,049		£	2,124		£	2,058		£	2,067
Turnover—continuing operations		2,430			1,528			1,701			2,124			2,058			2,067
Turnover—discontinued operations		596			375			348			—			—			—
Operating (loss)/profit		(6,045	)		(3,802	)		(281	)		280			412			481
Operating (loss)/profit—continuing operations		(6,199	)		(3,899	)		(333	)		280			412			481
Operating (loss)/profit—discontinued operations		154			97			52			—			—			—
(Loss)/profit before taxation		(6,824	)		(4,292	)		(493	)		57			225			276
Taxation		585			368			(25	)		(48	)		(118	)		(68	)

(Loss)/profit after taxation		(6,239	)		(3,924	)		(518	)		9			107			208

Dividends⁽³⁾⁽⁴⁾		—			—			(48	)		(48	)		(48	)		(110	)
Basic (loss)/earnings per ordinary share(s)		(1,040	)		(654.7	)p		(88.5	)p		1.2	p		16.4	p		30.3	p
Basic (loss)/earnings per ordinary share(s)—continuing operations		(1,066	)		(670.8	)p		(97.2	)p		1.2	p		16.4	p		30.3	p
Basic (loss)/earnings per ordinary share(s)—discontinued operations		26.0			16.1	p		8.7	p		—			—			—
Basic (loss)/earnings per ADS⁽⁵⁾		(78,074	)		(49,103	)p		(6,638	)p		90	p		1,230	p		2,272	p
Basic (loss)/earnings per ADS⁽⁵⁾—continuing operations		(79,993	)		(50,310	)p		(7,290	)p		90	p		1,230	p		2,272	p
Basic (loss)/earnings per ADS⁽⁵⁾—discontinued operations		1,921			1,208	p		652.5	p		—			—			—
Diluted (loss)/earnings per ordinary share(s)		(1,040	)		(654.7	)p		(88.5	)p		1.2	p		16.1	p		29.2	p
Diluted (loss)/earnings per ordinary share(s)—continuing operations		(1,066	)		(670.8	)p		(97.2	)p		1.2	p		16.1	p		29.2	p
Diluted (loss)/earnings per ordinary share(s)—discontinued operations		26.0			16.1	p		8.7	p		—			—			—
Diluted (loss)/earnings per ADS⁽⁵⁾		(78,074	)		(49,103	)p		(6,638	)p		90	p		1,208	p		2,190	p
Diluted (loss)/earnings per ADS⁽⁵⁾—continuing operations		(79,993	)		(50,310	)p		(7,290	)p		90	p		1,208	p		2,190	p
Diluted (loss)/earnings per ADS⁽⁵⁾—discontinued operations		1,921			1,208	p		652.5	p		—			—			—
Dividends per ordinary share, net⁽³⁾⁽⁴⁾		—			—			8.0	p		8.0	p		8.0	p		16.0	p
Dividends per ADS, net^(3)(4)(5)		—			—			600.0	p		600.0	p		600.0	p		1,200	p

	Year ended March 31,
	2003⁽¹⁾			2003			2002			2001			2000			1999
	(restated)⁽²⁾
	(in millions, except earnings and dividends per share and per ADS and weighted average shares)
*US GAAP*
Turnover	$	3,026		£	1,903		£	2,049		£	2,124		£	2,058		£	2,067
Turnover—continuing operations		2,430			1,528			1,701			2,124			2,058			2,067
Turnover—discontinued operations		596			375			348			—			—			—
(Loss)/profit after taxation		(12,294	)		(7,732	)		(426	)		(124	)		40			67
Basic (loss)/earnings per ordinary share(s)		(2,042	)		(1,284	)p		(71.2	)p		(21.0	)p		6.3	p		9.8	p
Basic (loss)/earnings per ordinary share(s)—continuing operations		(2,056	)		(1,293	)p		(74.0	)p		(21.0	)p		6.3	p		9.8	p
Basic (loss)/earnings per ordinary share(s)—discontinued operations		14.0			8.8	p		2.8	p		—			—			—
Basic (loss)/earnings per ADS⁽⁵⁾		(153,177	)		(96,300	)p		(5,340	)p		(1,575	)p		472.5	p		735.0	p
Basic (loss)/earnings per ADS⁽⁵⁾—continuing operations		(154,190	)		(96,975	)p		(5,550	)p		(1,575	)p		472.5	p		735.0	p
Basic (loss)/earnings per ADS⁽⁵⁾—discontinued operations		1,049			660	p		210	p		—			—			—
Diluted (loss)/earnings per ordinary share(s)		(2,042	)		(1,284	)p		(71.2	)p		(21.0	)p		6.1	p		9.4	p
Diluted (loss)/earnings per ordinary share(s)—continuing operations		(2,056	)		(1,293	)p		(74.0	)p		(21.0	)p		6.1	p		9.4	p
Diluted (loss)/earnings per ordinary share(s)—continuing operations		14.0			8.8	p		2.8	p		—			—			—
Diluted (loss)/earnings per ADS⁽⁵⁾		(153,177	)		(96,300	)p		(5,340	)p		(1,575	)p		457.5	p		705.0	p
Diluted (loss)/earnings per ADS⁽⁵⁾—continuing operations		(154,190	)		(96,975	)p		(5,550	)p		(1,575	)p		475.5	p		705.0	p
Diluted (loss)/earnings per ADS⁽⁵⁾—discontinued operations		1,049			660	p		210	p		—			—			—
Weighted average ordinary shares(millions)		602			602			598			597			651			712

	As at March 31,
	2003⁽¹⁾			2003			2002			2001			2000			1999
	(restated)⁽²⁾
	(in millions)
Balance sheet information
*UK GAAP*
Fixed assets	$	1,213		£	763		£	4,909		£	5,245		£	5,620		£	4,882
Total assets		3,461			2,177			6,775			6,784			7,051			6,561
Provisions and long term liabilities		(6,956	)		(4,375	)		(5,173	)		(4,931	)		(4,490	)		(4,308	)
Equity shareholders’ (deficit)/funds		(5,527	)		(3,476	)		490			1,075			1,110			1,616

	As at March 31,
	2003⁽¹⁾			2003			2002			2001			2000			1999
	(restated)⁽²⁾
	(in millions)
*US GAAP*
Fixed assets	$	1,175		£	739		£	8,259		£	8,082		£	8,517		£	7,612
Total assets		3,309			2,081			10,250			9,766			11,823			11,155
Provisions and long term liabilities		(15,848	)		(9,967	)		(10,367	)		(9,756	)		(11,024	)		(10,523	)
Equity shareholders’ (deficit)/funds		(14,700	)		(9,245	)		(1,228	)		(736	)		(545	)		103

	Year ended March 31,
	2003⁽¹⁾			2003			2002			2001			2000			1999
	(restated)⁽²⁾
	(in millions)
Cash Flow Information
*UK GAAP*
Operating (loss)/profit including exceptional items	$	(6,045	)	£	(3,802	)	£	(281	)	£	280		£	412		£	481
Exceptional items		6,211			3,906			512			(54	)		16			(8	)

Cash generated by operations:
operating profit excluding exceptional items		165			104			231			226			428			473
Depreciation charges		456			287			285			277			260			278
Nuclear liabilities charged to operating costs		167			105			156			132			141			166
Nuclear liabilities and other provisions discharged:
Nuclear liabilities		(183	)		(115	)		(332	)		(319	)		(310	)		(332	)
Other provisions discharged		(72	)		(45	)		(43	)		(39	)		(34	)		(28	)
Regular contributions to UK decommissioning fund		(29	)		(18	)		(18	)		(17	)		(17	)		(17	)
Working capital:
Decrease in stocks		95			60			66			27			4			8
(Increase)/decrease in debtors		(29	)		(18	)		(117	)		97			(54	)		13
(Decreased/increase in creditors		(38	)		(24	)		152			(107	)		32			(4	)

Net cash inflow from operating activities		534			336			380			277			450			557
Payments to acquire tangible fixed assets		(448	)		(282	)		(225	)		(133	)		(137	)		(78	)

Net cash inflow from operating activities net of capital expenditure		86			54			155			144			313			479

⁽¹⁾

Translated, solely for the convenience of the reader, at $1.59 to £1.00, the Noon Buying Rate in effect on September 5, 2003

⁽²⁾

Our consolidated financial statements were restated in 2002 to reflect the retroactive application of the UK Accounting Standards Board’s Financial Reporting Standard No. 19—Deferred Tax, FRS 19. FRS 19 came into effect with respect to all accounting periods ending after January 23, 2002 and requires that, when calculating the amount of taxation, full provisions be made for all timing differences for deferred taxes.

⁽³⁾

Dividends per share exclude any associated UK tax credit available to certain holders of ordinary shares.

⁽⁴⁾

In July 1999, our shareholders approved a return of value of approximately £432 million.

⁽⁵⁾

Calculated based on a ratio of 75 ordinary shares for one ADS. On March 18, 2003, we increased the ratio of four ordinary shares for one ADS to the current ratio of 75 ordinary shares for one ADS.

⁽⁶⁾

The turnover for discontinued operations which related to Bruce Power (our interest in which was sold on February 14, 2003) are set out on a 100% holding basis. British Energy’s share in Bruce Power was 82.4% prior to the disposal.

Dividends

Our board of directors did not declare any dividend payment for the year ended March 31, 2003. In prior fiscal years, we have paid interim and final dividends in January and July respectively. Future dividends will be dependent upon our earnings, financial condition and other factors, including completion of our proposed restructuring. Nevertheless, our board of directors does not expect to declare or propose any dividend on our ordinary shares or our A shares prior to the completion of our proposed restructuring (See “Item 5. Information about the Company – Proposed Restructuring”). The following table sets out the dividends paid on ordinary shares and ADSs in respect of the past five fiscal years, excluding any associated UK tax credit in respect of such dividends.

	Year ended March 31
	2003	2002	2001	2000	1999
	(in pence)
Pence per ordinary share⁽¹⁾
Interim	—	2.7	2.7	5.7	5.3
Final	—	5.3	5.3	2.3	10.7

Total	—	8.0	8.0	8.0	16.0


	Year ended March 31
	2003	2002	2001	2000	1999
	(in dollars)
US dollar per ADS:^(1)(2)(3)
Interim	—	3.00	3.00	6.75	6.38
Final	—	5.63	5.63	2.81	12.94

Total	—	8.63	8.63	9.56	19.32

⁽¹⁾

Dividends per share and per ADS exclude any associated UK tax credit available to certain holders of ordinary shares and ADSs. Dividends paid by the Depositary in respect of ADSs are paid in US dollars based on a market rate of exchange that differs from the Noon Buying Rate.

⁽²⁾

Calculated on a ratio of 75 ordinary shares for one ADS.

⁽³⁾

Dividends have been translated from pounds sterling into US dollars, solely for the convenience of the reader at the Noon Buying Rate in effect at the date of payment. As our dividends are paid in pounds sterling, exchange rate fluctuations will affect the US dollar amounts received by holders of ADSs on conversion by the Depositary of such cash dividends.

Exchange Rates

Dividends have been paid in pounds sterling. Exchange rate fluctuations have affected the US dollar amounts received by owners of the ADSs on conversion by the Depositary of such cash dividends. In addition, fluctuations in the exchange rate between pounds sterling and US dollars have affected the US equivalent of the quoted pounds sterling price of ordinary shares on the Daily Official List of the London Stock Exchange, and as a result, will likely affect the market price of ADSs in the United States.

The following table sets forth, for the periods and dates indicated, the noon buying rate in The City of New York as certified for customs purposes by the Federal Reserve Bank of New York, which we refer to as the Noon Buying Rate, for cable transfers in British pounds sterling, expressed in US dollars per British pound sterling. We provide these rates for your convenience only, and they are not the rates of exchange we used to prepare our consolidated financial statements included elsewhere in this annual report. We are not representing that British pounds sterling amounts have been or could be converted into US dollars at any of the exchange rates indicated.

Year ended December 31,	High		Low		Average(1)		Period end
1998	$	1.72	$	1.61	$	1.66	$	1.66
1999	$	1.68	$	1.55	$	1.62	$	1.60
2000	$	1.65	$	1.40	$	1.50	$	1.50
2001	$	1.50	$	1.37	$	1.44	$	1.45
2002	$	1.61	$	1.41	$	1.45	$	1.61
2003 (through September 5)	$	1.68	$	1.55	$	1.61	$	1.59

⁽¹⁾

The average of the Noon Buying Rates on the last business day of each month during the relevant period.

The following table sets forth, for the six months prior to the date of this annual report, the high and low Noon Buying Rates.

Month 2003	High		Low
March	$	1.61	$	1.56
April	$	1.60	$	1.55
May	$	1.65	$	1.59
June	$	1.68	$	1.63
July	$	1.65	$	1.59
August	$	1.62	$	1.57
September (through September 5)	$	1.61	$	1.57

Except as we specify otherwise, we converted exchange rate translations in this annual report at the rates in effect on March 31, 2003, which correspond to the rates we used to prepare our consolidated financial statements.

ITEM 4. INFORMATION ON THE COMPANY

Business Overview

We are an electricity generator, with interests in a total of 15 nuclear reactors and one coal-fired plant in the United Kingdom. We operate the eight most modern nuclear power stations in England and Scotland, with a combined capacity of 9,600 MW, and a coal-fired power station in England with a capacity of 2,000 MW. In the year ended March 31, 2003, we had an aggregate output from our nine power stations in the UK of 69.5 TWh.

In the United States, we have a 50% interest in AmerGen. Exelon Generation Company LLC, or Exelon, owns the remaining 50% interest. AmerGen owns and operates three nuclear power stations in Clinton, Illinois, Oyster Creek, New Jersey and Three Mile Island, Pennsylvania with a combined capacity of 2,500 MW. The operation of these nuclear power stations is integrated with the operation of Exelon’s nuclear power stations.

On September 11, 2003 we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy Nuclear Mid-Atlantic LLC, a wholly-owned subsidiary of FPL Group for approximately US$277m. See “Item 4 – Information on the Company – Proposed Restructuring – The sale of Bruce Power and AmerGen.”

We use a variety of routes to market in the United Kingdom, including trading electricity in the wholesale over-the-counter markets and selling electricity directly to large industrial and commercial customers through our direct sales business. Our direct sales business is continuing to grow, and accounted for 22.5 TWh during the year ended March 31, 2003, an increase of 20% on the previous year. We have placed particular emphasis on securing renewals and extensions of existing business to reduce our exposure to future wholesale market prices. In the United States, the American stations have fixed arrangements in place with the former owners of the stations or with Exelon for the sale of all of their output at agreed prices over the currently licensed lives of the stations. As a result, AmerGen has limited exposure to electricity price movements in the United States.

In the year ended March 31, 2003, our total turnover was £2,115 million. Our net loss before tax, including exceptional items, was £4,292 million, and our loss after tax was £3,924 million. Our net loss before tax, excluding exceptional items was £130 million. For a description of these exceptional items, please see “Item 5. Operating and Financial Review and Prospects – Factors Affecting Results of Operations – Exceptional Operating and Financing Items”.

Recent Developments

On September 9, 2002, the UK Government granted us the Credit Facility in order to provide working capital and cash collateral in support of our electricity trading contracts in the United Kingdom and certain procurement contracts. The Credit Facility currently provides for an aggregate principal amount of £200 million and will mature, subject to certain conditions, at the earlier of the completion of our proposed restructuring or September 30, 2004.

On November 28, 2002, we announced that we had concluded a non-binding agreement on the principles for the financial restructuring of British Energy, referred to as the Proposed Restructuring. The Proposed Restructuring had been negotiated among British Energy, the Bondholders, the steering committee of the Eggborough Banks, RBS as provider of a letter of credit to the Eggborough Banks, and our significant trade creditors, Teesside Power Limited, Total Gas & Power Ltd. and Enron Capital & Trade Europe Finance LLC (Teesside Power Limited, Total Gas & Power Ltd. and Enron Capital & Trade Europe Finance LLC are collectively referred to as the Significant Creditors).

On February 14, 2003, we announced we had entered into binding standstill agreements with our Bondholders, the Eggborough Banks, RBS, the Significant Creditors and BNFL based upon a non-binding agreement on the principles for the financial restructuring of British Energy plc, referred to as the Proposed Restructuring.

On March 7, 2003, it was announced that the UK Government had agreed to extend the Credit Facility in order to provide financial stability and security while British Energy sought to achieve the restructuring. The extended facility will mature on the earlier of September 30, 2004, or the date on which the restructuring plan becomes effective, and has been reduced from up to £650m to up to £200m.

On March 24, 2003, we announced that the necessary approvals required by that date had been obtained and the standstill agreement had become effective between the Company, British Nuclear Fuels plc, the Eggborough Banks, RBS, Teesside Power Limited and Total Gas & Power Limited. The Enron board approvals had been obtained and that required US Bankruptcy Court approvals were expected to be obtained and the the standstill was expected to become binding on Enron Capital & Trade Europe Finance LLC by May 14, 2003.

On May 16, 2003, we announced that we had exchanged the last of the suite of contracts covering front-end and back-end fuel services, required to give effect to the non-binding heads of terms entered into with BNFL on November 28, 2002.

The front-end contracts became effective on April 1, 2003, but may be terminated if the proposed restructuring is not completed. The back-end contracts are conditional on completion of the restructuring but under the terms of the standstill agreement announced on February 14, 2003, pending formal implementation of the new back-end contracts, payments from British Energy to BNFL

will be made as if the new back-end contracts had become effective on April 1, 2003. These arrangements reflect the heads of terms announced on November 28, 2002.

We also announced that new contracts had been entered into by British Energy for the sale of all of our enriched and natural uranium stocks to BNFL and their on-going supply and procurement by BNFL.

Further to the announcement of May 16, 2003, on July 9, 2003, we announced that we had completed the sale of the majority of our remaining uranics stocks to BNFL for a cash consideration of £7.8 million.

We do not currently anticipate that our material day-to-day operations, in particular electricity generation and the payment of suppliers and employees, will be disrupted by the restructuring process or affected by the Proposed Restructuring.

On August 28, 2003, the Board of British Energy was notified by the New York Stock Exchange that British Energy did not at that time comply with the NYSE’s continued listing standard relating to minimum market capitalisation and shareholders’ equity. The NYSE requires that the average global market capitalisation of a listed company during any 30 day consecutive trading period shall not fall below $50 million and that the total shareholders’ equity shall not be below $50 million. In the 30 day consecutive trading period ended August 8, 2003, British Energy’s average global market capitalisation was $49.2 million.

We are currently in discussions with the NYSE with respect to our ability to meet the minimum market capitalisation criteria and we are reviewing the options available to the Company going forward. See “Item 3. Risk Factors – Risks Related to our Business – We might not, in the future, comply with the minimum listing criteria of the New York Stock Exchange Inc., and we may, therefore, lose our listing on the New York Stock Exchange.”

On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy Nuclear Mid-Atlantic LLC, a wholly-owned subsidiary of FPL Group for approximately US$277 million. See “Item 4 – Information on the Company – Proposed Restructuring – The sale of Bruce Power and AmerGen.”

Proposed Restructuring

The Proposed Restructuring is comprised of the following principal elements:

•

New Bonds and New Equity. We will issue New Bonds, with an aggregate principal amount of up to £275 million, referred to as the New Bonds, together with substantially all of the ordinary shares of the restructured British Energy Group, referred to as the New Equity, to our Bondholders, the Eggborough Banks, RBS, and the Significant Creditors, in exchange for the extinguishment of certain existing obligations owed to them;

•

Eggborough CTA. We expect to enter into an agreement with the Eggborough Banks, for a new capacity and tolling agreement, or CTA, under which payments will be made as if they had been issued a further £150 million of our New Bonds;

•

The Nuclear Liabilities Fund. The existing Decommissioning Fund will be enlarged into the NLF to address our uncontracted nuclear liabilities and decommissioning costs. In addition to periodic contributions to the NLF, we will make an initial contribution of up to £275 million of New Bonds to the NLF making a total issue of no more than £550m of New Bonds. We will also contribute 65% (subject to adjustment) of our consolidated net annual cash flow after tax,

financing costs and the funding of cash reserves. Under the proposals the UK Government will assume responsibility for the liabilities associated with historic spent fuel, as well as for uncontracted nuclear liabilities and decommissioning costs of our nuclear power stations, to the extent such liabilities and costs are not otherwise met by the NLF;

•

New BNFL Contracts. We have entered into new contracts with BNFL intended to vary the agreements under which BNFL currently provides front- and back-end fuel related services to our AGR stations. We announced on May 16, 2003, that we had exchanged contracts covering front-end and back-end fuel services with BNFL. See “Item 4. Proposed Restructuring – The BNFL Contracts”; and

•

Sale of Bruce Power and AmerGen. We were required to sell our interests in AmerGen in the United States and Bruce Power in Canada. On February 14, 2003, we announced the completion of the sale of our interest in Bruce Power LP. On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen. See “Item 4. Proposed Restructuring – The Sale of Bruce Power and AmerGen”.

New Bonds and New Equity

The Proposed Restructuring involves the Bondholders, the Eggborough Banks, RBS and the Significant Creditors compromising their claims against us in exchange for the New Bonds and New Equity. The Proposed Restructuring contemplates that the Bondholders and RBS will compromise their claims through a “scheme of arrangement” under the UK Companies Act 1985. A scheme of arrangement is a procedure under UK law through which a company may enter into a voluntary compromise or arrangement with one or more classes of its creditors to effect a restructuring of its financial obligations. To become effective, a scheme of arrangement must be approved by 75% of the relevant creditors. The scheme of arrangement must then receive the sanction of the appropriate UK court. See “Item 3. Risk Factors – Risks Associated with our Restructuring – The proposed scheme of Arrangement requires the approval of the relevant UK court; without such approval, our proposed restructuring will not be able to proceed.”

Under the Proposed Restructuring, the amounts of the unsecured claims of each of the Bondholders, RBS and the Significant Creditors, or the claim amounts, are as follows:

Creditor	Claim Amount
Bondholders	£	408 million
RBS	£	37.5 million
The Significant Creditors:
Teesside Power Limited	£	159 million
Total Gas & Power Limited	£	85 million
Enron Capital & Trade Europe Finance LLC (an affiliate of Enron Corp.)	£	72 million

The following table summarizes the allocation of New Bonds and New Equity to the Bondholders, RBS, the Significant Creditors and the Eggborough Banks, as agreed in principle under the Proposed Restructuring:

Creditors	New Bonds	Proportion of New Equity issued to Creditors
	(£ in millions)
Bondholders	154.1	52.3	%
RBS	14.2	4.8	%
The Significant Creditors:
Teesside Power Limited	43.5	14.4	%
Total Gas & Power Limited	23.3	7.7	%
Enron Capital & Trade Europe Finance LLC (an affiliate of Enron Corp.)	20.0	6.8	%
Eggborough Banks	20.0	14.0	%

Total	275.0	100	%

⁽¹⁾

We expect that our current shareholders will receive only a very small fraction of the New Equity, if any. See “Item 3. Risk Factors – Risks Associated with our Restructuring – If we complete the restructuring, our shareholders will suffer a very significant dilution of their interests in British Energy plc.”

The Eggborough Banks

The Eggborough Banks have security over our Eggborough coal-fired power station and the assets of Eggborough Power Limited, our subsidiary that owns the Eggborough power station. Under the Proposed Restructuring, the Eggborough Banks will receive £20 million of New Bonds and 14% of the New Equity in respect of their unsecured claims. In addition, we will enter into a new capacity and tolling agreement with the Eggborough Banks, referred to as the CTA, under which we will make payments to the Eggborough Banks as if we had issued to them a further £150 million of New Bonds.

Decommissioning Fund and the NLF

The Proposed Restructuring provides that the Decommissioning Fund will be enlarged into a new Nuclear Liabilities Fund, or the NLF, to address our uncontracted back-end liabilities and the costs of decommissioning. We will contribute to the NLF:

•

£275 million of New Bonds;

•

fixed decommissioning contributions of £20 million per annum (indexed to the UK Retail Price Index (RPI)) but tapering off as our nuclear power stations close;

•

£150,000 (indexed to RPI) for every tonne of uranium loaded into Sizewell B our Pressurized Water Reactor nuclear power station, referred to as a PWR, after completion of the Proposed Restructuring; and

•

payments amounting (initially and subject to adjustment) to 65% of our consolidated annual cash flow net of tax, financing costs, cash reserves and a forecast expenditure reserve. The initial maximum cash reserve will be £490 million plus the amount by which our cash used as collateral exceeds £200 million.

Under the Proposed Restructuring the UK Government will meet the costs of historic spent fuel liabilities and will assume responsibility for uncontracted liabilities and decommissioning costs of our nuclear power stations to the extent that the accrued value of the NLF is insufficient to meet those costs and liabilities as they fall due.

The BNFL Contracts

On May 16, 2003, we announced that we had exchanged contracts covering front-end and back-end fuel services, required to give effect to the Proposed Restructuring. The front-end contracts became effective on April 1, 2003, but, with the exception of the new arrangements for the supply of uranics, may be terminated if, amongst other things, the Proposed Restructuring is not completed. The back-end contracts are conditional on, amongst other things, completion of the restructuring. However, under the terms of the standstill agreements (discussed below), pending formal implementation of the new back-end contracts, our payments to BNFL will be made as if the new back-end contracts had become effective on April 1, 2003.

At the same time, we announced that we had entered into new contracts to sell all of our enriched and natural uranium stocks to BNFL and for BNFL to procure and supply uranics stocks to British Energy. Under the new lifetime arrangements, which are terminable after an initial period of seven years, BNFL will supply the uranics required for our AGR stations in England and enriched uranium for PWR fuel fabrication. BNFL will continue to supply uranics for our AGR stations in Scotland under existing arrangements until 2006, when similar arrangements to those applicable in England will take effect.

The Sale of Bruce Power and AmerGen

Bruce Power

On February 14, 2003, we completed the sale of our entire 82.4% interest in Bruce Power and 50% interest in Huron Wind to a consortium made up of Cameco Corporation, BPC Generation Infrastructure Trust and TransCanada PipeLines Limited. As part of these arrangements, 2.6% of our interest in Bruce Power was transferred to the two unions representing employees at Bruce Power.

At completion we received initial consideration of C$627 million (£250 million) after minor closing adjustments and a payment of C$51 million (£20 million) in recognition of the capital contribution paid by us to Bruce Power on December 30, 2002. On April 28, 2003, we received a further C$20 million (£8.7 million), which had been retained on completion of the sale of Bruce Power for the possible price adjustment relating to pensions following confirmation that no such adjustment was required. A further C$120 million of deferred consideration remains outstanding, comprised of:

•

C$100 million, contingent on the restart of the two Bruce A units; plus

•

C$20 million, retained to cover any successful claims in respect of representations and warranties given by us in the agreement to dispose of Bruce Power until any claims raised against us or certain of our subsidiaries within two years from the date of closing are resolved.

The deferred amount of approximately C$100 million is contingent upon the successful restart of two of the Bruce A reactors. The master purchase agreement provided that if the restart of these two reactors were to be delayed beyond June 15, 2003 and August 1, 2003, respectively, the consideration of C$50 million per reactor will be reduced on a sliding scale falling to zero after nine months. Bruce Power did not succeed in restarting the two reactors by the dates specified, consequently, while work continues to restart the reactors as soon as possible, we cannot assure you that the amount of deferred compensation we receive will not be further reduced owing to any further delays in restarting the remaining reactors. See “Item 3. Key Information – Risk Factors. A substantial portion of the further proceeds we expect to receive as a result of the Bruce Power disposal are contingent upon the occurrence of certain events”.

In addition, C$80m was retained to cover the estimated outstanding tax liabilities of BECL and its subsidiaries. We subsequently received an interim refund of some C$3 million which may be subject to

further adjustment and we are continuing to pursue the refund of further amounts with the purchasers of our interest in Bruce Power and the Canadian tax authorities.

AmerGen

In September 2002, British Energy and Exelon announced their intention to sell AmerGen but, as we subsequently announced on March 7, 2003, these plans did not attract suitable offers. Independently from Exelon, we sought to realize the value of our investment.

On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy Nuclear Mid-Atlantic LLC, FPL Energy, a wholly-owned subsidiary of FPL Group for approximately US$277 million. The disposal of British Energy’s interest in AmerGen will be effected through the sale of its subsidiary, British Energy US Holdings Inc., to an affiliate of FPL Energy. The proposed sale of our interest in AmerGen is subject to a right of first refusal, or ROFR, held by Exelon pursuant to the terms of the limited liability company agreement, the LLC Agreement, between Exelon and us with respect to AmerGen. Pursuant to the terms of the LLC Agreement, Exelon has the right to purchase our interest in AmerGen upon the same terms offered to a third party, by giving notice of its intention to do so within 30 days of receiving notice of FPL Energy’s agreement to purchase our interest in AmerGen. Exelon’s ROFR will terminate on October 11, 2003. In certain circumstances, break fees of up to US$8.295 million will be payable by us to FPL Energy in the event that the transaction with FPL Energy is not completed including as a result of Exelon exercising its ROFR to acquire AmerGen. Notwithstanding Exelon’s ROFR the sale of our interest in AmerGen will also require various regulatory approvals and authorisations in the United States.

Under the LLC Agreement, in lieu of exercising its ROFR, Exelon has the right to elect to participate in the sale of our interest in AmerGen (the “Tag-along Right”) on the same timetable as the ROFR. If Exelon were to exercise its Tag-along Right, the consideration offered by FPL Energy for a 50% interest in AmerGen would be applied pro rata to the interests of British Energy and Exelon, leaving each with a 25% interest in AmerGen.

The Credit Facility

On September 9, 2002 the UK Government granted us a credit facility in an aggregate principal amount of up to £410 million to meet our immediate requirements for working capital and cash collateral to support our trading contracts in the United Kingdom and North America and certain procurement contracts. Subsequently, on September 26, 2002, the UK Government agreed to provide a revised facility for an amount up to £650 million.

Although the proceeds of the disposal of Bruce Power and standstill agreements were used to repay sums borrowed under the Credit Facility, the UK Government announced on March 7, 2003 that it had agreed to extend the maturity of the Credit Facility to the earlier of September 30, 2004 or the date on which the Proposed Restructuring becomes effective. The aggregate principal amount available under the Credit Facility was reduced from £650 million to £200 million. The UK Government is entitled to require immediate repayment of the Credit Facility if, in the opinion of the UK Secretary of State the restructuring cannot be implemented in the manner or timescale envisaged. See “Item 3. Key Information – Risk Factors. The continued financial support from the UK Government is subject to the approval of the UK Secretary of State for Trade and Industry.” As at September 19, 2003 we had drawn down £20.8 million, principally to meet trading and other cash collateral requirements.

Standstill Agreements

On February 14, 2003, we announced that we had entered into binding standstill agreements, referred to as the Standstill Agreements, with the Bondholders, the Eggborough Banks, RBS, the

Significant Creditors and BNFL. The Standstill Agreements were subsequently approved by a meeting of all holders of our sterling denominated bonds on March 24, 2003, at which time resolutions approving the standstill were passed, authorizing amendments to the trust deed constituting the bonds rendering the standstill binding on all bondholders. The Enron US bankruptcy court approvals were obtained and the standstill agreement became binding on Enron Capital & Trade Europe Finance LLC on May 8, 2003.

Under the terms of the Standstill Agreements, the Bondholders, the Eggborough Banks, RBS, the Significant Creditors and BNFL each agreed with us that they would not take any steps to initiate any administration proceedings or demand or accelerate any amounts due and payable by us during the period commencing on February 14, 2003 and ending on the earliest of (i) September 30, 2004, (ii) a termination event, or (iii) the completion of the Proposed Restructuring.

Under the Standstill Agreements, the Significant Creditors and RBS are paid interest, but not principal, in respect of any claims against the British Energy Group. Interest continues to be paid to Bondholders and the Eggborough Banks in accordance with existing arrangements, except that following the payment of the normal annual coupon to Bondholders on March 25, 2003, subsequent interest payments will be made on a semi-annual rather than an annual basis. Interest on outstanding principal amounts was paid to the Significant Creditors and RBS on March 25, 2003 and will be paid semi-annually thereafter based on the claim amounts. In the case of RBS, interest will be paid on the present value of the relevant claim amounts. In accordance with the terms of the Standstill Agreements, we amended our existing power purchase agreement with Teesside Power Limited so that during the standstill period, we will continue to purchase power from them at fixed prices set at levels based on the current forward curve for electricity. On completion of the Proposed Restructuring, this power purchase agreement with Teesside Power Limited will terminate.

The Standstill Agreements contain certain covenants, including covenants that prohibit us from making any acquisition or disposal in an amount greater than £5 million (other than the disposal of Bruce Power and AmerGen) without the unanimous consent of our creditors who are party to the Standstill Agreements. Furthermore, we may not issue equity or pay any dividends. The Standstill Agreements may be terminated following the occurrence of a termination event. The termination events include (i) certain insolvency events affecting British Energy plc, British Energy Generation Limited, British Energy Generation (UK) Limited, British Energy Power and Energy Trading Limited or Eggborough Power Limited, (ii) acceleration of the Credit Facility, (iii) the required approvals under the Standstill Agreements not being obtained within the timescales envisaged, (iv) any of the British Energy companies failing to discharge certain continuing obligations and (v) definitive documentation having not been executed by September 30, 2003.

Operations in the United Kingdom

Approximately 72% of our turnover during the year ended March 31, 2003 was derived from the generation and sale of electricity from our eight UK nuclear power stations and our coal-fired power station at Eggborough. Seven of our nuclear power stations, Dungeness B, Hartlepool, Heysham 1, Heysham 2, Hinkley Point B, Hunterston B and Torness, are each powered by two AGRs. The eighth nuclear power station, Sizewell B, is powered by a single Pressurized Water Reactor, or PWR. Six of our UK nuclear power stations (including Sizewell B) and our coal-fired power station are located in England. Our other two UK nuclear power stations are located in Scotland.

Advanced Gas-cooled Reactors

In the year ended March 31, 2003, total AGR output was 54.6 TWh, a decrease of 6.5% as compared with the previous year and the average load factor of our AGRs was 74.3%, a decrease of

5.2% as compared with the previous year. The average load factor represents the amount of electricity produced by a power station expressed as a percentage of the total electricity it could have produced if operating at full capacity for the same period of time. For example, if a power station could have produced a total of 100 MWh operating at full capacity over the relevant period and actually produced 50 MWh over the relevant period, its average load factor would be 50%. The highest achievable load factor for an AGR power station ranges between 97% (for an AGR using on-load refueling with no statutory outages during the relevant period) and approximately 85% (for an AGR that does not utilize on-load refueling and has a statutory outage during the relevant period).

The performance of our AGR stations, in order of the date in which they entered commercial operation, for the five years to March 31, 2003 is shown below.

	Year ended March 31,
Power Station	2003	2002	2001	2000	1999
	(TWh except average load factor)
Hinkley Point B	8.3	9.0	8.2	7.7	9.6
Hunterston B	8.9	9.9	6.4	8.9	9.2
Dungeness B	5.2	5.2	3.7	2.2	5.1
Heysham 1	7.8	8.1	8.9	8.5	7.8
Hartlepool	9.3	8.8	9.1	9.3	8.3
Torness	5.7	8.3	7.7	10.2	9.5
Heysham 2	9.3	9.0	10.1	6.4	9.3

Total	54.6	58.3	54.1	53.1	58.8

Average load factor⁽¹⁾	74%	79%	74%	72%	80%

⁽¹⁾

The average load factor represents the amount of electricity produced by a power station expressed as a percentage of the total electricity it could have produced if operating at full capacity for the same period of time.

Since the AGRs commenced operation, a number of technical, operational and engineering issues have arisen. We aim to resolve each of these issues by formulating solutions which either eliminate the issue or contain it in a manner sufficient to allow continued safe operation of the affected AGR. Each of these solutions requires the approval of the Nuclear Installations Inspectorate, or NII, for a revised safety case. In May 2002, a fault developed in a gas circulator at one of the reactors at Torness, resulting in plant shutdown. Subsequently, in August 2002, a similar fault also developed in the gas circulator on the other unit at Torness, which also resulted in plant shutdown. Both units had returned to service by December 2002. For further information about the technical risks associated with our operations, see “Item 3. Key Information – Risk Factors – A significant engineering fault or a design flaw at one of our power stations or which is generic to a class of nuclear plants could decrease our revenues and increase our costs”.

Refueling Operations

Improvements in the design and operation of refueling equipment have increased reliability, reducing output losses associated with refueling. In addition, better fuel utilization has reduced the amount of refueling required. In particular, we have developed more efficient fuel management techniques, such as increasing fuel enrichment to increase the output extracted per tonne of fuel loaded, and radial shuffling, which involves moving partially burnt fuel assemblies from the edge of the reactor to the center so that we can extract more of the energy from the fuel.

We have also reduced output losses associated with refueling through on-load refueling (when power stations refuel without shutting down) after extensive programs of work to enhance our AGRs’

refueling equipment. Currently, we conduct low power on-load refueling (refueling at approximately 30% to 40% of reactor power) at four of our power stations, Hinkley Point B, Heysham 2, Hunterston B and Torness. We believe that the further enhancement of AGR refueling equipment necessary to allow on-load refueling at greater than 40% of reactor power would not be cost effective. At Heysham 1 and Hartlepool, we have developed a technique of large batch off-load refueling to minimize the duration of refueling outages. However, we believe that the extensive programs of work necessary to enhance the refueling equipment at these two power stations and at Dungeness B in order to commence on-load refueling would not be cost effective.

The table below sets out the aggregate duration of all outages during which any one of our AGR reactors was shut down as a result of statutory, refueling or other outages during the periods indicated.

	Year ended March 31,
Outages	2003	2002	2001
	(reactor days)⁽²⁾
Statutory	382	183	307
Refueling	106	122	71
Other⁽¹⁾	571	383	578

Duration of all outages	1,059	688	956

⁽¹⁾

Other outages during the year ended March 31, 2003 include outages that arose in connection with failures to gas circulators which resulted in outages of 69 reactor days and 203 reactor days, respectively, on each of the two reactors at Torness. Other outages during the year ended March 31, 2001 include outages that arose in connection with superheater weld cracking at Dungeness B, which resulted in outages of 347 reactor days, on the two reactors. During the year ended March 31, 2001 an unplanned outage arose in connection with boiler tube corrosion at Hunterston B which resulted in an unplanned outage of 156 reactor days. For further discussion of outages, see “– Operations in the United Kingdom – Advanced Gas-cooled Reactors”.

⁽²⁾

A reactor day is any calendar day on which a reactor is shut down. If two reactors at the same station (where applicable) are shut down on the same day, this is recorded as two reactor days.

Statutory Outages. The interval between statutory outages is confirmed by license instrument given by the NII and made pursuant to the site licenses and are as agreed between the licensee for that site and the NII. Currently, each of our AGR reactors must initiate a statutory outage within a three-year period, with the exception of Dungeness B, which is required to initiate a statutory outage within a two-year period. We are currently working towards increasing this to a three-year period. After a statutory outage, the NII must consent to a reactor’s return to operation. We seek to manage the effect of statutory outages on output by timing such statutory outages to occur during periods of lower demand for electricity when prices are lower (generally between the months of March and October). We also seek to reduce the duration of any statutory outages by improving the efficiency with which we conduct the required program of work during a statutory outage and the speed with which we can refuel a reactor. During the year ended March 31, 2003, our completed AGR statutory outages had an average duration of 55 days. Furthermore, statutory outages are limited to one reactor within each AGR power station at any one time.

In 2002, based on recommendations by the World Association of Nuclear Operators, or WANO, we commenced a two year program of plant investment to improve nuclear safety, enhance reliability and raise output at our UK nuclear power stations at an estimated cost of £30 million over that period.

Unplanned Outages. Other outages arise due to emergent and therefore unplanned plant problems that result in the temporary shutdown of generating units.

During year ended March 31, 2003, unplanned outages rose to 571 reactor days as compared to the previous improved performance of 383 reactor days in 2002. The prime causes for this increase

were the extended unplanned outages of 69 and 203 reactor days respectively on each of the two generating units at Torness to inspect and repair faults with the gas circulators.

AGR Station Lifetimes

The primary factor in determining the lifetime of an AGR power station is the ability to support a secure safety case over the operating life of the power station. Although the safe operation of the entire power station is reviewed, a key element in support of the station safety case is the ability to prove the continuing viability of the AGR power station’s graphite moderator cores. A decision to extend the accounting life of an AGR power station is based, in large measure, on these engineering judgments. While we are not required to obtain the consent of the NII to extend the accounting lifetime of a power station, each power station is subject to a NII Periodic Safety Review, or PSR, every ten years.

Our AGR stations all became operational in the period between 1976 and 1988. The table below shows the year in which each reactor at our AGR power stations became fully operational, the AGR station lifetimes we have adopted for accounting purposes, and the expected closure date of each station. These accounting lifetimes reflect our current assessment of potential life limiting technical factors and independent engineering assessments.

Power Station	Date of commencement of operation of reactor	Station accounting lifetime in years	Station accounting closure date
Hinkley Point B Reactor 1 Reactor 2	1976 1976	35	2011
Hunterston B Reactor 1 Reactor 2	1976 1977	35	2011
Dungeness B Reactor 1 Reactor 2	1982 1985	25	2008
Heysham 1 Reactor 1 Reactor 2	1983 1984	30	2014
Hartlepool Reactor 1 Reactor 2	1983 1984	30	2014
Torness Reactor 1 Reactor 2	1988 1988	35	2023
Heysham 2 Reactor 1 Reactor 2	1988 1988	35	2023

Pressurized Water Reactors

Our pressurized water reactor, or PWR, station, Sizewell B, commenced operation in February 1995 and achieved full power generation in June 1995. Since June 1995, Sizewell B has operated at or close to its full commercial load. In the year ended March 31, 2003, Sizewell B achieved an average load factor of 88.4%. PWRs can operate for periods in excess of twelve months without being shut down for refueling and, consequently, the highest achievable average load factor is 100%.

The performance of the Sizewell B PWR power station over the past five years is shown below:

	Year ended March 31,
	2003	2002	2001	2000	1999
	(TWh (except load factor))
Sizewell B
Output	9.2	9.2	8.4	9.1	9.4
Average load factor	88%	89%	81%	87%	90%

Refueling

In contrast to AGRs, PWRs cannot refuel on-load and must be shut down for refueling. Accordingly, we seek to time statutory outages at Sizewell B to coincide with refueling outages.

Outages

Sizewell B has only one reactor. That reactor has a performance capacity comparable to the combined reactor capacity of both reactors at an AGR power station and the impact of each outage is substantially greater than that associated with a single AGR reactor. Consequently, increases in the duration between statutory outages at Sizewell B have a significant effect on its performance. Sizewell B currently operates for a period of up to 18 months between statutory/refueling outages. Sizewell B was shut down for a total of 31 days as a result of the most recent statutory/refueling outage commencing in April 2002. The next statutory outage is scheduled for October 2003.

PWR Station Lifetimes

Sizewell B has an accounting lifetime of 40 years and an assumed closure date of 2035. The operating lifetime of a PWR station is limited principally by the lifetime of the reactor pressure vessel because it would most likely be uneconomical to replace it. The current safety case for Sizewell B assumes a reactor pressure vessel life of 40 years.

UK Coal-Fired Power Station

We acquired the Eggborough coal-fired power station, which is located in North Yorkshire, from National Power in March 2000. The plant consists of four 500 MW generating units. Eggborough is operated at output levels necessary to meet customer demand, rather than simply at baseload levels in the manner of our nuclear stations. Because Eggborough provides a flexible generating capability, it fulfils a variety of functions. Firstly, by maintaining a level of reserve capacity, it provides a means for compensating for unplanned lost output from nuclear units at short notice; secondly, it provides the capability to profile the generation shape of output to better meet the requirements of both wholesale and directly-supplied customers; and thirdly, it provides a flexible capability that is offered to the system operator via the balancing mechanism. We are in the process of fitting two of the four units with flue gas desulphurization equipment, or FGD, at a cost of approximately £70 million, to limit sulphur emissions, by the end of 2004. Eggborough generated 7.1 TWh in the year ended March 31, 2002 and 5.7 TWh in the year ended March 31, 2003.

Under the restructuring proposals, we have agreed in principle with the syndicate of banks which provided project financing for Eggborough to enter into a new Capacity and Tolling Agreement (CTA). For further details see “Item 4. Information on the Company—Restructuring—Standstill Agreements”.

Electricity Sales in the United Kingdom

A key feature of the New Electricity Trading Arrangements, or NETA, is that buyers and sellers agree contracts at bilaterally negotiated prices rather than offer into a mandatory power pool and

receive a single wholesale price. NETA provides a balancing mechanism for the adjustment of demand and supply in real time and the settlement, in half-hourly blocks, of differences between the contractual and physical positions of those buying, selling, generating and consuming electricity. Because our ability to vary the output of our nuclear power stations is limited by design and safety considerations, we seek to actively build a portfolio of contracts with buyers of electricity to approximately match our planned output. These buyers include suppliers, other generators, wholesale electricity traders and large industrial consumers.

Along with other generators, we are effectively required to pay the cost of alternative generation in the event that we are unable to meet our contractual obligations as a result of unplanned outages. We may enter into contracts with other generators to help ensure our ability to meet contractual obligations. Our 2000 MW Eggborough power station adds further flexibility by allowing us to tailor contracts to meet varying customer demand as well as providing back-up in the event of unplanned outages at our nuclear power stations.

One of our most important routes to market is direct sales to large industrial and commercial customers. This direct sales business has increased by 20% in volume terms in the year to March 31, 2003 to 22.5 TWh while continuing to maintain a number one ranking in terms of customer satisfaction, based on data compiled by the Energy Information Centre. This follows an increase of around 60% in volume terms in the year to March 31, 2002. Particular emphasis has been placed on securing renewals and extensions of existing business to reduce exposure to wholesale market prices.

We currently sell all the output from our Scottish nuclear power stations to Scottish Power and Scottish and Southern Energy under the terms of the Nuclear Energy Agreement or NEA. On July 15, 2002, we agreed revised terms to the NEA with both of the other parties. The revised terms subsequently obtained regulatory approval. The revision to the terms of the NEA followed the commencement of legal proceedings by Scottish Power on April 30, 2001 seeking clarification of the legal status of the contract and how price should be determined following the introduction of NETA in England and Wales. Following the introduction of the NETA on March 27, 2001, electricity pool reference prices required to calculate prices under NEA ceased to exist.

Under the revised terms, Scottish Power and Scottish and Southern Energy now purchase electricity from us under arrangements much more closely linked to market prices and terms for base load energy in England and Wales. The amended NEA will continue in operation until the introduction of the proposed British Electricity Transmission and Trading Arrangements, or BETTA or, if earlier, April 1, 2006. Extension of the amended NEA, beyond its original date of April 1, 2005, will require regulatory approval.

Beyond that date, Scottish Power and Scottish and Southern Energy have an option for follow-on contracts up to 2011 at reduced volumes.

Operations in the United States

AmerGen Energy Company LLC, or AmerGen, our 50% owned joint venture with Exelon Generation Company LLC, or Exelon, was established in 1997 to pursue opportunities in the nuclear electricity generation industry in the United States. The United States Nuclear Regulatory Commission, or NRC, which regulates the operation of nuclear power stations in the United States, permits only US companies to hold a license to operate a nuclear power station in the United States. Accordingly, our interest in AmerGen is limited to 50%.

AmerGen owns the Clinton, Oyster Creek and Three Mile Island-1, or TMI-1, nuclear power stations with a total capacity of 2,500 MW. TMI-1 is a PWR while both Clinton and Oyster Creek are Boiling Water Reactors, or BWRs. Operations at AmerGen’s nuclear power stations are integrated with operations at Exelon’s fleet of nuclear power stations. We are entitled to 50% of AmerGen’s profits.

By summer 2002, despite the successful performance of the AmerGen business, British Energy and Exelon concluded that there was limited scope to grow AmerGen due to the changes in the overall market for nuclear plant. In September 2002, British Energy and Exelon announced their intentions to sell AmerGen but, as we announced on March 7, 2003, these plans did not attract suitable offers. Independently from Exelon, we subsequently focused our efforts on realizing the value of our investment as soon as was practicable.

Electricity Sales in the United States

The AmerGen stations have fixed arrangements in place with the former owners of the stations or with Exelon for the sale of all of their output at agreed prices over the currently licensed lives of the stations. As a result, we have limited exposure to market price movements in the United States.

Safety and Environmental Standards

The following is information regarding our safety and environmental performance. For a discussion of the safety and environmental regulatory scheme to which we and our operations are subject, please see “ – Regulation – Safety and the Environment”.

Safe operation is our first priority. We strive to ensure our continued compliance with all health and safety legislation and the continued improvement of safe working conditions for our employees, contractors, visitors and the general public. Operational management are responsible for safety and are supervised by the Safety and Regulation Division. A Board committee, the Safety, Health and Environment Committee, or SHEC, oversees our performance in this area and provides strategic guidance. The SHEC is chaired by an independent director with considerable experience in the nuclear industry and has three independent members. In addition, a Nuclear Safety Committee established pursuant to the requirements of the nuclear site license for each UK nuclear power station advises that power station on matters related to nuclear safety. Each Nuclear Safety Committee comprises station staff and independent members who are not our employees but who have the relevant technical expertise in nuclear safety. We also regularly consult with the NII on matters of nuclear safety.

In the year ended March 31, 2003 we had no events registered level 2 or higher on the 7 point International Nuclear Event Scale, or INES, as all events registered at or below level 1. Level 1 events represent minor operating anomalies with no impact on staff or the general public.

An INES level 2 incident (signficant failure in safety provisions but with sufficient defence in depth remaining to cope with additional failures) occurred at Dungeness B power station on July 11, 2003. The causes of the incident are being addressed and the station returned to service on July 29, 2003.

In January 2000, the NII published a report on its audit of our central technical support functions. The report followed an inspection carried out early in 1999 which focused on central technical and safety support to our eight nuclear power stations. A series of key recommendations identified areas for improvement relating to retention of skills, use of contractors and overall workload. The report also identified a number of good practices. We firmly believe that excellent safety performance is essential

to good operating performance. By the close of financial year 2002/3, we had responded to all recommendations, and the NII confirmed that they considered the vast majority of such issues to be either closed or subject to long-term monitoring.

We exercise strict control over our operations to ensure compliance with environmental regulations. We have also implemented international standards of best practice, as described below. All radioactive waste is subject to strict control and, with the exception of the gaseous and liquid waste which are authorized to be discharged under a variety of environmental licenses, is stored at our power stations prior to disposal in approved facilities.

Last year, five of our plants maintained a level 8, or higher, rating on the ten point International Safety Rating System (ISRS), a widely adopted standard for monitoring industrial safety. Each of our power stations has been externally audited and certified to the ISO 14001 international standard for environmental management systems. All our UK power stations operate to quality systems consistent with the United Kingdom’s BS 5882 (Specification for a Total Quality Assurance Programme for Nuclear Installations) standard. In 1997 Sizewell B was accredited to the European Union’s eco-management and audit scheme, or EMAS. Sizewell B was the first nuclear power station in the world to achieve EMAS accreditation.

The Fuel Cycle

The fuel cycle consists of the front-end fuel cycle, the preparation of fuel before it enters the reactor, and the back-end fuel cycle being the handling, storage, reprocessing and ultimate disposal of spent fuel and waste. With respect to AGRs and PWRs, the front-end fuel cycle consists of procuring uranium in the form of uranium ore concentrate, which is available on the world market, and converting the uranium into uranium hexafluoride, which is itself a tradable commodity available on a spot or long term basis. The back-end fuel cycle consists of the removal, storage, possible reprocessing and the eventual disposal of the spent fuel (fuel which is removed from a reactor) or waste products arising from its reprocessing. Spent fuel elements may be stored for long periods prior to final disposal, or can be reprocessed after a period of at least three years for AGR spent fuel and five years for PWR spent fuel. Reprocessing of spent fuel separates uranium and plutonium from nuclear waste products. Nuclear waste products are categorized by their radioactivity into low level radioactive waste, or LLW, intermediate level radioactive waste or ILW, and high level radioactive waste, or HLW.

Fuel Cycle in the United Kingdom

Fuel cycle costs represent a significant proportion of our operating costs in the United Kingdom. We rely to a significant extent on BNFL in supplying our fuel cycle requirements, and rely on them exclusively for our AGR fuel. As at March 31, 2003, our contracts for front end and back-end fuel cycle services for the AGR stations required payments in the future totaling £5.7 billion (subject to contractual indexation for inflation). The provision by BNFL of front and back-end fuel cycle services is subject to our revised contracts with BNFL. The continued implementation of our revised contracts with BNFL is contingent on the completion of our proposed restructuring. For a detailed summary of the revised contracts with BNFL, see “Item 10. Additional Information – Material Contracts”. Also see “Item 4 – Proposed Restructuring – The BNFL Contracts.”

UK Front-End Fuel Cycle. Up to the fabrication stage, AGRs and PWRs use identical fuel cycle processes. At the fabrication stage, enriched uranium hexafluoride is converted into either AGR or PWR fuel elements. BNFL is currently the sole provider of AGR fuel fabrication services in the world. The up-front costs associated with AGR fuel fabrication services (for which we are the only customer in the world) present significant barriers to new market entrants. Consequently, we depend upon BNFL for AGR fuel fabrication services. Under the existing contracts we have the option to extend the contracts until the closure of our existing power stations. We have revised contracts with BNFL, which are contingent on our implementation of the proposed restructuring and run until the end of the life of both our English and Scottish AGR stations.

A competitive world market exists for PWR fuel fabrication services. Until 1998, we purchased PWR fuel fabrication services from BNFL. In March 1998, following a competitive international tender, we entered into a contract with Siemens AG for three PWR fuel reloads for delivery between 2000 and 2003 with an option for up to a further four reloads. In accordance with the terms of this agreement, as with the previous agreement with BNFL, we must deliver the required quantities of enriched uranium to Siemens and they will return any unused enriched uranium to us. We satisfy our obligation to provide enriched uranium through our normal uranics procurement sources.

UK Back-End Fuel Cycle. In relation to the English AGRs, we entered into a contract with BNFL in 1995 to reprocess the first 3,060 metric tonnes of spent AGR fuel arising from the operation of those power stations until 2005. In 1997, we entered into a further contract with BNFL to manage all remaining spent AGR fuel arising over the lifetime of the English AGRs. This contract provides that BNFL may reprocess or store that AGR spent fuel at its discretion. Our contract with BNFL with respect to the Scottish AGRs, also entered into in 1995, provides for the reprocessing of the first 1,698 metric tonnes and storage of all remaining spent AGR fuel arising from the operation of those power stations over their lifetime. In 1997, we entered into a contract with BNFL to store reprocessing derivatives (primarily plutonium, uranium and HLW) until 2086 and any ILW to which we retain title until at least 2020. We either incinerate our LLW on site or, where appropriate, compact and send it with any ash from incineration to BNFL’s disposal facility at Drigg in Cumbria. BNFL’s charges for reprocessing and spent fuel management services are based on an annual fixed price (subject to indexation for inflation).

After typically three to six months’ storage in cooling ponds at AGR stations, we send spent AGR fuel in flasks to BNFL’s Sellafield facility by rail. The rail transport is provided under contract by Direct Rail Services Limited, a wholly owned subsidiary of BNFL. Road transport is used between the power stations and the railheads where necessary. The costs associated with the transport of spent fuel by Direct Rail Services Limited are included within the terms of our contracts with BNFL for reprocessing and spent fuel management services over the lifetime of our AGRs. Although the specific transportation costs have not been reduced, we believe that the transfer of this contract to BNFL will result in increased operational efficiency. Spent PWR fuel is stored at Sizewell B pending final disposal. Our storage facilities at Sizewell B can accommodate approximately 30 years of spent PWR fuel, subject to obtaining satisfactory consents from the NII.

Our revised back-end fuel contracts with BNFL are conditional on, amongst other things, completion of the restructuring. However, pending formal implementation of the new back-end contracts, our payments to BNFL will be made as if these new back-end contracts had become effective on April 1, 2003.

UK Long-Term Waste Disposal. We currently retain ultimate responsibility for all AGR spent fuel that has not been reprocessed as well as all uranium, plutonium, ILW and HLW stored by BNFL. We, along with other UK nuclear entities, established United Kingdom Nirex Limited, or Nirex, to pursue the development of an underground repository for ILW and certain LLW. As at March 31, 2003, we had invested a total of £37 million in Nirex. Although Nirex commenced detailed investigations with a view to the construction of a long term waste repository at Sellafield it was denied planning permission in 1997 and the UK Government announced that it would not pursue further development of the site. Nirex’s activities have been reduced pending selection of an appropriate site for a long term waste repository. However, Nirex remains the expert body in the United Kingdom on ILW disposal and provides advice to the United Kingdom’s nuclear industry on waste repackaging requirements.

In September 2001, the UK Government published a report containing proposals for developing a policy for managing solid radioactive waste in the United Kingdom. The aim was to initiate a national public debate. An outline program to 2007 has been announced, which is expected to culminate in an option being selected.

Subject to successful completion of the Restructuring, responsibility for AGR spent fuel (and other back-end fuel liabilities) in relation to fuel loaded into the reactors prior to the restructuring effective date will transfer to the NLF and HMG as described in “Item 3. Proposed Restructuring – Decommissioning Fund and the NLF.”

On July 16, 2003, the UK Government announced plans for Nirex to be made independent of the UK nuclear industry. This proposal is intended to increase Nirex’s accountability.

Fuel Cycle in the United States

Under the terms of its joint venture agreement, Exelon is responsible for purchasing fuel on behalf of AmerGen. AmerGen does not have responsibility for disposing of spent fuel but pays a levy of US$1 per MWh generated to the US Government to fund its disposal.

Decommissioning in the United Kingdom

Decommissioning of a nuclear power station is the process whereby it is shut down at the end of its operating life, eventually dismantled, and the site made available for other purposes. There are generally three stages in the decommissioning of a nuclear power station. In the United Kingdom these stages are:

(i)

Stage 1—defueling the reactor shortly after station closure and removing the fuel from the power station;

(ii)

Stage 2—dismantling redundant ancillary buildings and making the reactor complex secure and weather proof, following which it is maintained and monitored, usually over long periods (estimated to be up to 135 years after station closure for AGRs and up to 50 years after closure for PWRs); and

(iii)

Stage 3—dismantling the reactor to allow the site to be reused.

The decommissioning of the first of our power stations is not expected to commence before 2008. The estimated cost of decommissioning the stations is based on technical engineering assessments and other detailed studies in light of the current regulatory regime. In accordance with UK GAAP, we provide in full for these costs at the time that a power station is commissioned. This provision is expressed at its current value as of the balance sheet date, discounted by 3% per year to reflect the long time period before the costs occur. As at March 31, 2003 we estimated the total discounted cost of decommissioning our AGR power stations and the PWR power station to be £1.0 billion.

Decommissioning Fund

In connection with our privatization we established the Nuclear Generation Decommissioning Fund Limited, or the Decommissioning Fund, in March 1996. The Decommissioning Fund is owned by the trustees of an independent trust, the Nuclear Trust. The Decommissioning Fund was established to accumulate funds to meet our Stage 2 and Stage 3 decommissioning costs, including on-site waste management. We made an initial endowment of £228 million to the Decommissioning Fund in July 1996. We make quarterly contributions to the Decommissioning Fund, which are subject to an adjustment for inflation. During the year ended March 31, 2003, these contributions totalled £18 million.

The value of the Decommissioning Fund asset in our balance sheet represents these contributions and the income accrued to date based on the estimated actuarially determined long-term rate of return on the Decommissioning Fund and the annual effect of inflation. The estimated actuarially determined long-term rate of return, which has been applied consistently for the last three years, is 3.5% per annum. The rate represents the independent actuaries’ assessment of the long-term return from the Decommissioning Fund that will be earned from the accumulation in the Decommissioning Fund. See also Note 15 to our consolidated financial statements.

On September 25, 2002 the Decommissioning Fund served a default notice relating to the solvency of the Company, British Energy Generation Limited and British Energy Generation (UK) Limited. Unless the default is cured to the satisfaction of the Decommissioning Fund, or waived, the

Decommissioning Fund has the right to require accelerated payment of all of the contributions due to the Decommissioning Fund prior to the next quinquennial review in Autumn 2005. The Decommissioning Fund has agreed not to take enforcement action without further notice while the British Energy Group continues to make progress toward completing its proposed restructuring. If the proposed restructuring is effective, the NLF will replace the Decommissioning Fund. For a detailed description, see “Item 3. Risk Factors – Risks Related to our Business – If the NLF does not become effective, we may be required to make substantial payments to meet the long-term post-closure costs of decommissioning our existing nuclear power stations in the United Kingdom. Separately, and in addition, we may be required to make substantial payments to meet revised projected costs of decommissioning of the AmerGen stations” and “Item 4. Information on the Company – Proposed Restructuring – Decommissioning Fund and the NLF.”

If our proposed restructuring is completed, the Decommissioning Fund will be enlarged into the NLF. As with the Decommissioning Fund, we will make an initial contribution to the NLF of £275 million of New Bonds. In addition we will pay:

•

fixed decommissioning contributions of £20 million per annum (indexed to the UK RPI) but tapering off as our nuclear power stations close;

•

£150,000 (indexed to the UK RPI) for every tonne of uranium loaded into our PWR nuclear power station Sizewell B; and

•

In connection with the establishment of the NLF, the UK Government has agreed to meet the cost of historic spent fuel liabilities and will assume responsibility for uncontracted nuclear liabilities and decommissioning costs of our nuclear power stations to the extent that the accrued value of the NLF is insufficient to meet those liabilities and costs as they fall due.

Principal Subsidiaries

Details of our principal subsidiaries and other holdings of more than 10% are as follows:

Country of

Registration and

operation

Class

Share

Group

Shareholding

Company

shareholding

Principal

Activity

Subsidiary

British Energy Generation (UK) Limited⁽¹⁾⁽³⁾

Ordinary

100

Generation and sale of
electricity

British Energy Generation Limited⁽²⁾⁽⁴⁾

Ordinary

100

—

Generation and sale of
electricity

British Energy Power
and Energy Trading Limited⁽³⁾

Ordinary

100

Energy trading

Eggborough Power Limited

Ordinary

100

—

Generation and sale of
electricity

Lochside Insurance Limited

Guernsey

Ordinary

100

Insurance

British Energy US Holdings Inc⁽⁵⁾

Ordinary

100

—

Holding Company

British Energy Holdings Limited

Canada

Ordinary

100

—

Holding Company

⁽¹⁾

One Special Rights Redeemable Preference Share is held by Her Majesty’s Secretary of State for Scotland.

⁽²⁾

One Special Rights Redeemable Preference Share is held by Her Majesty’s Secretary of State for Trade and Industry.

⁽³⁾

On September 26, 2002, British Energy plc granted a pledge over all of the shares held by it in (amongst others) British Energy Generation (UK) Limited and British Energy Power and Energy Trading Limited in favor of the Secretary of State for Trade and Industry.

⁽⁴⁾

On September 26, 2002, British Energy Generation (UK) Limited granted a mortgage over all of the shares held by it in British Energy Generation Limited in favor of the Secretary of State for Trade and Industry.

⁽⁵⁾

On September 26, 2002, British Energy Investment Limited granted a pledge over all of the shares held by it in British Energy US Holdings Inc in favor of the Secretary of State for Trade and Industry.

Other holdings of more than 10%

AmerGen Energy LLC

Ordinary

—

Generation and
sale of electricity

United Kingdom Nirex Limited

Ordinary

10.8

—

Disposal of
nuclear waste

Property, Plant and Equipment

Our properties consist of power stations, administrative offices and certain other properties, including training facilities, all of which are fully utilized (subject to normal production outages). We own the freehold to each of our eight UK nuclear power stations and one coal fired power station as well as the administrative centers, our corporate headquarters at Peel Park near East Kilbride in Scotland and at Barnwood, near Gloucester in England. In addition, we currently lease offices in London and Slough, near London and in Brussels, Belgium. The nuclear power stations are operated under license and subject to strict regulation (as detailed above and in “Regulation”). We believe that all of our properties are in a condition adequate for their purpose and utilization according to their individual natures and requirements. As previously noted, we are in the process of fitting FGD, units to two of the four units at Eggborough power station. The project is expected to be completed by the end of 2004 and is expected to cost approximately £70 million.

Details of our power stations and offices are set out below:

	Type	Capacity		Location
		(MW)
United Kingdom
Nuclear Power Stations:
Dungeness B	AGR	1120		England
Hartlepool	AGR	1205		England
Heysham 1	AGR	1060		England
Heysham 2	AGR	1340		England
Hinkley Point B	AGR	1270		England
Hunterston B	AGR	1195		Scotland
Sizewell B	PWR	1200		England
Torness	AGR	1210		Scotland
Coal Fired Power Stations:
Eggborough	—	2000		England
Principal Offices:
Peel Park, East Kilbride	—	—		Scotland
Barnwood, Gloucester	—	—		England
Jermyn Street, London	—	—		England
Herschel Street, Slough	—	—		England

United States—AmerGen
50% share in nuclear power stations:
Clinton	BWR	1017	⁽¹⁾	Illinois, United States
Oyster Creek	BWR	627		New Jersey, United States
Three Mile Island—Unit 1	PWR	835		Pennsylvania, United States

⁽¹⁾

Net of station load.

In connection with our privatization in July 1996, we entered into a Property Clawback Deed with the UK Government’s Secretary of State for Trade and Industry. The Property Clawback Deed provides that in the event of the disposal, or an event deemed to be a disposal, of any property in which we had an interest as at March 31, 1996 (other than our power stations), the UK Government is entitled to 50% of any post tax gain realized on the disposal in excess of £400,000. The Property Clawback Deed will cease to have effect from March 31, 2006.

Under the terms of the extended loan facility agreement provided by the UK Government on November 28, 2002, we granted a first ranking security to the Secretary of State for Trade and Industry over each of our UK nuclear stations.

On July 2, 2003, we announced proposals to close our current corporate headquarters at Peel Park in East Kilbride. Under these proposals, certain operational posts will be relocated to our Barnwood office, and our headquarters will be transferred to a new location in Scotland in smaller offices which are yet to be identified. We are currently in the process of consulting with those employees directly affected by these proposals.

Employees

United Kingdom Employees

The average number of employees in the United Kingdom during the year ended March 31, 2003 was 5,054. The average number of employees in the United Kingdom was 5,224 in the year ended March 31, 2001 and 4,920 in the year ended March 31, 2002.

In addition to full time employees, at any one time, we engage a significant number of contract staff. In particular, during outages, resources at the stations are supplemented by a significant number of contract staff who provide maintenance and other specialist services.

The terms and conditions of employment for the majority of our staff are subject to agreements with the following trade unions: Prospect, Amicus AEEU, GMB, UNISON and the Transport and General Workers Union. These agreements, introduced in 1994 cover most full time, part time and temporary employees and include provision for performance related salary progression for some employees. Management believes we have good relations with both employees and its trade unions.

For a breakdown of our employees by category of activity, see Note 7 to our consolidated financial statements.

Competition

We compete in the market for electricity supply with other power stations, including other nuclear power stations, and a number of coal-, oil- and gas-fired power stations. As compared to nuclear power stations, coal-, oil- and gas-fired power stations are able to more easily adjust their output to take advantage of changes in market price, which in some situations may put us at a competitive disadvantage.

Legal Proceedings

We are currently pursuing two separate claims against Siemens that are the subject of an arbitration proceeding that commenced in May 2000. We are seeking to recover losses of approximately £85 million plus interest related to the failure of two turbines at Heysham 2 refurbished by Siemens in 1997 and 1998. Disclosure commenced in October 2002 and the trial is due to commence in December 2003.

We understand that AES and Greenpeace have filed an appeal in the European Court of First Instance seeking judicial review of the European Commission’s approval of the UK Government’s decision to grant rescue aid to us in September 2002.

In March 2003, FLS Miljø a/s, or FLS Miljø, the main contractor for the FGD plant works at Eggborough Power Station issued a notice of default under the contract between them and Eggborough Power Limited, or EPL. This notice of default alleged that EPL was in breach of the provisions of that contract following the announcement of the restructuring proposals on February 14, 2003 primarily, but not exclusively, on the basis that EPL had agreed or would shortly enter into, a composition or voluntary arrangement with its creditors, by virtue of the standstill arrangements and non-binding agreement on the principles of our proposed restructuring agreed on February 14, 2003. EPL obtained a letter of advice from external counsel to the effect that no event of default had occurred under the contract between EPL and FLS Miljø on this basis. On July 25, 2003 FLS Miljø served a further notice of default alleging that EPL was insolvent, and/or that it had entered into a voluntary arrangement with its creditors in breach of the terms of its contract with FLS Miljø.

Other than as described above, we are not aware of any material legal proceedings, other than ordinary routine litigation incidental to our business, to which British Energy or its subsidiaries is a party or of which any of their property is subject. Similarly, we are not aware of any proceedings concerning British Energy or its subsidiaries contemplated by any governmental authority in the United Kingdom, the United States or elsewhere.

Regulation

Our business is subject to extensive regulation by governmental agencies in each of the jurisdictions in which we operate. Regulation that applies specifically to our business generally covers three areas: electricity regulation; nuclear regulation; and regulation of safety and the environment. In the countries where we operate, the United Kingdom and the United States, regulation is carried out and enforced by national regulatory authorities. In the United States, there are various additional layers of regulation at the international, state, regional and/or local level.

We are subject to a varied and complex body of laws and regulations that both public bodies and private parties may seek to enforce.

An overview of the regulatory framework in each of the countries in which we operate is set out below.

Electricity Regulation

These regulations govern the development, ownership and operation of power generation plants and the transactions between producers and consumers of electrical power and related products, such as ancillary services. The degree of energy market regulation in the countries in which we operate generally depends upon the structure of the energy market in that country and the level of private versus state ownership of the energy sector. In the markets in which we operate, there is a well-established regulatory framework.

Electricity Regulation in the United Kingdom

The electricity industry in Great Britain is regulated by the Electricity Act 1989, or the Electricity Act, as amended by the Utilities Act 2000. The primary responsibility for regulating the electricity industry rests with the Gas and Electricity Markets Authority, or GEMA, the members of which are appointed by Her Majesty’s Secretary of State for Trade and Industry. GEMA is responsible for the

enforcement of the licensing regime under the Electricity Act and carries out these functions via the Office of Gas and Electricity Markets, OFGEM. GEMA also has various other responsibilities including the power to refer matters in certain circumstances to the Competition Commission.

Unless covered by an exemption, all electricity generators operating a power station in Great Britain must have a generation license issued by GEMA. We currently hold generation licenses covering our activities throughout Great Britain.

Unless covered by exemption, a supplier of electricity to premises in Great Britain must also be licensed. Restrictions on the customers’ rights to choose their licensed supplier were removed in 1999, resulting in a competitive supply market of approximately 330 TWh per annum. We currently hold a license entitling us to supply all non-domestic customers in Great Britain.

Failure to comply with any of the generation or supply license conditions may subject the licensee to a variety of sanctions, including enforcement orders by GEMA, the imposition of financial penalties, or license revocation if the licensee does not comply with an enforcement order.

Certain aspects of British Energy’s electricity trading activities in Great Britain are regulated by the Financial Services Authority in accordance with the Financial Services and Markets Act 2000.

Electricity Regulation in the United States

AmerGen operates in three states. AmerGen sells power at wholesale and is therefore subject to the jurisdiction of the Federal Energy Regulatory Commission, or the FERC, which regulates the transmission and wholesale sales of electricity in interstate commerce. Because AmerGen is not selling directly in the retail market, it is not subject to rate regulation by the state regulatory bodies in the states in which it operates. As an exempt wholesale generator, AmerGen is prohibited from participating directly in their retail markets.

Nuclear Regulation

Nuclear Regulation in the United Kingdom

Under the Nuclear Installations Act 1965 as amended, or NIA, the licensee of a nuclear site has a duty to secure that no occurrence involving nuclear material and that no ionizing radiation causes personal injury or damage to property other than property of the licensee. The licensee is normally exclusively liable for a breach of this duty irrespective of fault. We hold licenses issued by the Health and Safety Executive, or HSE, for each of our UK nuclear power stations.

Under the NIA the liability of the licensee to pay compensation for a breach of this duty is currently limited to £140 million per occurrence, apart from interest or costs. The NIA requires the licensee to make such provisions, by insurance or other means, as the UK Government may approve, for sufficient funds to be available at all times to ensure that duly established claims against the licensee as licensee of that nuclear site (excluding claims for interest or costs) are satisfied up to £140 million in respect of each of the cover periods specified in the NIA. The Secretary of State may direct the licensee to begin a new cover period in the light of previous occurrences or claims. The NIA implements the United Kingdom’s obligations under the Paris Convention of 1960 (as supplemented by the Brussels Convention of 1963), on third-party liability in the field of nuclear energy. The UK Government participated in discussions with members of the Organisation for Economic Co-operation and Development to update the Paris Convention, primarily to increase the limits of liability of nuclear operators to a minimum of 700 million euros in the light of developments in available insurance capacity. The European Commission gave approval for the Euratom Community to allow member states to sign the protocol amending the Paris Convention in July 2003. The European Commission has set a deadline of 2008 for member states to sign and ratify the amending protocol.

Subject to this, the NIA would be amended thereafter to incorporate any agreed amendments to the Paris Convention.

The NIA also provides that the UK Government shall make available such sums as, when aggregated with the funds required to be available through insurance or other means, may be necessary to ensure that all duly established claims (excluding claims for interest or costs) in respect of any occurrence are satisfied up to the amount (at current exchange rates) of approximately £286 million. A claim for compensation which would not be payable by the licensee because of the limit on its liability to pay compensation, and which is not satisfied out of the sum of approximately £286 million, may, under the NIA, be satisfied by the UK Government to such extent and out of funds provided by such means as Parliament may determine. The proposed revisions to the Paris and Brussels conventions described above, if implemented, would result in an increase in the Government’s liability cap from £286 million to 1.5 billion euros, or as calculated at the September 5, 2003 Noon Buying Rate, £1.0 billion.

The NIA provides for the licensing and inspection of sites which are to be used for the operation of nuclear reactors and certain other nuclear installations and requires that no site may be used for a licensable activity unless a license has been granted by the HSE. The NII, which is part of the HSE, administers the license. The nuclear site license is granted to the corporation in charge of the day to day operations of the installation. It defines the site and installation and has standard conditions attached to it which set out general requirements but do not prescribe how they should be achieved.

The NII inspectors’ powers under the Health and Safety at Work Act extend to industrial safety and to enforcing the nuclear site license by improvement notices, prohibition notices, or in the event of non-compliance with license conditions or other offences, by prosecution. The NII may also direct a licensee to shut down a nuclear reactor. A nuclear power station remains a licensed site throughout the decommissioning process and is subject to the same system of regulation as when it was operational. Nuclear site license conditions include a requirement for statutory outages and periodic shutdown when necessary for the purpose of enabling any examination, inspection, maintenance or testing required by the maintenance schedule approved by the NII.

Our nuclear site licenses were amended in the early 1990s to include a requirement that each of our nuclear power stations carries out a Periodic Safety Review, or PSR. As part of our nuclear site license compliance arrangements, we carry out a PSR at each site once every ten years.

The transport of all radioactive material, both waste and fuel, off-site must comply with the Department of Transport’s requirements under the Radioactive Material (Road Transport) Act 1991, or RMRTA, the HSE’s requirements under the Carriage of Dangerous Goods by Rail Regulations 1994 and the Anti-Terrorism Crime and Security Act 2001. The RMRTA regulates the transport by road of radioactive material. Under this Act, the UK Government may regulate the packaging, labeling, consignment, handling, transport, storage and delivery of radioactive packages. The current regulations require certain consignments to be specifically approved by the Secretary of State for Transport.

Nuclear Regulation in the United States

In the United States, the Nuclear Regulatory Commission, or NRC, regulates the operation of nuclear plants for the period up to the agreed operating life of the stations. The NRC was established by Congress under the Energy Reorganization Act of 1974 to ensure adequate protection of the public health and safety, the common defense and security and the environment, in each case, with respect to the use of nuclear materials in the United States. The funds necessary to enable AmerGen to comply with the NRC’s requirements are guaranteed by its owners, Exelon and British Energy. Along with Exelon, we have provided funding assurances to AmerGen totaling US$200 million, in order to

provide assurance that AmerGen will be able to meet its obligations to the NRC, which include the expenses associated with the ownerships and operation of its nuclear plants. Under the terms of this funding assurance, our 50% share is to be provided in amounts equal to that provided by Exelon, but not to exceed US$100 million.

Under the terms of the proposed disposal of our interest in AmerGen, British Energy will be released from its obligation when the disposal is completed.

Safety and the Environment

Our operations are subject to numerous international, UK and US federal, state, and local environmental, health and safety laws and regulations governing, among other things, the construction, operation and decommissioning of nuclear and coal-fired power stations, discharges to the air, water and land, the use, handling and disposal of radioactive and hazardous substances and wastes, soil and groundwater contamination and public and employee health and safety. As with our competitors, liability risks are inherent in our operations. Requirements under environmental, health and safety regulation can be expected to increase in the future.

We have made significant expenditures to comply with environmental regulations. Significant additional financial reserves, or compliance expenditures could be required in the future due to changes in law, new information on environmental conditions or other events, and those expenditures could have an adverse effect on our operations and our financial condition or results of operations.

With regard to safety, we adopt a common approach to our international nuclear fleet, adopting methodologies of the World Association of Nuclear Operators, or WANO, and the Institute of Nuclear Plant Operators to compare relative plant performance, operationally and in safety terms, and to seek to improve this performance.

Along with many other major companies which operate large industrial sites, we regularly organize exercises as part of an ongoing program under Licence Condition 11 of our nuclear site licenses. This program, involving a wide range of local and national agencies, plays a major part in keeping emergency response plans up to date. Security measures are regulated by the UK Government’s Office for Civil Nuclear Security.

Safety and Environment in the United Kingdom

A nuclear site license is required from the Health and Safety Executive to operate a nuclear power station in the United Kingdom. Licenses for our nuclear power stations in England are held by BEG, and for those in Scotland by BEG(UK). The NII administers the license. Nuclear site licenses define the site and installation and have standard conditions attached to them which set out general requirements but do not prescribe how they should be achieved. In December 2002 BEG applied for nuclear site licenses in respect of the 2 nuclear stations in Scotland currently licensed to BEG(UK). The re-licensing of these 2 stations is expected to be completed in 2004/5 and will result in all our UK nuclear stations being within a single licensed company.

The Radioactive Substances Act, or RSA, governs the disposal of radioactive waste including radioactive discharges. Radioactive gaseous, liquid or solid waste may only be disposed of or moved off the site in accordance with authorizations granted under the RSA. To enable the re-licensing referred to above it is also necessary for BEG to be granted the RSA authorizations in respect of the 2 Scottish stations. Applications for these authorizations have been submitted to the Scottish Environment Protection Agency (SEPA) and are expected to be granted on a similar timescale to the nuclear site licenses.

The UK Environmental Protection Act 1990, or EPA 1990, provides that potentially polluting activities, such as the operation of power plants, require prior authorization. The EPA 1990 also

provides for a waste management licensing regime and imposes certain obligations and duties on companies that produce, handle and dispose of waste.

In England and Wales, the Environment Agency, or EA, regulates nuclear power stations under the RSA. The EA consults with the public, relevant bodies and the Department of Environment, Food and Rural Affairs, or DEFRA, in relation to nuclear sites in England and Wales before granting discharge authorizations. Appeals may be made to the Secretary of State for the Environment against decisions taken by the EA, and the Secretary can also direct the EA to refer applications to him for determination. In Scotland, the Scottish Environment Protection Agency, or SEPA, regulates under the RSA and follows a similar consultation process including consultation with the First Minister of the Scottish Parliament, before granting hazardous and radioactive materials discharge authorizations for nuclear sites in Scotland. The First Minister of the Scottish Parliament has similar powers to the Secretary of State for the Environment in relation to appeals against decisions of the SEPA. We have obtained all necessary consents and authorizations from EA and SEPA for the disposal of radioactive waste and for non-radioactive discharges from our stations.

Authorizations for disposal of radioactive waste require the operator to use best practicable means to reduce discharges of radioactivity. The operator must in any event comply with the authorized discharge limits set by the EA or SEPA.

Nuclear power stations use large volumes of water to condense the steam from the turbines and all our power stations use seawater for this purpose, which is discharged to the sea after use under consents granted either by the EA or SEPA as relevant.

Operators of nuclear power stations must comply with the strict dose limits set out in the Ionizing Radiations Regulations 1999, implementing Euratom Directive 96/29 laying down basic safety standards for the protection of the health of workers and the general public against the dangers arising from ionizing radiation.

Eggborough, our only coal-fired power station, is subject to particularly stringent environmental regulation. Under the EPA 1990, a system of Integrated Pollution Control, or IPC, was introduced in April 1991 for power stations. Under EPA 1990, the EA has authority for enforcing IPC with respect to emissions to the atmosphere in the United Kingdom. Each IPC authorization requires that a power station use the best available techniques not entailing excessive cost to minimize the emission of certain pollutants. The main requirements imposed on Eggborough, our coal-fired power station, are set out in the authorization issued by the EA. This authorization contains the station’s emissions limits for discharges to air and water. With respect to emissions to air, a program agreed with the Environment Agency has been undertaken to cut sulphur oxides, or SOx, nitrogen oxides, or NOx, and particulate emissions from the station. See “Item 4. Information on the Company—Property, Plant and Equipment” regarding FGD to be installed pursuant to EA requirements. Eggborough also operates under two waste management licenses, regulated by the EA. Negotiations are ongoing to transfer the license from the previous holder. Landfills are now regulated by the Landfill Directive and in England by the Landfill (England and Wales) Regulations 2002. In due course, a landfill permit will be required to replace the Waste Management License which may result in different conditions being imposed.

Under the auspices of the United Nations Economic Commission for Europe, or UNECE, protocols regarding reductions in the emissions of sulphur dioxide and nitrogen oxide have been agreed. These are currently implemented in the EU by means of the Large Combustion Plants Directive, which has

been recently amended. The EU has introduced a “Ceilings Directive” which implements the sulphur dioxide and nitrogen oxide targets agreed in the UNECE Gothenburg Protocol. The United Kingdom had introduced legislation implementing these directives. These Directives may affect the operation and emissions of Eggborough. Once implemented and in effect, we may choose to install significant additional pollution control technology at Eggborough, although it is not presently contemplated.

The EU has adopted a Directive on Integrated Pollution Prevention and Control. This Directive is being implemented via the Pollution Prevention and Control Regulations which will bring modifications to the IPC regime into effect, on a staged basis.

Under UK law, a liability can be incurred for environmental contamination or pollution. In respect of pollution or contamination in ground or in certain waters, there are three laws in particular which should be noted: the first is the contaminated land regime (to be found in the EPA 1990 Part IIA); the second is water pollution (to be found in the Water Resources Act 1991); and the third is the general law of nuisance.

Under the contaminated land regime, remediation notices may be served in the event of land being found to be contaminated. The polluter and the person who knowingly permitted contamination to be present or remain will normally be liable but if such persons cannot be found, the owner or occupier of the land will be liable. Accordingly, the site operator could be liable to carry out remediation of any contamination present. Contamination will need remediation where significant harm is being caused or where there is a significant possibility of such harm being caused or where pollution of waters controlled by the legislation is being or is likely to be caused. The contaminated land regime is to be extended to cover radioactive contamination. Generally, in order for harm to be demonstrated, there should normally be a source of pollution, a receptor and a pathway present. A clean-up is generally required to be to “fitness for use” standards. We are continuing our investigations of all our UK sites in compliance with the regulations.

Under the Water Resources Act 1991, the polluter or the person who has knowingly permitted water pollution or the possibility of water pollution may be ordered to carry out or pay for the carrying out of remediation works. Furthermore, causing or knowingly permitting water pollution is generally an offence so it is incumbent on the site occupier to take action where necessary (the waters controlled by the legislation include most of the aquatic environments including rivers, streams and groundwaters).

Proposals which may impose liability for environmental damage (including strict liability, particularly for damage to protected natural areas or biodiversity damage caused by dangerous and potentially dangerous activities) are under consideration by the EU and a Directive is being brought forward.

Safety and Environment in the United States

In the United States the NRC regulates the operation of nuclear plants under an NRC license for the operating life of the stations (initially forty years, with the ability to apply for a twenty year license extension). The NRC also regulates the decommissioning of each nuclear plant until the applicable license is terminated by the NRC. The NRC was established by Congress under the Energy Reorganization Act of 1974 to ensure adequate protection of the public health and safety, the common defense and security and the environment in the use of nuclear materials in the United States. Environmental matters for AmerGen plants are regulated by the United States government, through the US Environmental Protection Agency and other agencies. Local environmental matters are regulated by state and local government entities in the states of Illinois, Pennsylvania and New Jersey.

Certain environmental laws, in particular, the US Comprehensive Environmental Resource and Conservation Act of 1980, impose strict, joint and several liability on current or previous owners or operators of real property for the cost of removal or remediation of hazardous substances. These environmental laws also assess liability on persons who arrange for or transport hazardous substances to be sent to disposal or treatment facilities. Our nuclear power stations have been operated by us and our predecessors for many years. As a result of these and our future operations and potential impact from neighboring facilities, there are contamination and other potential environmental liabilities associated with them.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

You should read the following information together with the Financial Statements and the related notes included in this annual report beginning on page F-1. Certain statements in this section are “forward-looking” statements. You should read “Information Regarding Forward Looking Statements” on page 3, for information about our presentation of forward-looking information in this annual report. The following discussion and analysis is based on the Financial Statements which have been prepared in accordance with UK GAAP. You can find a description of the differences between UK GAAP and US GAAP and reconciliations of (loss)/profit after tax (or net (loss)/income) and deficit on equity shareholders’ funds in Note 37 of the notes to our consolidated financial statements.

Introduction

We have interests in a total of 15 nuclear reactors and one coal-fired plant in the United Kingdom and, through our joint venture AmerGen, 3 nuclear reactors the United States. Our operations in the United Kingdom, which comprise eight nuclear power stations and one coal-fired station, represent the largest part of our business with an aggregate output of 69.5 TWh and turnover of £1,528 million during the year ended March 31, 2003. In the period between April 1, 2002 and the disposal of our interests in Canada on February 14, 2003, our Canadian operations produced output of 19.2 TWh and turnover of £375 million. In the United States, AmerGen operates three nuclear power stations, contributing an operating profit of £43 million during the year ended March 31, 2003.

In general, the operation of nuclear power stations is characterized by high fixed costs and low marginal costs. Fixed costs include costs that are unique to the nuclear power generation industry, including the cost of reprocessing and storage of spent fuel and storage and disposal of nuclear waste, collectively referred to as back-end fuel costs, as well as the costs of defueling plants and decommissioning nuclear power stations upon closure. In the United Kingdom, we are currently responsible for all our back-end fuel costs as well as the cost of defueling and decommissioning. As discussed in “—Critical Accounting Policies—United Kingdom Generally Accepted Accounting Principles—Nuclear Liabilities and Decommissioning”, these costs have a significant impact on our financial condition and results of operations.

Recent Developments

On September 5, 2002, our board of directors announced that it had initiated discussions with the UK Government with a view to seeking immediate financial support to implement a longer-term financial restructuring. The board of directors decided to initiate discussions with the UK Government based on several factors including: (i) its review of our revised forecast for UK nuclear generation for the fiscal year ending March 31, 2003 (which indicated output of approximately 63 TWh as compared with the original target output of 67.5 TWh, due to unplanned outages particularly those at our Torness and Dungeness B nuclear power stations), (ii) the failure of our negotiations with British Nuclear Fuels plc, or BNFL, to reach agreement on the terms of revisals to our fuel contracts our fuel contracts, and (iii) its review of the long-term prospects of the British Energy Group.

On November 28, 2002, we announced that we had concluded a non-binding agreement on the principles for the financial restructuring of British Energy, referred to as the Proposed Restructuring. The Proposed Restructuring had been negotiated among British Energy, the Bondholders, the steering committee of the Eggborough Banks, RBS as provider of a letter of credit to the Eggborough Banks, and our significant trade creditors, including Teesside Power Limited Total Gas & Power Ltd. and Enron Capital & Trade Europe Finance LLC (Teesside Power Limited, Total Gas & Power Ltd. and Enron Capital & Trade Europe Finance LLC are collectively referred to as the Significant Creditors).

We are currently in discussions with the NYSE with respect to our ability to meet the minimum market capitalisation criteria and are reviewing the options available to us going forward. See “Item 5. Risk Factors – Risks Related to our Business – We currently do not and may not, in the future, comply with the minimum listing criteria of the New York Stock Exchange Inc., and we may, therefore, lose our listing on the New York Stock Exchange.”

On September 11, 2003, we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy LLC, a wholly-owned subsidiary of FPL Group for approximately US$277 million. See “Item 4 – Information on the Company – Proposed Restructuring – The sale of Bruce Power and AmerGen.”

Factors Affecting Results of Operations

During each of the periods under review, the three years ended March 31, 2003, our results of operations were significantly impacted by a number of factors and by the recognition of a number of exceptional operating and financing items. Each of these factors and exceptional items is discussed below.

UK Operations

The results of our UK operations are principally affected by changes in plant output, achieved electricity prices, operating costs, and our revalorization charge. The results of our UK operations during the periods under review were also affected by a change in the manner in which we account for turnover and certain operating costs to reflect the new trading arrangements in England and Wales as a result of NETA. Each of these factors is discussed below.

Plant Output

Our net nuclear output was 62.5 TWh for the year ended March 31, 2001 compared to 67.6 TWh for the year ended March 31, 2002 and to 63.8 TWh for the year ended March 31, 2003. Eggborough produced 7.0 TWh during the year ended March 31, 2001, 7.1 TWh during the year ended March 31, 2002 and 5.7 TWh during the year ended March 31, 2003.

Nuclear output is subject to a number of factors, principally the frequency and duration of outages. The nuclear regulatory regime in the United Kingdom requires each nuclear power station to be shut down periodically for maintenance and inspection as a condition of that power station’s nuclear site license, which we refer to as a statutory outage. Certain of our nuclear power stations must be shut down to allow for refueling, which we refer to as a refueling outage. In addition, nuclear power stations must be shut down for planned maintenance, inspection and testing or to address an unplanned technical malfunction or engineering failure, all of which we refer to as other outages. The ability of a nuclear power station to reduce the duration of statutory and refueling outages, and to reduce the duration or eliminate the occurrence of other outages as a result of a technical malfunction or engineering failure, can have a significant positive effect on its operating cash flows and profitability. In recent years, we have sought to reduce the impact of refueling outages through the introduction of low power on-load refueling at four of our seven AGR power stations and scheduling refueling outages to coincide with statutory outages. In addition, we have undertaken extensive programs of work to improve plant performance and reduce both the duration and occurrence of other outages. This program has also allowed us to secure the agreement of the NII to the extension of the period between statutory outages at all of our power stations, with the exception of Dungeness B. Set forth below is the aggregate duration of our statutory, refueling and other outages during the periods shown.

	Year ended March 31,
Outages	2003	2002	2001
	(in reactor days)⁽²⁾
Statutory	382	183	307
Refueling	106	122	71
Other⁽¹⁾	571	383	578

Duration of all outages	1059	688	956

⁽¹⁾

Other outages during the year ended March 31, 2003 include outages that arose in connection with failures to gas circulators which resulted in outages of 69 reactor days and 203 days, respectively, on each of the two reactors at Torness. Other outages during the year ended March 31, 2001 include outages that arose in connection with superheater weld cracking at Dungeness B, which resulted in outages of 347 reactor days on the two reactors. Also, during the year ended March 31, 2001 an unplanned outage arose in connection with boiler tube corrosion at Hunterston B which resulted in an unplanned outage of 156 reactor days. For further discussion of outages, see “Our Business—Operations in the United Kingdom—Advanced Gas-cooled Reactors”.

⁽²⁾

A reactor day is any day on which a reactor is shut down. If two reactors at the same station (where applicable) are shut down on the same day, this is recorded as two reactor days.

Electricity Prices

Our achieved selling price (which is calculated by dividing total wholesale and direct sales by total output during the period) for the year ended March 31, 2001 (before the introduction of NETA (New Electricity Trading Arrangements)) was £22.50/MWh. Our achieved selling price for the years ended March 31, 2002 and 2003, however, reflects the effect of several changes to the manner in which we account for turnover and certain operating costs as a result of the introduction of new trading arrangements brought about by the commencement of NETA. On a comparable basis, adjusted to reflect the trading arrangements in place prior to the commencement of NETA, our achieved selling price for the year ended March 31, 2002 was £20.40/MWh, a decrease of 9%. On the same basis, our achieved selling price for the year ended March 31, 2003 was £18.30/MWh, a further decrease of 10%.

These declines reflect the impact of increased competition in the UK electricity generation market and other factors outside our control, such as gas and coal prices. You should also read “Item 3. Key Information—Risk Factors”. Assuming that our proposed restructuring is completed, our profitability is dependent upon a number of factors over which we have little or no control, including our ability to achieve and maintain lower operating costs per unit.

Operating Costs

We have undertaken a number of initiatives to reduce our operating costs during the periods under review. Our fuel costs reflect not only the cost of our nuclear fuel and the amount of fuel burnt during the period (based on output), but also the efficiency of our fuel utilization (the percentage of nuclear fuel used before it is removed from the reactor). Principally through the introduction of radial reshuffling of fuel in our AGR reactors, we have improved the efficiency of our fuel utilization during the periods under review, resulting in substantial fuel cost savings.

Revalorization

Each fiscal year we recompute our back-end fuel costs and decommissioning costs to reflect the impact of inflation during the year and to remove the effect of one year’s discount to the estimated costs of decommissioning (which is capitalized at the commencement of commercial operation of a nuclear power station and depreciated over the life of the station as the estimated payment date moves a year closer). These two effects combined, known as “revalorization”, are accounted for as part of the financing charge in our income statement. The charge in respect of the revalorization of decommissioning liabilities is partially offset by a credit in respect of the actuarially determined long term rate of return on the decommissioning fund during the year. You should also read “Item 11. Quantitative and Qualitative Disclosures about Market Risk – Financial Instruments and Risk Management – Equity Risk Management” and “Item 4. Information on the Company – Decommissioning in the United Kingdom – Decommissioning Fund” for more information about our decommissioning fund. The amount of the revalorization charge in any one year will be affected, principally, by the rate of inflation in the United Kingdom. Over the last three years the rate of inflation for the twelve months ended March 31 has fluctuated from 2.1% in 2001 to 1.7% in 2002 and 3.0% in 2003. Although these fluctuations are relatively modest in absolute terms, they have had a significant impact on our revalorization charges due to the magnitude of the long-term nuclear liabilities. In general, a 1% change in the retail price index results in a £35 million change to our revalorization charges.

Canadian Operations

On May 12, 2001, our 82.4% owned Canadian subsidiary, Bruce Power, leased the two nuclear power stations at the Bruce nuclear site in Canada from OPG. The initial term of the lease was until 2018, and we had an option to extend the lease for up to a further 25 years. In connection with the signing of the lease, Bruce Power paid OPG C$367 million (£168 million) in May 2001 and undertook to make a further payment of C$225 million (£104 million). This amount was payable in two equal installments in February 2005 and February 2007 and bore interest at 10.5%.

Our financial difficulties have resulted in dramatic changes for our interests in North America. As a key element of our proposed restructuring we sold our interest in Bruce Power.

The terms of the disposal of Bruce Power were negotiated in very difficult circumstances. At an EGM on February 10, 2003, our shareholders approved the disposal, which was completed on February 14, 2003. The purchaser of our interest was a consortium consisting of Cameco Corporation (an existing partner in Bruce Power), BPC Generation Infrastructure and TransCanada Pipelines Limited. The Power

Workers’ Union and The Society of Energy Professionals also acquired a further combined 2.6% interest to add to their existing 2.6% interest.

At completion of the disposal, we received initial consideration of C$627 million (£250 million) after minor closing adjustments, and a payment of C$51 million (£20 million) in recognition of earlier capital contributions paid by the Company to Bruce Power.

Since the year-end, we have received a further C$20 million that had been held in an escrow account following closing in respect of a potential pension fund adjustment. The cash received to date represents a loss on disposal of £35 million. However, in addition, British Energy expected to receive further proceeds up to:

•

C$100 million, contingent on the restart of two of the reactors at Bruce A. If the restart of the two reactors was delayed beyond June 15 and August 1 respectively, the consideration of C$50 million per reactor reduces on a sliding scale falling to zero after 9 months delay and amounts not paid to British Energy are paid instead to the Province of Ontario. To date, Bruce Power has not succeeded in restarting the two reactors at Bruce A, see note 36 to our consolidated financial statements.

•

C$20 million, which will be held in an escrow account to cover claims made up to February 2005 in respect of representations and warranties.

In addition, C$80 million was held in an escrow account to cover the estimated outstanding tax liabilities of the Bruce Power group. In the event that the sums held back to satisfy the tax liability are insufficient, British Energy would be required to repay the amount of such excess to the purchasing consortium. Conversely, British Energy will be refunded any balance remaining after settlement of the tax liability. We have subsequently received interim refunds of some C$3 million from this account which remain subject to further adjustment. British Energy is continuing to pursue the refund of further amounts with the buying consortium and the Canadian tax authorities.

In the period from May 12, 2001 to March 31, 2002, Bruce Power generated 20.5 TWh and made a profit contribution before minorities of £52 million. In the period of April 1, 2002 to February 14, 2003, Bruce Power generated 19.2 TWh and made an operating profit contribution before minority interest of £97 million.

Exceptional Operating and Financing Items

During the three years ended March 31, 2003, our financial results have been significantly impacted by a number of exceptional operating and financing items.

The table below summarizes the impact of exceptional operating and financing items (before tax) under UK GAAP for each of the three years ended March 31, 2003.

	Year ended March 31,
	2003		2002		2001
	(in millions of pounds)
Write-down of fixed asset carrying values	(3,738	)	(300	)	—
Write-down of UK decommissioning fund	(124	)	(27	)	—
Write-down of AmerGen decommissioning fund	(48	)	—		—
Write-down of own shares held	(102	)	—		—
Provision against slow moving stocks	(57	)	—		—
Provision for interest swaps	(56	)	—		—
Restructuring costs	(35	)	—		—
Loss on sale of investments in Bruce Power and Huron Wind	(35	)	—		—
Write-off of capitalized borrowing costs	(6	)	—		—
Trading contracts	(2	)	(209	)	—
Release of Nuclear Energy Agreement provision	41		—		—

Release of pension provision	—		—		52
Favorable adjustments to fuel costs in respect of Heysham l and Hartlepool accounting life extensions	—		—		24

Exceptional costs in respect of shares issued to the British Energy Qualifying Share Trust to meet options granted to employees under the Sharesave Scheme	—		(3	)	(8	)
Increase in power purchase contract provision	—		—		(14	)
Exceptional redundancy costs at AmerGen	—		—		(7	)
Loss on disposal of Swalec	—		—		(5	)
Revalorization credit in respect of Heysham 1 and Hartlepool accounting life extensions	—		—		5
Sale of investment in Humber Power Limited	—		4		—

Total	(4,162	)	(535	)	47

During the periods under review, we recognized net exceptional operating and financial charges of £4,162 million before tax during the year ended March 31, 2003, net exceptional operating and financial charges of £535 million before tax during the year ended March 31, 2002 and net exceptional operating and financial income of £47 million before tax during the year ended March 31, 2001. Exceptional items during the periods under review were comprised of:

•

An exceptional charge of £3,738 million during the year ended March 31, 2003 resulting from the write-down of our fixed assets.

The carrying value of the nuclear stations was calculated by discounting the expected future cash flows from continued use of the assets, having made appropriate assumptions regarding future operating performance. The valuation of Eggborough was based on an assessment of net realizable value.

The electricity price assumptions were a very significant component of the asset value calculation. The Directors considered the market’s views on future prices of wholesale electricity and also the forecasts specifically commissioned for the Company. They considered the potential for rationalization of generation capacity in the UK and the potential effect on the market of changes in Government policy on renewables generation. In determining the price assumptions the Directors also took account of the effect on the market as a result of the dramatic fall in prices over the last two years and took a cautious view on there being a significant recovery in prices. As market prices are outside the Directors’ control actual prices may differ from those forecast.

•

An exceptional charge of £300 million during the year ended March 31, 2002 resulting from the writedown of our investment in the Eggborough coal-fired plant. This writedown arose as a result of lower electricity selling prices in England and Wales than had been anticipated when Eggborough was purchased and our assessment as to the effect of continued over-capacity in the UK electricity market on the value of similar coal-fired power stations.

•

An exceptional charge of £124 million during the year ended March 31, 2003 related to a write-down in the market value of our UK decommissioning fund. An exceptional charge of £27 million during the year ended March 31, 2002 related to a similar writedown in the market value of our UK decommissioning fund. The market value of our UK decommissioning fund, which is partly invested in equity securities, declined in both years relative to its book value, which is based on an actuarially determined growth rate of 3.5% over the life of the fund, as a result of the world-wide decline in prices of equity securities.

•

An exceptional charge of £48 million during the year ended March 31, 2003 related to a similar write-down in the market value of the AmerGen decommissioning fund.

•

An exceptional charge of £102 million in the year ended March 31, 2003 related to the write-down in value of British Energy shares held in trust to cover employee share options. The shares were written down to £2 million to reflect market value, based on market prices of 3.75p and 3.0p for the Company’s Ordinary and ‘A’ shares respectively.

•

An exceptional charge of £57 million during the year ended March 31, 2003 related to a provision for slow-moving and obsolete stocks.

•

An exceptional charge of £56 million during the year ended March 31, 2003 related to interest swap provisions in respect of interest rate swap contracts which are no longer effective as hedges and are no longer required by the Group.

•

An exceptional charge of £35 million during the year ended March 31, 2003 related to advisory and other costs associated with the Company’s proposed restructuring.

•

An exceptional charge of £35 million during the year ended March 31, 2003 related to a loss on disposal of Bruce Power and Huron Wind. The calculation of the loss on disposal incorporates receipt of the C$20 million retention relating to pensions, but does not take into account retentions of C$120 million.

•

An exceptional charge of £6 million during the year ended March 31, 2003 related to borrowings which are now part of the proposed financial restructuring. These costs had been capitalized and were being amortized over the duration of the borrowings.

•

An exceptional charge of £209 million during the year ended March 31, 2002 arising as a result of a provision for three significant out-of-the-money trading contracts due to lower than anticipated electricity prices in the United Kingdom. These contracts had previously been accounted for as a hedge against our electricity output in the United Kingdom. However, since the introduction of NETA, these contracts are no longer accounted for as hedge contracts and, because they are out-of-the-money, they must be provided for as onerous contracts under UK GAAP. A further provision of £2 million was made in the year ended March 31, 2003, when two of these contracts were terminated, thus giving rise to claims for certain amounts which became payable. The amounts reflect the claimed amounts which have been agreed in principle with the three relevant counterparties for the purposes of restructuring. You should read “—Critical Accounting Policies—United Kingdom Generally Accepted Accounting Principles—Onerous Contracts” for more information as to how we account for these contracts.

•

An exceptional credit of £41 million during the year ended March 31, 2003 related to the revised terms for the electricity supply agreement with ScottishPower and Scottish and Southern Energy. Under the terms of the agreement, which has now had regulatory approval,

the Company is in a position to release a balance of £41 million in respect of cash previously received.

•

Exceptional operating costs of £3 million in the year ended March 31, 2002 and £8 million in the year ended March 31, 2001 resulting from the issuance of shares to the British Energy Qualifying Employee Share Trust, or QUEST, to satisfy the exercise of options granted to employees under the Sharesave Scheme between 1999—2000 and 2002—2003. The charge arises as a result of the difference between QUEST’s subscription price (the then prevailing market price per share) and the option exercise prices. The costs were charged over a five-year period ended March 31, 2002.

•

An exceptional credit of £4 million in the year ended March 31, 2002 related to the gain on the sale of our investment in Humber Power Limited. We acquired a 12.5% interest in Humber Power Limited, the operator of a 1,260 MW Combined Cycle gas fired power plant in 1997.

•

An exceptional operating credit of £52 million in the year ended March 31, 2001 relating to the release of a pension provision following the ruling by the House of Lords in favor of National Grid Group in respect of the use of pension scheme surplus to offset the cost of early retirement. Our main pension scheme is, like National Grid’s, a participant in the Electricity Supply Pension Scheme, or ESPS.

•

Adjustments of £24 million in the year ended March 31, 2001 to reflect the extensions to the accounting lives of two power stations, Heysham 1 and Hartlepool. The extension of the accounting lives at these stations resulted in the recognition of an exceptional credit to operating costs reflecting the postponement of nuclear liabilities by the additional years of operation of those power stations as well as a revalorization credit of £5 million during the year ended March 31, 2001.

•

Exceptional operating costs of £14 million during the year ended March 31, 2001 to reflect the change in value of a power purchase contract acquired as part of our acquisition of the Swalec electricity and gas supply business following the fall in electricity selling prices.

•

Exceptional costs of £7 million during the year ended March 31, 2001 reflecting our share of the costs incurred by AmerGen in respect of redundancy costs at its three nuclear power stations, which we recognize as an exceptional item under UK GAAP.

•

An exceptional loss of £5 million during the year ended March 31, 2001 related to the loss on the sale of the Swalec gas and electricity supply business. We acquired Swalec from Hyder plc in February 2000. However, in August 2000 we disposed of the Swalec business after determining it did not meet our strategic requirements.

Results of Operations for the year ended March 31, 2003 compared with the year ended March 31, 2002

Turnover

Turnover in the year ended March 31, 2003 was £1,903 million, a decrease of £146 million compared with turnover of £2,049 million for the year ended March 31, 2002. The principal factors resulting in this decrease are set forth below.

	Changes in turnover
	(in millions of pounds)
Decreased UK turnover
Due to decreased output	(118	)
Due to lower electricity prices	(111	)
Due to exceptional NEA income	41
Increase in Miscellaneous income—mainly due to Torness related insurance receipts	15

Decrease in turnover from continuing activities	(173	)

Increase in Bruce Power turnover	27

Total decrease in turnover	(146	)

Output in the United Kingdom was 69.5 TWh in the year ended March 31, 2003 as compared with 74.7 TWh in the year ended March 31, 2002. Nuclear generation output was 63.8 TWh in the year ended March 31, 2003 compared with 67.6 TWh in the year ended March 31, 2002. Eggborough output reduced from 7.1 TWh to 5.7 TWh in the year ended March 31, 2003. Decreased output from our UK power stations resulted in decreased turnover of £118 million. Our achieved selling price during the year ended March 31, 2003 was £18.30/MWh, a decrease of 10% as compared with the prior year, resulting in a decrease in UK turnover of £111 million. UK turnover increased by £41 million in respect of the exceptional credit relating to the release of the balance that had been held awaiting settlement of our dispute with Scottish Power and Scottish and Southern Energy for the Nuclear Energy Agreement. Miscellaneous income increased by £15 million, mainly due to insurance receipts relating to outages at Torness. The increase in turnover at Bruce Power was mainly due to increased electricity prices, offset to some extent by a reduction in output.

Operating Costs

Operating costs were £5,705 million in the year ended March 31, 2003, an increase of £3,375 million compared with £2,330 million in the year ended March 31, 2002. Excluding the exceptional items, operating costs decreased by £60 million to £1,758 million in the year ended March 31, 2003 from £1,818 million in the year ended March 31, 2002. The following table sets forth the various components of our operating costs for the years ended March 31, 2003 and March 31, 2002.

	Year ended March 31,
	2003	2002
Continuing Activities
Fuel	371	467
Material and services	519	604
Staff costs	227	212
Depreciation	4,011	580

	5,128	1,863

Amounts written off non-operational assets	115	—
Energy supply costs	184	171

	5,427	2,034

Discontinued Activities
Fuel	17	23
Material and services	143	149
Staff costs	111	119
Depreciation	7	5

	278	296

Total operating costs	5,705	2,330

Fuel costs for our continuing UK activities were £371 million in the year ended March 31, 2003 compared with £467 million in the year ended March 31, 2002. The reduction reflects decreased output by our UK power stations, fuel efficiencies and price variances.

Materials and service costs are comprised of operating expenses for our power stations and support functions (such as administrative, engineering and maintenance costs) excluding fuel costs, staff costs and depreciation. Materials and services costs for our continuing UK activities in the year ended March 31, 2003 were £519 million, a decrease of £85 million compared with the year ended March 31, 2002. These figures include exceptional charges in the year ended March 31, 2003 of £57 million in respect of a write down of slow moving stocks, £35 million in respect of restructuring costs and £2 million in respect of additional provisions for onerous trading contracts. They include exceptional charges of £209 million in the year ended March 31, 2002 in respect of provisions for onerous trading contracts. Excluding these exceptional items, materials and services costs for our continuing UK activities increased by £30 million to £425 million in the year ended March 31, 2003 compared with £395 million in the year ended March 31, 2002. This increase was primarily due to the costs associated with a higher number of outages in the year ended March 31, 2003.

Staff costs for our continuing UK activities in the year ended March 31, 2003 were £227 million, an increase of £15 million compared with the year ended March 31, 2002. The main reason for the increase was additional severance costs of £8 million.

Depreciation charges for our continuing UK activities were £4,011 million in the year ended March 31, 2003 compared with £580 million in the year ended March 31, 2002. These figures include exceptional charges associated with the write down of our fixed assets amounting to £3,738 million in the year ended March 31, 2003 and £300 million in the year ended March 31, 2002. Excluding these exceptional charges, the depreciation charges for our continuing UK activities decreased by £7 million to £273 million in the year ended March 31, 2003 compared with £280 million in the year ended March 31, 2002.

Amounts written off non-operational assets in our continuing activities amounted to £115 million in the year ended March 31, 2003 compared to zero in the year ended March 31, 2002. These amounts

consisted of exceptional items relating to the write down of own shares held and an element of a write down of the UK decommissioning fund receivable, both of which were treated as exceptional items.

Energy supply costs in the UK were £184 million in the year ended March 31, 2003 compared with £171 million in the year ended March 31, 2002. The increase primarily reflects the increase of sales through our direct supply business.

Operating costs in our discontinued Canadian activities were £278 million in the year ended March 31, 2003 compared with £296 million in the year ended March 31, 2002. The decrease was partly attributable to reduced fuel costs arising from the reduction in output and partly attributable to operational efficiencies.

Operating Loss

The operating loss in the year ended March 31, 2003 was £3,802 million compared with an operating loss of £281 million in the year ended March 31, 2002. The operating loss of our continuing activities was £3,899 million in the year ended March 31, 2003 compared with an operating loss of £333 million in the year ended March 31, 2002. The operating profit of our discontinued activities was £97 million in the year ended March 31, 2003 compared with an operating profit of £52 million in the year ended March 31, 2002.

Excluding exceptional items, operating profit in the year ended March 31, 2003 was £104 million, compared with an operating profit of £231 million in the year ended March 31, 2002. The operating profit of our continuing activities was £7 million in the year ended March 31, 2003 compared with an operating profit of £179 million in the year ended March 31, 2002. The operating profit of our discontinued activities was £97 million in the year ended March 2003 compared with an operating profit of £52 million in the year ended March 31, 2002.

Share of Operating Profit of Joint Ventures

Our share of the operating profit of AmerGen increased by £6 million to £43 million in the year ended March 31, 2003. The output from the three AmerGen power stations totaled 20.2 TWh in the year ended March 31, 2003, an increase of 1.5 TWh compared with 18.7 TWh in the year ended March 31, 2002.

(Loss)/Profit on Sale of Business

The results for the year ended March 31, 2003 include a loss of £35 million in respect of the disposal of our interests in Bruce Power and Huron Wind. The results for the year ended March 31, 2002 include a profit of £4 million on the disposal of our interests in Humber Power.

Financing Charges

Financing charges, which comprise revalorization charges and net interest expense, were £498 million in the year ended March 31, 2003, an increase of £245 million compared with £253 million in the year ended March 31, 2002. The financing charges for the year ended March 31, 2003 include exceptional items amounting to £159 million in respect of a write down of our decommissioning fund receivables, £56 million in respect of a provision for interest rate swaps and £6 million in respect of a write off of capitalized borrowing costs. Financing charges for the year ended March 31, 2002 consist of a write down of £27 million in respect of the decommissioning fund receivable. Excluding these exceptional items, financing charges increased by £51 million to £277 million in the year ended March 31, 2003 compared with £226 million in the prior year. The increase primarily reflects higher

revalorization as a result of higher UK inflation. Excluding the exceptional items, the revalorization charge was £205 million in the year ended March 31, 2003 compared with £160 million in the prior year. The increase in revalorization reflects the weighted average UK inflation rate of 3.0% in the year ended March 31, 2003 compared with 1.7% in the year ended March 31, 2002.

Taxation

In the year ended March 31, 2002 we adopted FRS19, the UK deferred tax accounting standard, on a discounted basis. The tax credit for the year ended March 31, 2003 was £368 million. Excluding tax relating to exceptional items, the tax charge for the year ended March 31, 2003 was £2 million. The effective tax rate is higher than the standard rate of 30% as a result of overseas profits being taxed at rates in excess of 30%, the impact of items that are non-deductible for tax purposes, such as the write-down of our investment in Eggborough, and the impact of unwinding one year’s discount from our opening deferred tax liability. The tax charge for the year ended March 31, 2003 comprises a deferred tax credit of £396 million, an overseas tax charge of £18 million and £10 million charge in respect of AmerGen. The tax charge for the year ended March 31, 2002 comprised a prior year UK corporation tax credit of £11 million, a deferred tax credit of £8 million, an overseas tax charge of £15 million and £29 million charge in respect of AmerGen.

As of March 31, 2003 there were deferred tax assets of £382 million and deferred tax liabilities of £20m on an undiscounted basis. £262 million of the deferred tax asset relates to tax relief from operating losses carried forward. A further £64 million relates to the expected tax relief associated with accrued decommissioning costs which are expected to be deductible against future taxable income and £56 million relates to accelerated depreciation in excess of capital allowances. The deferred tax liability relates to other short term timing differences.

On a US GAAP basis, the total deferred tax asset, before valuation allowance, of £2,917 million and the total deferred tax liability of £811 million are significantly greater because they are based on the undiscounted amount of decommissioning and uncontracted back-end fuel costs. See note 37 to our consolidated financial statements.

The net discounted deferred tax asset under UK GAAP at March 31, 2003 of £150 million has not been recognized as it is not likely to be realized unless restructuring is effective. Under US GAAP a full valuation allowance has been made against the net deferred tax asset of £2,106 million at March 31, 2003.

Loss on Ordinary Activities

As a result of the factors discussed above, there was a loss on ordinary activities after taxation for the year ended March 31, 2003 of £3,924 million compared with a loss of £518 million in the year ended March 31, 2002. Excluding exceptional items there was a loss of £132 million in the year ended March 31, 2003 compared with a loss of £39 million in the year ended March 31, 2002.

Minority Interests

There was a minority interest in respect of the 17.6% minority shares of the profits of Bruce Power of £17 million in the year ended March 31, 2003 compared with £9 million in the year ended March 31, 2002.

Loss per Share

There was a loss per share of 654.7p per share in the year ended March 31, 2003 compared with a loss per share of 88.5p per share in the year ended March 31, 2002. Excluding the effect of

exceptional items there was a loss per share of 24.8p per share in the year ended March 31, 2003 compared with a loss per share of 8.4p in the previous year.

In view of the Company’s financial situation, no dividend was proposed in respect of the year ended March 31, 2003. On May 14, 2002 the Board of Directors recommended a final dividend of 5.3p per share which brought the total dividend for the year ended March 31, 2002 to 8.0p per share.

Results of Operations for the year ended March 31, 2002 compared with the year ended March 31, 2001

Turnover

Turnover in the year ended March 31, 2002 was £2,049 million, a decrease of £75 million compared with turnover of £2,124 million for the year ended March 31, 2001. A meaningful comparison between turnover during the year ended March 31, 2002 and March 31, 2001 is difficult due to a number of factors:

•

The contribution to turnover during the year ended March 31, 2002 of £348 million in respect of 11 months of operations from Bruce Power; and

•

The contribution to turnover during the year ended March 31, 2001 of £170 million in respect of Swalec during the five months prior to its disposal in August 2000.

Excluding the factors set forth above, turnover in the United Kingdom was £1,701 million, an increase of £34 million. The principal factors resulting in this increase are set forth below:

	Changes in UK turnover
	(in millions of pounds)
Due to increased output	123
Due to new trading arrangements under NETA	49
Due to lower electricity prices	(137	)
Due to lower miscellaneous income	(1	)

Total increase in turnover	34

Output in the United Kingdom was 74.7 TWh in the year ended March 31, 2002 as compared with 70.5 TWh in the year ended March 31, 2001. Nuclear generation output was 67.6 TWh in the year ended March 31, 2002 compared with 63.5 TWh in the year ended March 31, 2001. Eggborough output increased from 7.0 TWh to 7.1 TWh in the year ended March 31, 2002. Increased output from our power stations resulted in increased turnover of £123 million, although this amount was more than offset by a decrease in electricity sales prices. On a comparable basis, adjusted to reflect the trading arrangements in place prior to the commencement of NETA, our achieved selling price during the year ended March 31, 2002 was £20.40/MWh, a decrease of 9% as compared with the prior year, resulting in a decrease in UK turnover of £137 million. As discussed above, following the implementation of NETA, the reported sales price for both direct and wholesale electricity sales reflects the cost of transmission and other distribution costs incurred to deliver our output which added a further £49 million to our reported turnover. Miscellaneous income, which includes sales of ash from Eggborough and certain nuclear services to British Nuclear Fuels plc, or BNFL, declined by £1 million.

Turnover in each of the periods under review includes our view of the price we will achieve for our output in Scotland during the applicable fiscal year. During each fiscal year we also receive additional amounts as a result of adjustments reflecting the actual price achieved in England and Wales during prior years in accordance with the NEA. Accordingly, during the year ended March 31, 2002 we recognized certain additional sales of £41 million with respect to our output in Scotland in previous

years. For more information on this dispute see “Item 4. Information on the Company – Operations in the United Kingdom – Electricity Sales in the United Kingdom.

Operating Costs

Operating costs were £2,330 million in the year ended March 31, 2002, an increase of £486 million, or 26%, compared with £1,844 million in the year ended March 31, 2001. Excluding the operating costs for Bruce Power of £306 million in the year ended March 31, 2002 and Swalec of £174 million in the year ended March 31, 2001, operating costs were £354 million higher at £2,024 million for the year ended March 31, 2002 compared with £1,670 million for the year ended March 31, 2001. Excluding the exceptional items, operating costs decreased by £80 million, or 4%, to £1,818 million in the year ended March 31, 2002 from £1,898 million in the year ended March 31, 2001.

The following table sets forth the various components of our operating costs for the years ended March 31, 2002 and March 31, 2001:

	Year ended March 31,
	2002	2001	increase/ (decrease)
	(in millions of pounds)
Fuel costs	490	401	89
Materials and services costs	753	493	260
Staff costs	331	166	165
Depreciation charges	585	277	308
Energy supply costs	171	507	(336	)

Total operating costs	2,330	1,844	486

Fuel costs were £490 million in the year ended March 31, 2002 compared with £401 million in the year ended March 31, 2001. Excluding fuel costs associated with Bruce Power and an exceptional credit related to the extension of accounting lives during the year ended March 31, 2001, fuel costs increased by £42 million, or 10%, to £467 million. This increase reflects increased output by our UK nuclear power stations and higher fuel purchase prices.

Material and service costs are comprised of operating expenses for our power stations and support functions (such as administrative, engineering and maintenance costs) excluding fuel costs, staff costs, and depreciation. Materials and services costs in the year ended March 31, 2002 were £753 million, an increase of £260 million compared with the year ended March 31, 2001. Excluding costs relating to Bruce Power and Swalec and an exceptional charge of £209 million in respect of out-of-the-market trading contracts, materials and services costs have decreased by £81 million to £385 million in the year ended March 31, 2002 compared with £466 million in the year ended March 31, 2001. This decrease reflects reduced expenditure at Dungeness following completion of an unplanned outage during the year ended March 31, 2001 and the elimination of certain energy supply costs associated with repurchases of works power as a result of our new trading arrangements under NETA.

Staff costs in the year ended March 31, 2002 were £331 million, an increase of £165 million as compared with £166 million in the year ended March 31, 2001. Excluding costs relating to Bruce Power and Swalec, an exceptional charge related to QUEST and an exceptional credit related to the release of a provision following the House of Lords ruling in connection with the ESPS, staff costs in the year ended March 31, 2002 were £209 million, up £2 million compared with costs of £207 million in the previous year.

Depreciation charges were £585 million in the year ended March 31, 2002 compared with £277 million in the year ended March 31, 2001. Excluding depreciation charges relating to Bruce Power and

Swalec and the exceptional charge associated with the writedown of Eggborough, the charge for depreciation was £280 million in the year ended March 31, 2002, an increase of £7 million compared with £273 million in the year ended March 31, 2001.

Energy supply costs were £171 million in the year ended March 31, 2002, a decrease of £336 million compared with £507 million in the year ended March 31, 2001. This decrease principally reflects the fact that, following the introduction of NETA, we are no longer required to repurchase output from the electricity pool to meet our obligations under our direct sales contracts. After adjusting for the effect of NETA as well as the cost of electricity purchased by Swalec and an exceptional charge related to the change in value of one of Swalec’s power purchase contracts, energy supply costs increased by £105 million, from £66 million in the year ended March 31, 2001 to £171 million in the year ended March 31, 2002. This increase reflects other electricity distribution costs associated with a 60% increase in the volume of direct supply sales during the year ended March 31, 2002. For a discussion of the effect of NETA on our energy supply costs, you should read “—Factors Affecting Results of Operations—UK Operations—New Electricity Trading Arrangements (NETA)”, above.

Operating (loss)/profit

Operating loss in the year ended March 31, 2002 was £281 million as compared with an operating profit of £280 million in the year ended March 31, 2001. Excluding exceptional items, operating profit in the year ended March 31, 2002 was £231 million, an increase of £5 million or 2%, compared with an operating profit of £226 million in the year ended March 31, 2001. Excluding exceptional items operating profit as a percentage of turnover was 11.3% compared with 10.6% in the prior year, reflecting the contribution that has been made by Bruce Power during the 11 months since May 2001.

Share of operating profit of joint venture

Our share of operating profit of AmerGen, increased by £24 million to £37 million in the year ended March 31, 2002. The output from the three AmerGen power stations totaled 18.7 TWh in the year ended March 31, 2002, an increase of 1.9 TWh compared with 16.8 TWh in the year ended March 31, 2001.

Financing charges

Financing charges, which comprise revalorization charges and net interest expense, were £253 million in the year ended March 31, 2002, an increase of £29 million or 13%, compared with £224 million in the year ended March 31, 2001. Excluding an exceptional charge of £27 million relating to a write-down of the market value of the UK decommissioning fund, financing charges decreased by £3 million to £226 million in the year ended March 31, 2002 compared with £229 million in the prior year. The decrease reflects lower revalorization as a result of lower UK inflation, partially offset by increased interest charges, reflecting the higher average debt in the year ended March 31, 2002 compared with the year ended March 31, 2001.

The revalorization charge was £187 million in the year ended March 31, 2002 compared with £168 million in the year ended March 31, 2001. Excluding the exceptional items, the revalorization charge was £160 million in the year ended March 31, 2002, compared with £173 million in the prior year. The decrease in revalorization reflects the weighted average UK inflation rate of 1.7% in the year ended March 31, 2002 compared with 2.1% in the year ended March 31, 2001.

Net interest increased by £10 million to £66 million in the year ended March 31, 2002. The increase in net interest expense reflects the higher average level of net debt in the year ended March 31, 2002 incurred to finance the Bruce Power lease arrangements and the investment that has been made to date to restart two reactors at Bruce A.

Taxation

Following the introduction of FRS19, the new UK deferred tax accounting standard, the tax charge for March 31, 2001 was restated and increased by £20 million. We have implemented the new standard on a discounted basis. The tax charge for the year ended March 31, 2002 was £25 million, a decrease of £23 million from the restated tax charge for the year ended March 31, 2001. Excluding tax relating to exceptional items, the tax charge for the year ended March 31, 2002 was £81 million, an increase of £48 million as compared with the restated tax charge of £33 million in the year ended March 31, 2001. The effective tax rate is higher than the standard rate of 30% as a result of overseas profits being taxed at rates in excess of 30%, the impact of items that are non-deductible for tax purposes, such as the write-down of our investment in Eggborough, and the impact of unwinding one year’s discount from our opening deferred tax liability. The tax charge for the year ended March 31, 2002 comprises a prior year UK corporation tax credit of £11 million, a deferred tax credit of £8 million, an overseas tax charge of £15 million and £29 million in respect of AmerGen. The restated tax charge for the year ended March 31, 2001 comprised £2 million of UK corporation tax charge, £45 million deferred tax and £1 million in respect of AmerGen.

As of March 31, 2002 there were deferred tax assets of £252 million. Of this amount £189 million relates to tax relief from operating losses carried forward. A further £63 million relates to the expected tax relief associated with accrued decommissioning costs which are expected to be deductible against future taxable income. On a US GAAP basis, the total deferred tax asset of £1,814 million is significantly greater because it is based on the undiscounted amount of decommissioning and uncontracted back-end fuel costs. See Note 36 to our consolidated financial statements.

We believe it is more likely than not that these deferred tax assets will be realized.

Loss on ordinary activities after taxation

As a result of the factors discussed above, there was a loss on ordinary activities after taxation for the year ended March 31, 2002 of £518 million compared with a restated profit of £9 million in the year ended March 31, 2001. Excluding exceptional items there was a loss of £39 million in the year ended March 31, 2002 compared with a loss of £23 million in the year ended March 31, 2001, reflecting the higher tax charge discussed above.

Minority interest

There was a minority interest in respect of the 17.6% minority share of the profits of Bruce Power of £9 million in the year ended March 31, 2002.

Earnings and dividends

There was a loss per share of 88.5p per share in the year ended March 31, 2002 compared with restated earnings per share of 1.2p per share in the year ended March 31, 2001. Excluding the effect of exceptional items there was a loss per share of 8.4p per share in the year ended March 31, 2002 as compared with a loss per share of 4.2p in the previous year.

On May 14, 2002 the board of directors recommended a final dividend of 5.3p per share which brought the total dividend for the year ended March 31, 2002 to 8.0p per share, unchanged from the previous year. The dividend was uncovered by profit after tax.

Capital Expenditure

Capital expenditure during the year ended March 31, 2003 was £282 million compared with £225 million during the year ended March 31, 2002 and £133 million during the year ended March 31, 2001.

Capital expenditure during the year ended March 31, 2003 consisted of £112 million in respect of our continuing UK activities and £170 million in respect of our discontinued Canadian activities. Capital expenditure during the year ended March 31, 2002 included £50 million with respect to the extended maintenance and testing outage at one of the reactors at Bruce B and £64 million with respect to the progress to date of our restart program at Bruce A. We expect to spend an aggregate amount of £70 million to install flue gas desulphurization units at Eggborough by the end of fiscal year 2004.

Research and Development

We support primarily scientific and engineering research activity directed toward securing further improvements in the reliability, performance and safety of our generating business and related activities. In fiscal years 2003, 2002 and 2001 our expenditure on research and development was £15 million, £16 million and £17 million, respectively.

Liquidity and Capital Resources

Cash Flow

The table below sets out the key components of operating cash flow for the periods indicated.

	Year ended March 31,
	2003		2002		2001
	(in millions of pounds)
Operating (loss)/profit	(3,802	)	(281	)	280
Exceptional items	3,906		512		(54	)

Operating profit excluding exceptional items	104		231		226
Depreciation and provisions(1)	392		441		409

Cash generated by operations	496		672		635
Nuclear liabilities, decommissioning fund payments and other provisions Discharged	(178	)	(393	)	(375	)
Capital expenditure, net of disposal receipts	(282	)	(225	)	(133	)
Working capital	18		101		17

Operating cash flow net of capital expenditure	54		155		144

(1)

Includes depreciation charges and nuclear liabilities charged to operating costs.

During the year ended March 31, 2003, operating cash flow was £54 million, a decrease of £101 million, or 66% as compared with £155 million in the year ended March 31, 2002. The decrease in cash principally reflects a decrease in cash generated by operations, an increase in capital expenditure associated primarily with Bruce Power, and higher working capital, offset by the reduction in nuclear liabilities discharged following standstill agreements reached with BNFL relating to the proposed financial restructuring.

During the year ended March 31, 2002, operating cash flow was £155 million, an increase of £11 million, or 8% as compared with £144 million in the year ended March 31, 2001. The increase in cash principally reflects an increase in cash generated by operations, and lower working capital partially offset by higher capital expenditure associated with the initial payment we made for the lease of the Bruce nuclear power stations.

During the year ended March 31, 2003 net cash outflow for investment activities, comprising movements in financial investments and the increase in term deposits, was £37 million compared with

a net cash inflow of £56 million in the year ended March 31, 2002. The cash outflow during the year ended March 31, 2003 resulted from an increase in term deposits primarily attributable to the standstill arrangements that were put in place as part of the proposed financial restructuring.

During the year ended March 31, 2002 net cash inflow for investment activities, comprising movements in financial investments and the decrease in term deposits, was £56 million as compared with a net cash outflow of £184 million in the year ended March 31, 2001. The cash inflow during the year ended March 31, 2002 results from a reduction in term deposits to fund investment in Bruce and cash receipts from the sale of our investment in Humber Power and receipts from employee share options.

During the year ended March 31, 2003 the net cash outflow for financing activities comprising returns on investment and servicing of finance, dividend payments and repayments of amounts borrowed net of new loans was £195 million, an increased outflow of £109 million compared to the previous year. During the year ended March 31, 2002 the net cash outflow for financing activities comprising returns on investment and servicing of finance, dividend payments net of new loans and minority funding, was £86 million, a decreased outflow of £16 million on the previous year.

During the year ended March 31, 2003 cash inflow in respect of acquisitions and disposals was £262 million, reflecting the disposal of our interests in the Bruce nuclear power stations. During the year ended March 31, 2002 cash outflow in respect of acquisitions and disposals was £129 million, reflecting our investment in the lease of the Bruce nuclear power stations.

Capital Resources

At March 31, 2003, we had total debt of £883 million. After taking into account our interest rate swaps which had the effect of reclassifying £475 million of floating rate debt as fixed rate debt, all of our total debt was fixed rate debt. Our total debt is comprised of:

•

A project finance loan of £475 million secured on the assets of Eggborough Power Limited (EPL), our subsidiary that operates our Eggborough coal-fired power station. Amounts owed by EPL to the lenders are not guaranteed by British Energy plc but British Energy guarantees the payment of amounts by British Energy Power and Energy Trading Limited (BEPET) to EPL under the CTA. The contractual amounts payable by BEPET under the CTA are calculated so as to cover EPL’s borrowing requirements and operating costs. British Energy also provides a subordinated loan facility to EPL. The final instalment of loan principal will be repaid in 2011. The loan currently bears interest at LIBOR plus 1.25%. It is proposed that these arrangements will be restructured as part of the proposed restructuring of the Group. At March 31, 2003 the effect of the Group’s interest rate contracts is to classify the borrowings as fixed rate.

•

An aggregate principal amount of £408 million pound sterling denominated bonds due between 2003 and 2016. The bonds bear interest at a rate of between 5.9% and 6.2%. An aggregate principal amount of £110 million matured in March 2003 but payment has been deferred as part of the standstill arrangements in our financial restructuring.

As at March 31, 2003 we had an undrawn credit facility with the UK Government amounting to £200 million, which is available to provide working capital for the business and collateral to support UK trading operations. HMG is entitled to require immediate repayment of the facility if, in the opinion of the Secretary of State for Trade and Industry, the restructuring cannot be implemented in the manner envisaged. The facility agreement is cross-guaranteed by the principal Group subsidiaries (excluding Eggborough Power (Holdings) Limited and Eggborough Power Limited) and is secured by, among other things, fixed and floating charges and/or share pledges granted by those subsidiaries. The facility agreement also contains a requirement to provide further security as required by the Secretary of State

for Trade and Industry provided that the creation of such security would not cause a material default under any contract to which any member of the Group is a party or is a breach of law.

Our outstanding pounds sterling denominated bonds require that we maintain a minimum interest cover ratio of at least 2:1. As of March 31, 2003, we were in compliance with this financial covenant. We believe that it is highly unlikely that we will be able to continue to comply with this financial covenant during the remainder of the period leading up to completion of restructuring. However, as the amounts due under the Bonds are already the subject of a standstill agreement which was put in place pending implementation of the proposed financial restructuring of the Group’s activities, we do not believe that non-compliance will adversely affect our trading operations.

At March 31, 2003, our cash at bank balances amounted to £87 million and our term deposits amounted to £246 million. Cash not immediately required for business purposes is invested in fixed rate term deposits. At March 31, 2003 the term deposits were due to mature within one month and earned interest at an average rate of 3.7%. Term deposits and bank balances at March 31, 2003 include £209 million of cash which has been deposited in collateral bank accounts for trading purposes. Availability of this cash is therefore restricted over the period of the collateralized position.

Disclosure of Contractual Obligations

We have made various financial commitments in the ordinary course of our business. Such commitments include entering into contracts for the supply of fuel for our power stations and capital expenditure commitments. In addition, we have made certain contingent financial commitments which may become payable under certain circumstances, for example in the event that a guarantee becomes payable.

The following table provides a summary of our general financial obligations as of March 31, 2003.

	Payment due by period
	Total	2003	2004	2005	2006	2007	2008	Thereafter
	(in millions of pounds)
Bonds⁽²⁾	408	110	—	—	163	—	—	135	⁽¹⁾
Project finance loan⁽²⁾	475	—	42	45	48	52	56	232
UK nuclear fuel purchases	583	—	208	181	166	28	—	—
UK coal purchases	68	—	47	14	4	3	—	—
Capital commitments	40	—	40	—	—	—	—	—
Long-term electricity purchase contracts⁽²⁾	316	46	62	61	47	36	37	27

	1,890	156	399	301	428	119	93	394

⁽¹⁾

Final maturity in 2016.

⁽²⁾

The analysis of maturity of Bonds, Project Finance loan and long term electricity trading contracts has been prepared based on the dates when they mature under the existing contractual arrangements. However, the standstill arrangements which have been put in place have the effect of deferring the payments of certain amounts due until the bonds, Eggborough project finance loan and long term electricity trading contracts are replaced as part of the restructuring of the Group or earlier termination of the standstill. The maturity profile is likely to change upon completion of the restructuring.

In addition to the above, there are also amounts payable relating to our back-end fuel costs and decommissioning liabilities. These amounts are based on our expected future output and costs. For more information as to how we calculate the amounts set forth below, see “ – Critical Accounting Policies – Nuclear Liabilities and Decommissioning”.

	Payment due by period
	Total	2004	2005	2006	2007	2008	Thereafter
	(in millions of pounds)
Nuclear liabilities	10,403	355	234	224	189	209	9,192

Future liquidity

Our main source of liquidity is from our operating businesses. Cash generation by our operating businesses is dependent upon the reliability of our power stations to produce electricity, the selling price achieved for our product, operational risk and capital expenditure requirements.

Subject to our compliance with the terms of the credit facility with the UK Government (discussed more fully in “Item 3 – Risks Associated with our Restructuring), we have £200 million of facility available to provide working capital from the business and collateral to support UK trading operations. The facility will mature on the earlier of September 30, 2004 or the date on which the restructuring plan becomes effective.

The Group lost its investment grade rating in September 2002. British Energy will seek the granting of another credit rating for its business after the proposed restructuring has been completed. The loss of our investment grade rating has meant that we now have to provide significant levels of collateral to our counterparties in order to enter into trades, thereby substantially reducing the levels of cash resources available to us.

While we believe that funds provided to us under the UK Government credit facility will provide us with sufficient liquidity and capital resources for us to meet our current and future financial obligations – including the provision for collateral, working capital, capital expenditure and other needs for at least the next twelve months – we draw your attention to the extensive risks which may impact upon our cash resources and the liquidly of our business during the periods prior to and post-completion of our restructuring. The risks associated with liquidity, which are discussed in more detail in “Item 3 – Risks Associated with our Restructuring” are principally associated with the ability to retain access to the facility, risks related to the steps required to implement our restructuring, including the need for our creditors, the UK Government and the EU authorities to approve the restructuring, and the potential inadequacy of the credit facility if the level of collateral demanded were to increase or if certain liquidity events such as significant unplanned outages or repairs were to occur. While the Group uses its best endeavors to manage its cash flows there are also seasonality factors inherent in its business, primarily related to market prices and the timing of outages, which during certain periods of the year increase the vulnerability of our cash resources and liquidity to unexpected demands for funding. The occurrence of one or more of these circumstances may place significant strain on our liquidity and capital resources and therefore, although we believe that we have sufficient facilities in place to meet our liquidity and capital resource requirements for the foreseeable future, we cannot provide absolute assurance.

Critical Accounting Policies

United Kingdom Generally Accepted Accounting Principles

Our accounts are prepared in accordance with UK Generally Accepted Accounting Principles, or UK GAAP. This requires the Directors to adopt those accounting policies which are most appropriate for the purpose of the preparation of the accounts.

Our material accounting policies are set out in full in Note 2 of our consolidated financial statements. In preparing the accounts in conformity with UK GAAP, the directors are required to make estimates and assumptions which impact on the reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates. Certain of our accounting policies have been identified as the most critical accounting policies by considering which policies involve particularly complex or subjective decisions or assessments and these are discussed below. The discussion below should be read in conjunction with the full statement of accounting policies. Your attention is also drawn to the “principles underlying going concern assumption” in Note 1 of our consolidated financial statements.

Going Concern

As described more fully in Note 1(ii) of our consolidated financial statements, we have reviewed our long-term prospects and have sought financial assistance through a business restructuring plan. The principal features of our proposed restructuring include:

•

Amendment and extension of our front-end and back-end related fuel contracts;

•

Establishment of a Nuclear Liabilities Fund (“NLF”) for uncontracted nuclear liabilities and decommissioning costs to which we will make initial and ongoing contributions;

•

Funding of the liabilities for historic spent fuel and any shortfall in the NLF by the UK Government;

•

Compromise of existing claims of significant creditors; and

•

Disposal of AmerGen as well as Bruce Power.

As indicated in “Item 4. Information on the Company—Business Overview—Restructuring”, we are currently in the process of seeking the various approvals required for our proposed restructuring plan. We disposed of our interest in Bruce Power on February 14, 2003.

On September 11, 2003 we announced that we had entered into an agreement to dispose of our 50% interest in AmerGen to FPL Energy LLC, a wholly-owned subsidiary of FPL Group for approximately US$277 million. See “Item 4. Information on the Company – Proposed Restructuring – The Sale of Bruce Power and AmerGen.”

Our consolidated financial statements have been prepared on a going concern basis because the Directors are currently seeking an alternative to liquidation or ceasing trade operations. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption is dependent on the continued financial assistance from the UK Government and our significant creditors, and the successful completion of the proposed restructuring.

The terms of the proposed restructuring will need to be agreed definitively with the significant creditors whose entitlements are to be compromised and will need to be approved by the Secretary of State, existing shareholders (where required), Inland Revenue and the European Commission prior to being finally implemented. If such agreements with creditors cannot be reached, the standstill arrangements are terminated, the required approvals are not forthcoming, the assumptions underlying the restructuring proposals are not fulfilled, the UK Government credit facility is not maintained or the conditions to the restructuring are not satisfied or waived, in each case within the time scales envisaged, then we may be unable to meet our financial obligations, in which case we could no longer be considered to be a going concern. The final restructuring plan, as approved, may differ significantly from that which we have proposed and may render the restructuring impossible to implement or no longer feasible. If this occurs, we may no longer be considered to be a going concern. Many of the steps required to implement the proposed restructuring, such as European Commission State Aid approval and the continued support by the UK Government, are beyond our control.

Therefore, if for any reason we are unable to complete the proposed restructuring and cease to be a going concern, adjustments may have to be made to reduce the monetary values of assets to their recoverable amounts, to provide for further liabilities that might arise and to reclassify the fixed assets and long-term liabilities as current assets and liabilities.

Nuclear Liabilities and Decommissioning

Our nuclear liabilities principally relate to the cost of reprocessing and storage of spent fuel and storage and disposal of nuclear waste, collectively known as back-end fuel costs. Nuclear liabilities also include the cost of decommissioning our nuclear power stations and defueling plants.

In accordance with UK GAAP, back-end fuel costs are recognized in proportion to the amount of fuel burnt. However, because these costs will not be incurred for many years the estimated costs (expressed in current prices) are discounted at 3% per annum from their estimated payment dates. The discounted back-end fuel cost is recognized when the related fuel is burnt. The 3% discount rate reflects average long-term investment returns. More than 80% of AGR back-end fuel costs are covered by contractual arrangements with BNFL, all of which include fixed price terms subject to indexation. Liabilities for PWR back-end fuel costs are based on cost estimates derived from the latest technical estimates. See “Item 4. Information about the Company – Proposed Restructuring for details of the new BNFL contracts.”

In accordance with UK GAAP, the estimated costs of decommissioning our power stations are provided for when the power stations begin operating commercially, are capitalized as part of the cost of construction and depreciated over the same lives as the stations. The estimated costs of decommissioning are discounted to reflect the timescale before and during which the work will take place (following closure of the power station). We anticipate that after defueling the reactors, dismantling the reactors will not be possible for at least 50, and up to 135 years, after the closure of the relevant power station.

As at March 31, 2003, our total undiscounted expected future payments in respect of nuclear liabilities, stated at current money values, were £14.7 billion. This amount takes into account all costs associated with fuel burnt in the past, estimated fuel to be burnt in the future and decommissioning. Discounted at 3% per annum from the estimated eventual payment dates, this amount was £5.3 billion as at March 31, 2003, of which £3.9 billion had been accrued. The difference between the total discounted nuclear liabilities and the amount accrued as at March 31, 2003, represents the estimated discounted back-end fuel cycle costs associated with fuel to be burnt in the future.

The actual liability for decommissioning can vary significantly from our estimate, and as a result, the liabilities we report in our results can vary significantly if our assessment of these costs changes. Many of the factors that are integral to the determination of our estimate, such as governmental regulations and inflation, are beyond our control.

Station Accounting Lives

Accounting lifetimes of our nuclear power stations reflect our current assessment of potential life limiting technical factors and independent engineering assessments. The operating lifetime of a nuclear power station is limited principally by the lifetime of items which are uneconomical to replace such as the graphite core, the boiler (in AGRs) and other components inside the reactor pressure vessel. The methodologies and technology used to evaluate the expected lifetimes of nuclear stations is dynamic, resulting in progressively improved measurement capabilities that allow us to determine whether the safety case for an extended accounting life of a nuclear power station can be supported. The estimates of station accounting lives are therefore subjective. The extension of a station’s life may

improve our results, particularly when accounting for liabilities such as decommissioning. We have not considered it appropriate to extend the accounting lives of any of our power stations in the financial year ended March 31, 2003.

Impairment of Fixed Assets

We undertake a review of the carrying value of our fixed assets compared with the economic value and net realizable value of those assets. In carrying out the economic valuations significant estimates are made of the future cash flows being generated by the assets, taking into account current and expected future market conditions and the expected lives of our power stations. The assessment of future market conditions includes, for example, a view of likely overcapacity in the market over a number of years and the likely timing of the market returning to new entrant prices. The actual outcome can vary significantly from our forecasts, thereby affecting our assessment of expected future cash flows. The expected future cash flows are discounted at a rate approximating to our weighted average cost of capital as this is the rate most representative of those assets. The impairment review has resulted in the value of our power stations being written down by £3,738 million for UK GAAP during the year ended March 31, 2003.

UK Decommissioning Fund

We make annual contributions into an independently administered Decommissioning Fund, which is intended to cover all the costs of decommissioning our UK nuclear power stations, except defueling. We made an initial endowment of £228 million to the Decommissioning Fund when it was established in July 1996 and have contributed a total of £115 million since that time based on an agreed schedule of quarterly payments. The returns from investments vary from year to year but, based on actuarial advice, we assume that an annual rate of return of 3.5% after tax will be achieved. This assumed rate of return is, therefore, included in the profit and loss account each year as a revalorization credit. This credit partly offsets the revalorization charge made to unwind one year’s discount from the decommissioning liability. See Note 16 to our consolidated financial statements. The actual return from the investments may vary significantly from the assumed actuarial rate of return, and as a result, the amounts we report in our results can vary significantly as a result of changes in market conditions, which are beyond our control.

The inclusion of the assumed rate of return, which is not a realized profit, is, however, a departure from the UK Companies Act. We believe that the departure is necessary for the accounts to give a true and fair view and have, therefore, invoked the true and fair over-ride provisions of the Companies Act 1985. If the true and fair over-ride provision were not invoked we would carry the Decommissioning Fund at cost which could be significantly lower than its market value and the revalorization credit for the Decommissioning Fund would not be included in the profit and loss account.

In the event that the net realizable value as indicated by the market value of the fund is lower than the value determined by applying the assumed annual rate of return of 3.5% after tax, we would include the lower amount in our consolidated financial statements. We were required to restate the fund to market value at March 31, 2003 by a charge of £82 million in our income statement due to the fall in value of the equity markets during the reporting period.

Deferred Taxation

Following the implementation of FRS19, Deferred Taxation, we discount our full deferred tax liability. FRS19 allows a company the choice as to whether or not to discount its deferred tax liability. We implemented FRS19 on a discounted basis in the financial year ended March 31, 2002 as we consider that this is necessary in order to present all our long term liabilities on a consistent basis. The

implementation of FRS 19 resulted in a prior year adverse adjustment to reserves and net assets of £130 million in our consolidated financial statements for the year ended March 31, 2002. As a result of the application of FRS 19 our tax charge consists of current tax, both in the United Kingdom and North America, deferred tax and the unwinding of two years’ discount in respect of the current year and the opening deferred tax liability. Deferred tax assets are recognized in the accounts to the extent to which they are considered to be recoverable in the foreseeable future.

Onerous Contracts

Following the introduction of NETA and the renegotiation of certain contracts, a number of our electricity trading contracts no longer hedge the Group’s physical output. As the status of these contracts changed under UK GAAP, a provision was made for the “out of market” element of the contracts under FRS 12. In arriving at the provision the terms of the contract are considered along with our estimate of the expected future electricity prices over the period of the contracts. The financial statements for the year ended March 31, 2003 reflect the claim amounts for these contracts which have been agreed in principle for the purpose of the proposed restructuring of the Group.

United States Generally Accepted Accounting Principles

In addition to preparing our accounts in accordance with UK GAAP, the directors are also required to prepare a reconciliation of our profit and loss and shareholders’ funds from UK GAAP to United States Generally Accepted Accounting Principles, or US GAAP. The adjustments required to reconcile our profit and loss and shareholders’ funds from UK GAAP to US GAAP are explained in Note 37 to the accounts. Certain of our US GAAP accounting policies have been identified as the most critical US GAAP accounting policies and these are discussed below. The discussion below should be read in conjunction with the full explanation of US GAAP accounting policies set out in Note 37.

Impairment of Fixed Assets

As discussed in the preceding section under UK GAAP, we have performed an impairment review of our fixed assets for UK GAAP. In addition, we have also performed an impairment review of our fixed assets under US GAAP, using consistent assumptions and estimates as those used for purposes of our review under UK GAAP. However under US GAAP, fixed assets are written down to their fair value only when their carrying value exceeds their undiscounted future cash flows. In the current year the US GAAP impairment test indicated that the carrying value of our power stations exceeded their undiscounted future cash flows. As a result, we were required to record an additional impairment charge of £2,942 million for purposes of US GAAP in the year ended March 31, 2003. The additional impairment charge is due to the different treatment of certain plant costs, such as capitalized interest and decommissioning, for UK and US GAAP as described more fully in Note 37 of our consolidated financial statements. Significant estimates are made when performing an impairment review. A change in any of estimates of the future cash flows or in the method of determining the fair value of our power stations could result in a different impairment charge under US GAAP.

Derivatives

Under US GAAP certain contracts that have been entered into by us in the ordinary course of business are considered to be derivative instruments. Accordingly we are required to arrive at the fair value of these contracts at March 31, 2003 and include these fair values in our US GAAP balance sheet. The movement in fair value from one reporting period to the next is recognized in our income statement or within other comprehensive income, as appropriate.

In arriving at the fair values of the derivatives, estimates are made of future commodity prices, including the selling price for electricity and for coal. Certain of these prices can be ascertained externally in the short term, however, in the longer term we are required to use internal valuation techniques and models which take account of forecast sales volumes, prices and the correlation between various factors in the market place. The actual outcome can vary significantly from our future forecasts and, as a result, the amounts we report in our results can vary significantly as a result of changes in factors, many of which are beyond our control.

UK Decommissioning Fund

As discussed in the preceding section under UK GAAP, we rely on an actuarially determined assumed annual rate of return on the assets of the Decommissioning Fund that is recorded in our profit and loss account as a revalorization credit for UK GAAP. Under US GAAP, the assets of the Decommissioning Fund are classified as “available-for-sale” securities and are recorded at market value. Unrealized gains and losses resulting from changes in the market value of the securities in the Decommissioning Fund that are deemed to be temporary are excluded from the profit and loss account until realized and instead are reported within other comprehensive income as a separate component of equity shareholders’ funds. However, if the assets of the Decommissioning Fund continue to perform poorly, we are required to review the decline in the Decommissioning Fund’s value for an impairment that could potentially be considered to be “other-than-temporary” and would result in a charge to our profit and loss account rather than to shareholders’ equity. In arriving at a conclusion as to whether or not an impairment is considered to be temporary or “other-than-temporary”, we consider the following factors:

•

Current market conditions

•

Earnings and dividends of the assets and investments comprising the fund

•

Security ratings on the investments

•

Financial condition of the underlying investments

We are required to make estimates and apply significant judgment in reviewing the assets of the Decommissioning Fund for an “other-than-temporary” impairment. The actual returns on the assets of the Decommissioning Fund can vary significantly from our estimate and market assumptions, and may therefore result in an inappropriate or a deficient charge recognized in earnings.

In arriving at the market value of our investments in the Decommissioning Fund at March 31, 2003, we reviewed the decline in value of the Decommissioning Fund’s assets for impairment. Based on our review, we recognized a £94 million charge to our US GAAP net loss as we deemed a portion of the decline in value in the Decommissioning Fund to be “other-than-temporary”.

UK GAAP to US GAAP Reconciliation

Under US GAAP an additional impairment charge of £2,942 million was recorded in the financial year ended March 31, 2003. £300 million of this charge related to Eggborough, which was deemed to be impaired for UK GAAP in the financial year ended March 31, 2002. The difference in the timing of the impairment charge was due to a difference in the impairment test methodology for UK and US GAAP. The remaining £2,642 million of the impairment charge is due to the different treatment of certain interest and decommissioning costs for UK and US GAAP.

Under US GAAP the lease of the Bruce nuclear power stations was treated as a capital lease until our disposal of Bruce in February 2003, with interest and depreciation charges being recognized in our profit and loss account. See Note 37 to our consolidated financial statements.

Under US GAAP, future nuclear liabilities associated with back-end fuel costs that are not covered by contractual arrangements are recognized on an undiscounted basis. Although US GAAP now permits our estimated costs of decommissioning to be discounted, we have not yet adopted this treatment. Such uncontracted liabilities are recognized on an undiscounted basis and the movement in current price levels is capitalized. As at March 31, 2003, our total undiscounted estimated costs in respect of back-end fuel costs and decommissioning, stated at current prices, were £9.7 billion for back-end fuel costs and £5.0 billion for decommissioning. See Note 22 to our consolidated financial statements.

Under US GAAP, the loss after tax for the year ended March 31, 2003 and the year ended March 31, 2002 were £(7,732) million and £426 million, respectively, compared with a loss of £3,924 million and £518 million, respectively, under UK GAAP.

The deficit on equity shareholders’ funds under US GAAP at March 31, 2003 and March 31, 2002 were £(9,245) million and £1,228 million compared with equity shareholders’ funds of £(3,476) million and £490 million respectively under UK GAAP. Differences primarily result from the differing accounting treatment of nuclear liabilities (including decommissioning costs and uncontracted back-end fuel costs and the deferred tax implications of these adjustments). See Note 37 to our consolidated financial statements.

New Accounting Standards

UK Accounting Standards

There is one new accounting standard which could have a potentially significant impact on our reported results which we have not yet implemented. FRS 17 sets out the requirements for disclosure and measurement of retirement benefits, including pensions. FRS 17 replaces SSAP 24 and discloses deferred benefit pension scheme surpluses or deficits on the balance sheet and accounts for all annual movements in pension scheme valuations through the profit and loss account and statement of total recognized gains and losses. The date for full adoption of FRS17 has been put back to June 2005. However, we have complied with the applicable disclosure provisions by meeting the disclosures set out in Note 26 to our consolidated financial statements regarding the potential impact of FRS 17 on our balance sheet at March 31, 2003.

US Accounting Standards

In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets”. This standard will be effective for us for the year ending March 31, 2004, although early adoption is permitted. The standard provides the accounting requirements for retirement obligations associated with tangible long-lived assets and requires that the obligations associated with the retirement of the tangible long-lived assets be capitalized into the asset cost at the time of initial recognition. The liability is then discounted to its fair value at the time of recognition using the guidance provided by the standard. We have not yet quantified the impact that adoption of SFAS 143 will have on our results of operations and financial position; however, we expect that adoption will significantly reduce the GAAP difference for our decommissioning and back-end fuel costs (both contracted and uncontracted).

On April 30, 2002, the Financial Accounting Standards Board issued FASB Statement No. 145, “Rescission of FASB Statements No.4, 44 and 64, Amendment of FASB Statement No.13 and Technical Corrections”, or SFAS 145. SFAS 145 rescinds both FASB Statement No.4, “Reporting Gains and Losses from Extinguishment of Debt”, and the amendment to SFAS 4, FASB Statement No.64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements”. SFAS 145 will be effective for the year ending March 31, 2004; however, early adoption is encouraged. SFAS 145 is not expected to have a material impact on our financial results.

In December 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an Amendment of SFAS No. 123.” SFAS 148 provides two additional transition methods for companies electing to adopt the fair value accounting provisions of SFAS 123, “Accounting for Stock-Based Compensation”, but does not change the fair value measurement principles of SFAS 123. This statement also requires additional disclosures for entities continuing to measure compensation expense pursuant to APB 25, “Accounting for Stock Issued to Employees”. SFAS 148 is not expected to have any impact on our financial position or results of operations as we already measure compensation expense in terms of the fair value accounting provisions of SFAS 123.

In April 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively, referred to as derivatives) and for hedging activities under SFAS 133. This statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. We are currently assessing the effect that the adoption of SFAS 149 will have on our results of operations or financial position; however, we do not expect that the impact will be significant.

In May 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 150 “Accounting For Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS 150 establishes standards for how a Company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that a Company classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) if certain criteria are met. Many of those instruments were previously classified as equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective for the first fiscal period beginning after December 15, 2003. We have not yet determined the effect that the adoption of SFAS 150 will have on our results of operations or financial position.

In November 2002, the Financial Accounting Standards Board issued FASB Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34”. FIN 45 clarifies the requirements of a guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees by requiring that the guarantor recognize a liability for the fair value of the obligation it assumes under a guarantee. We have adopted the disclosure provisions of FIN 45 for our financial year ended March 31, 2003. The initial recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees that are initiated or modified after December 31, 2002. The adoption of FIN 45 did not have a material effect on our consolidated financial position or cash flows for the financial year ended March 31, 2003.

In January 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulleting No. 51.” FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and, therefore, we do not expect that the adoption of FIN 46 will have a material effect on our consolidated financial position, results of operations or cash flows.

ITEM 6. DIRECTORS, SENIOR MANAGERS AND EMPLOYEES

Directors and Senior Management

We operate under the overall direction of our board of directors. Our articles of association provide that the number of directors shall not, unless or until otherwise determined by an ordinary resolution, be less than four or more than 15. This provision of the articles of association may not be amended without the consent of the Special Shareholder (the UK Government). The Articles of Association also provide that at every annual general meeting of shareholders one third (or the number nearest to but not less than one third) of the directors shall retire from office. The directors to retire in each year are the directors who have been longest in office since their appointment or re-appointment. Directors who retire by rotation in this manner are eligible to stand for re-election. The directors may, at any time, appoint any person to be a director. Any person so appointed will hold office until the next annual general meeting of shareholders and shall then be eligible for election. The directors may appoint one or more of their number to the office of managing director or to any other executive office for such period and on such terms as the directors think fit. With the exception of Mr. Alexander the Executive Directors have one-year rolling employment contracts with us. Mr. Alexander’s service contract provides for a notice period of 24 months during the first year of his employment, reverting to 12 months thereafter. The executive officers have contracts that are terminable by us on one year’s notice. It is our policy that Non-Executive directors are appointed for a three-year term, renewable for a further three-year term on the basis of satisfactory performance, except where they are required to stand for re-election under the Articles of Association.

The name, title, age and date appointed of each of our Non-Executive Directors, our Executive Directors and our executive officers as at March 31, 2003 were as follows:

Name	Title	Age	Date appointed
Adrian Montague D	Chairman	55	November 28, 2002
Mike Alexander †#¨	Chief Executive	55	March 1, 2003
David Gilchrist †#¨	Managing Director, UK Generation	51	September 1, 2001
Duncan Hawthorne	Non-Executive Director	47	September 1, 2001
Keith Lough †¨	Finance Director	44	September 1, 2001
Ian Harley +*D	Independent Director	53	June 1, 2002
Sir Robert Hill +*D#	Independent Director	66	January 1, 1999
Clare Spottiswoode +*D	Deputy Chairman and Senior Independent Director	50	December 1, 2001
Robert Armour ¨	Company Secretary and General Counsel	43	December 13, 1995
Sally Smedley ¨	Director, Human Resources and Communications	54	February 8, 1999
Terry Brookshaw †¨	Director, Power and Energy Trading	57	September 25, 2000

Denotes member of the Audit Committee.

Denotes member of the Remuneration Committee.

†

Denotes member of the Group Risk Management Committee.

Denotes member of the Nominations Committee.

Denotes member of the Safety, Health and Environment Committee.

Denotes member of the Executive Committee.

Sir Robert Hill retired from our board at the Annual General Meeting on July 30, 2003. William Coley, former Group President of Duke Power and Pascal Colombani, a member of the Electricité de France Supervisory Board joined our board on June 1, 2003.

On August 1, 2003, we appointed Sir Robert Walmsley as an Independent Director.

The written consent of the Special Shareholder is required for the appointment of the chairman of the board. There are no other arrangements or understandings between any director or executive officer and any other person pursuant to which such director or executive officer was selected to serve. There are no family relationships between any of our directors or executive officers.

Robert Armour was previously a partner at Wright Johnston & Mackenzie, Solicitors, and Company Secretary at Scottish Nuclear. He holds an LL.B in Scots Law and an MBA.

David Gilchrist was previously Business Development Director at GKN plc Automotive Division, PA Management Consultants and Ford of Europe. He is a member of the Institution of Mechanical Engineers.

Ian Harley was formerly Chief Executive of Abbey National plc. He is a Non-Executive Director of Rentokil plc and a Fellow of the Institute of Chartered Accountants in England and Wales, and a Fellow and past President of the Chartered Institute of Bankers.

Duncan Hawthorne has more than 25 years of experience in the power engineering business and has held senior positions within our UK and North American operations. He is Chief Executive Officer of Bruce Power. He is a Chartered Engineer and a Fellow of both the Institution of Electrical Engineers and the Institution of Mechanical Engineers.

Keith Lough was formerly Chief Financial Officer of Hurricane Hydrocarbons Ltd. and Managing Director, Europe and North Africa for Lasmo plc. He is a fellow of the Chartered Association of Certified Accountants.

Clare Spottiswoode has held a variety of senior regulatory positions including the Director General of Ofgas (1993 to 1998).

Adrian Montague is currently Chairman of Crossrail, Deputy Chairman of Network Rail, Non-Executive Chairman of Michael Page International plc and a senior advisor to Société Générale. He was previously a solicitor with Linklaters & Paines and subsequently worked for Kleinwort Benson.

Mike Alexander was formerly Chief Operating Officer of Centrica plc, having previously held commercial and marketing roles with BP. He subsequently held senior positions at British Gas.

William Coley was appointed as an Independent Director on June 1, 2003. He recently retired as Group President of Duke Power after a career with that company, and is a Non-Executive Director of CT Communications Inc. South Trust Corporation and Novant Healthcare.

Pascal Colombani was appointed as an Independent Director on June 1, 2003. He is a Nuclear Physicist, formerly Non-Executive Chairman of Areva, the international nuclear services group in France. He was formerly a Board member of France Télécom, and until last year, Chairman and Chief Executive Officer at Commissariat à l’Energie Atomique. He is also a member of the Electricité de France Supervisory Board.

Sir Robert Walmsley was appointed as an Independent Director on August 1, 2003. Sir Robert, 62, was most recently Chief of Defence Procurement, Ministry of Defence (MoD), a post which he held from 1996 until 2003. Prior to his MoD appointment, Sir Robert’s career was in the Royal Navy during which time he was a nuclear propulsion specialist and for a time Chairman of the Naval Nuclear Technical Safety Panel. Sir Robert will chair our Safety, Health and Environment Committee, succeeding Sir Robert Hill.

Sally Smedley was previously Director Human Resources and Corporate Relations at East Midlands Electricity plc, and Employee Relations Director, the BOC Group plc. She has a BSc (Tech) in Occupational Psychology.

Terry Brookshaw was previously Energy Trading Manager for British Gas where he was responsible for helping to develop their electricity market entry strategy. He has a BSc in Physics and an MSc in Operational Research.

Outside Business Activities

Details of the outside business interests of our directors and executive officers are as follows:

		Other Directorships
Adrian Montague		Crossrail, Network Rail; Michael Page International plc; Cellmark AB
Mike Alexander		Associated British Foods plc
William Coley		CT Communications Inc; SouthTrust Corporation; Novant Healthcare
Pascal Colombani		Electricité de France
Ian Harley		Rentokil Initial plc
Duncan Hawthorne		AmerGen Energy Company LLC; Bruce Power Inc; Canadian Nuclear Association; World Association of Nuclear Operators (WANO)
Clare Mary Joan Spottiswoode		Advanced Technology (UK) plc; Caminus Corp; Economatters Ltd; Gerrard Energy Ventures; Homebill Ltd.
Sally Smedley		Remploy.
Robert Armour		N.I.A.; The Electricity Association; Scottish Council Development and Industry

None of the other directors or executive officers had other business interests outside of British Energy.

Compensation of Directors and Officers

During the year ended March 31, 2003, the aggregate amount of compensation we paid to all Executive and Non-Executive Directors and Executive officers was £2,105,961 (excluding pension contributions). During the year ended March 31, 2003, the aggregate amounts set aside or accrued to provide pension, retirement or similar benefits for Executive and Non-Executive Directors and executive officers, pursuant to any existing plan, was £87,687. Note 8 to the consolidated financial statements sets forth specific information regarding the emoluments and interests of individual Executive and Non-Executive Directors but does not address executive officers.

All of our executive directors are entitled to bonus payments under the Annual Incentive Plan. Bonus payments are determined by performance against a range of challenging targets underpinned by the safety and environmental priorities necessitated by the nature of our business.

In the year ended March 31, 2003, Executive Directors could be awarded cash payments of up to 50% of salary, depending on achievement of financial and other targets. In the year ended March 31, 2003, the plan included profit before tax, operating cash flow and the performance of the operating businesses, and was subject to a safety and environmental performance modifier.

On the basis of the targets set, bonuses would have been due to the Executive Directors and the Executive Committee. In view of the financial position of the Company, the Executive Committee recommended to the Remuneration Committee that no bonus under the Annual Performance Incentive Plan be paid. The Remuneration Committee accepted this recommendation. Because of his date of appointment, Mike Alexander did not participate in the bonus arrangements for the year ended March 31, 2003.

Following a review of market practice, the maximum bonus level for Executive Directors and Executive Committee has been increased to 60% of base salary for the current financial year. Payment will be based on cash flow, cost and output targets.

Service Contracts

The Company aims to set notice or contract periods for Executive Directors at one year or less. Where it is necessary to offer longer notice or contract periods to new Directors recruited from outside the Company, it is policy to reduce these as soon as possible after the initial period. Mike Alexander has a contract which provides 24 months’ notice if given in the first 12 months of employment. Thereafter, he will revert to 12 months notice on a rolling basis.

All other Executive Directors have a 12 month rolling contract.

Independent and Non-Executive Directors

The remuneration of Non-Executive Directors is determined by the Board, without the participation of the directors concerned. Appointed for three-year terms, they do not have service contracts, they are not eligible for any of our share schemes and do not receive any pension provision from us.

Board Practices

Remuneration Committee

The Remuneration Committee is concerned primarily with the pay, benefits and other employment conditions of Executive Directors. In addition, it retains an interest in the pay and benefits to other senior staff, to ensure reasonable consistency. The Terms of Reference for the Committee empower it to:

•

establish the remuneration policies and practices for Executive Directors and certain other directors and senior employees;

•

design and implement long-term incentive schemes;

•

determine and review the individual remuneration packages of the Executive Directors and other selected senior employees, including pension provision;

•

authorize the annual performance incentive plan for Executive Directors;

•

obtain external professional advice and expertise necessary for the performance of its duties.

The Committee is made up entirely of Independent directors.

Audit Committee

The Audit Committee is comprised entirely of Independent Directors. The Committee is responsible for reviewing the adequacy and effectiveness of our internal control and compliance procedures and ensuring that the Group complies with all statutory requirements in relation to the principles, policies and practices adopted in the preparation of the Financial Statements. The Committee reviews risk management processes across the Group including actions to mitigate or control key risks facing us. The Committee seeks the advice of both external and internal auditors in relation to matters arising from their work and is also responsible for encouraging and monitoring the adoption of Best Practice in Corporate Governance. The Committee also reviews the nature and extent of the external auditor’s non-audit services to the Group to ensure that a balance of objectivity and value for money is maintained.

Nominations Committee

The Nominations Committee advises the Board in relation to senior appointments and succession policy throughout the Group. Board appointments recommended by the Committee are made after an appropriate search and selection process has been undertaken.

The Committee is made up entirely of Independent Directors.

Share Ownership

As of March 31, 2003, the total amount of voting securities owned by the directors and executive officers, as a group was 39,276 ordinary shares, representing 0.004% of our issued and outstanding ordinary shares.

In addition, as of March 31, 2003, our directors and executive officers as a group, held options to purchase 785,718 ordinary shares, all of which options were issued pursuant to our Executive Share Option Schemes or our Sharesave Scheme.

Options to Purchase Securities from Registrant or Subsidiaries

We have established several share option schemes. The No. 1 Scheme has been designed for approval by the UK Inland Revenue under Schedule 9 of the UK Taxes Act of 1988 and, consequently, confers certain tax benefits on its participants. The No. 2 Scheme is an unapproved share option scheme and does not, therefore, confer any particular tax benefits on its participants. Collectively, the No. 1 Scheme and No. 2 Scheme are referred to as the “Executive Share Option Schemes”. In order to be eligible to participate in the Executive Share Option Schemes an individual must be a full time director or employee of British Energy. The No. 3 Scheme (the “All-Employee Share Option Scheme”) has been approved by the UK Inland Revenue and is available to all of our employees other than those who may participate in the Executive Share Option Schemes. There is also a Sharesave Scheme which is open to all our UK employees and full time directors who have been continuously employed for such period as the Board of Directors may prescribe (not exceeding five years before the date the options are to be granted).

As at March 31, 2003 there were 3,982,183 options outstanding under the Executive Share Option Schemes, 14,877,603 options outstanding under the All-Employee Share Option Scheme, and 19,073,380 options outstanding under the Sharesave Scheme.

Detailed below are the No. 1 Scheme options held by directors and executive officers as at March 31, 2003. These options become exercisable three years after the date of grant, subject to achievement of a performance condition.

Date of Grant	Date when option expires	Option price		Number of Ordinary Shares under Option
July 15, 1997	July 14, 2007	£	2.60	11,538
August 12, 1997	August 11, 2007	£	2.60	23,076
September 14, 2001	February 13, 2011	£	3.18	9,433

At our Annual General Meeting in July 2001, our shareholders approved the All Employee Share Option Plan 2001, which revised the terms of the previous No. 3 Share Option Scheme. No options have been granted under this scheme.

The Shareholders also approved the Share Incentive Plan (SIP) 2001. The SIP is based on UK legislation, which permits favourable tax treatment under certain circumstances for employees who invest in their employing company. This plan has not been activated.

Following the acquisition of Bruce Power, British Energy developed an International Sharesave Plan based on the UK Sharesave Scheme but open to employees in Canada only. Two grants were made under this scheme in January and July 2002. No Executive Directors were eligible to participate. Following the sale of Bruce Power, participants could exercise for a period of six months. This period terminated on August 15, 2003.

At our Annual General Meeting in July 2002 shareholders approved a new Executive Share Option Plan 2002 to replace the No. 1 and No. 2 Share Option Schemes. No options have been granted under the plan.

Directors’ Emoluments

This information and the information on Shares and Share Options has been subject to audit as required by the United Kingdom Companies Act 1985 (as amended).

Name	Basic Salary and Fees (£)			Bonus (£)		Contingent Fees		Compensation for Loss of Office (£)
	2003	2002		2003	2002	2003	2002	2003	2002
A Montague⁽¹⁾	100,000	—		—	—	300,000	—	—
M Alexander⁽²⁾	33,333	—		—	—	—	—	—
D Gilchrist	183,563	96,250	⁽³⁾	—	38,981	—	—	—
D Hawthorne⁽⁴⁾	152,978	94,984	⁽³⁾	—	38,943	—	—	—
K Lough	211,250	116,667	⁽³⁾	—	44,683	—	—	—
Sir R Hill⁽¹¹⁾	57,500	57,500		—	—	—	—	—
I Harley⁽⁵⁾	25,833	—		—	—	—	—	—
C Spottiswoode	53,333	8,333		—	—	—	—	—
Total Emoluments for serving Directors at 31 March 2003	817,790	373,734		—	122,607	300,000	—	—
R Jeffrey⁽⁶⁾	309,188	336,250		—	130,220	—	—	98,000
Sir R Biggam⁽⁷⁾	11,167	52,500		—	—	—	—	—
P Stevenson⁽⁸⁾	25,893	30,000		—	—	—	—	—
M Kirwan⁽⁹⁾	45,042	188,126		—	72,579	—	—	—
J Walsh⁽¹⁰⁾	7,325	25,000		—	—	—	—	—
Sir J Robb	—	48,082		—	—	—	—	—
P Hollins	—	66,409		—	18,000	—	—	—	364,600
Total Emoluments (all Directors)	1,216,405	1,120,101		—	343,406	300,000	—	98,000	364,600

Name	Accommodation and Relocation (£)			Other Benefits (£)		Total Emoluments Excluding Pension (£)		Pension Contributions (£)
	2003	2002		2003	2002	2003	2002	2003	2002
A Montague⁽¹⁾	—	—		209	—	400,209	—	—	—
M Alexander⁽²⁾	—	—		2,202	—	35,535	—	1,385	—
D Gilchrist	—	41,534		20,067	6,597	203,630	183,362	12,020	5,565
D Hawthorne⁽⁴⁾	—	—		8,046	12,949	161,024	146,876	21,749	8,750
K Lough	—	38,286		12,886	6,901	224,136	206,537	12,020	5,565
Sir R Hill⁽¹¹⁾	—	—		—	—	57,500	57,500	—	—
I Harley⁽⁵⁾	—	—		—	—	25,833	—	—	—
C Spottiswoode	—	—		—	—	53,333	8,333	—	—
Total Emoluments for serving Directors at 31 March 2003	—	79,820		43,410	26,447	1,161,200	602,608	47,174	19,880
R Jeffrey⁽⁶⁾	—	—		17,349	11,731	424,537	478,201	—	—
Sir R Biggam⁽⁷⁾	—	—		—	—	11,167	52,500	—	—
P Stevenson⁽⁸⁾	—	—		—	—	25,893	30,000	—	—
M Kirwan⁽⁹⁾	—	—		4,007	20,195	49,049	280,900	4,453	26,526
J Walsh⁽¹⁰⁾	—	—		—	—	7,325	25,000	—	—
Sir J Robb	—	—		—	—	—	48,082	—	—
P Hollins	—	—		—	3,456	—	452,465	—	2,134
Total Emoluments (all Directors)	—	79,820		64,766	61,829	1,679,171	1,969,756	51,627	48,540

Notes:

^1.

Appointed on December 1, 2002.

^2.

Appointed on March 1, 2003.

^3.

Appointed as Executive Directors on September 1, 2001.

^4.

D Hawthorne’s pro rata salary to termination date of February 14, 2003 was C$357,107 and has been converted into £152,978 sterling at the average exchange rate for the year (£1=C$2.40). Mr. Hawthorne became a Non-Executive Director serving on the Board from February 15, 2003.

^5.

Appointed on June 1, 2002.

^6.

R Jeffrey resigned as Director on February 10, 2003.

^7.

Sir R Biggam resigned as Director on June 7, 2002.

^8.

P Stevenson resigned as Director on February 28, 2003.

^9.

M Kirwan resigned as Director on May 31, 2002. The Salary figure for 2003 includes accrued holiday pay of £13,458.

^10.

J Walsh resigned as Director on July 16, 2002.

^11.

Sir R Hill retired as a director on July 30, 2003.

Detailed below are the No. 2 Scheme options held by directors and executive officers as at March 31, 2003. These options become exercisable three years after the date of grant, provided that the performance condition is met.

Date of Grant	Date when option expires	Option price		Number of Ordinary Shares under Option
July 15, 1997	July 14, 2004	£	2.60	57,692
August 12, 1997	August 11, 2004	£	2.60	137,320
June 29, 1998	June 28, 2005	£	5.08	68,446
February 8, 1999	February 7, 2006	£	6.67	15,368
June 25, 1999	June 24, 2006	£	5.29	104,935
July 14, 2000	July 13, 2007	£	2.41	216,824
September 14, 2001	September 13, 2008	£	3.18	116,353

Detailed below are the Sharesave Scheme options held by directors and executive officers as at March 31, 2003. These options become exercisable three or five years after the date of grant.

Date of Grant	Date when option expires	Option price		Number of Ordinary Shares under Option
September 1, 2000	February 28, 2004	£	1.36	6,211
September 1, 2001	February 28, 2005	£	2.61	6,465
September 1, 2002	February 28, 2006	£	1.36	502
September 3, 2002	February 28, 2008	£	1.36	7,058

The following information with regard to individual directors’ share option holdings has previously been made publicly available in our Annual Report.

No. 1 Scheme Options

	Date of Grant	Date when option expires	Option price		Number of Ordinary Shares under Option
D Gilchrist	July 15, 1997	July 14, 2007	£	2.60	11,538
M Kirwan	August 12, 1997	August 11, 2007	£	2.60	11,538
K Lough	September 14, 2001	September 15, 2011	£	3.18	9,433
R Armour	August 12, 1997	August 11, 2007	£	2.60	11,538
S Smedley	February 8, 1999	February 7, 2009	£	6.67	4,497

No. 2 Scheme Options

	Date of Grant	Date when option expires	Option price		Number of Ordinary Shares under Option
M. Kirwan	August 12, 1997 June 29, 1998 June 25, 1999 July 14, 2000	August 11, 2004 June 28, 2005 June 24, 2006 July 13, 2007	£ £ £ £	2.60 5.08 5.29 2.41	118,077 37,192 33,097 76,269
D. Gilchrist	July 15, 1997 June 29, 1998 June 25, 1999 July 14, 2000	July 14, 2004 June 28, 2005 June 24, 2006 July 13, 2007	£ £ £ £	2.60 5.08 5.29 2.41	57,692 19,862 21,379 40,659
K. Lough	September 14, 2001	September 13, 2008	£	3.18	116,353
R. Armour	August 12, 1997 June 29, 1998 June 25, 1999 July 14, 2000	August 11, 2004 June 28, 2005 June 24, 2006 July 13, 2007	£ £ £ £	2.60 5.08 5.29 2.41	19,243 11,392 25,436 43,523
S. Smedley	February 8, 1999 June 25, 1999 July 14, 2000	February 7, 2006 June 24, 2006 July 13, 2007	£ £ £	6.67 5.29 2.41	15,368 25,023 56,373

Robin Jeffrey and Duncan Hawthorne ceased to be Executive Directors in 2002/3. All share options granted to them lapsed on the dates when, respectively, Mr Hawthorne ceased to be an Executive Director and when Dr Jeffrey tendered his resignation. Mike Kirwan’s share options lapsed on 31 May, 2003 when he ceased to be an employee.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

Control of Registrant

We are not directly or indirectly owned or controlled by another corporation or by any government (except to the extent permitted by the Special Share, discussed below). As at August 31, 2003 we had been notified of the following interests of 3% or more of the issued ordinary share capital of British Energy.

Shareholder		Percentage
Amvescap		10.14
Brandes Investment Partners		7.80
British Energy Employee Share Trust		3.50
Legal & General Investment Management Limited		3.01

The voting rights of holders of 3% or more of the Company’s ordinary shares do not differ from those of other shareholders.

The shareholding held by British Energy Employee Share Trust at the same date in each of the previous three years was as follows:

March 31, 2002	3.47	%
March 31, 2001	3.65	%
March 31, 2000	3.65	%

On March 31, 2003, there were 180 registered holders of 285,566 ordinary shares with addresses in the US. The combined holdings of these shareholders constituted less than 1% of the total number

of ordinary shares outstanding. As certain of the ordinary shares are held by brokers and other nominees, these numbers may not be representative of the actual number of beneficial owners in the US or the number of ordinary shares beneficially held by US persons.

On March 31, 2003, there were 16 registered holders of 1,206,313 ADRs. The combined holdings of these shareholders constituted over 10% of the total number of ordinary shares outstanding. One ADR is equivalent to 75 ordinary shares.

We do not know of any current arrangements the operation of which may result in our change of control. However, the proposed agreements governing the NLF would, if effective, grant the NLF the option, in certain circumstances, to convert certain cash amounts due to the NLF from us into ordinary shares of British Energy. Such option if effective and if exercised may result in a change of control.

Our share capital includes one special rights redeemable preference share, the Special Share, with a nominal value of £1.00. The Special Share may only be held by the Special Shareholder, which includes any of one or more of Her Majesty’s Secretaries of State, another minister in the UK Government, the Treasury Solicitor or any person acting on behalf of the UK Government. The Special Shareholder may require us to redeem the Special Share at any time after September 30, 2006 at its nominal value by giving us notice and delivering the relevant share certificate. The registered holder of the Special Share may attend and speak at any general or other meeting of holders of any class of our shares but has no right to vote at any such meeting.

Until such time as the Special Share is redeemed, our articles of association prohibit any person (other than certain permitted persons) from holding more than 15% of the voting rights of our issued share capital. We call this restriction the Limitation. Permitted persons are deemed to include any custodian or depositary who holds shares for the benefit of holders of our American Depositary Receipts, or ADRs. However, permitted persons would not include a holder of ADRs which represent, in aggregate, a beneficial interest in more than 15% of the voting rights of our issued share capital. As long as the Limitation is in effect, we are required by our articles to enforce the Limitation (including, without limitation, withdrawal of voting rights of such shares and the forced sale of such shares).

The written consent of the Special Shareholder is required for each of the following:

•

The amendment, removal or alteration of the effect of (including the ratification of any breach of) certain provisions of our Articles of Association, including the provisions with respect to the Special Share and the Limitation and the number of directors who may be appointed to the board of directors.

•

The creation or issue of any of our shares carrying voting rights other than (a) shares carrying voting rights in all circumstances at general meetings of our shareholders and (b) shares which do not constitute equity share capital (as defined in the Company Act) and which, when aggregated with all other such shares, carry the right to cast less than 15% of the votes capable of being cast at any general meeting of our shareholders.

•

Variation of any voting rights attached to any class of shares.

•

The appointment of the Chairman of the board.

•

The passing of a resolution for our voluntary winding up.

•

Any changes to the Articles of Association of our operating subsidiaries that would allow them to issue shares to any person other than us and the disposal by us of any such shares.

As a consequence of our proposed restructuring (see “Item 4. Information on the Company – Proposed Restructuring – Scheme of Arrangement”) it is likely that the Company will become a wholly-owned subsidiary of a new parent company of the British Energy Group. As a result, the interests of

existing shareholders are likely to be very substantially diluted. British Energy plc may subsequently be liquidated or dissolved, with all of its assets distributed to its creditors over time in accordance with the proposed scheme of arrangements.

Related Party Transactions

Interest of Management in Certain Transactions

There have been no material transactions during our most recent three fiscal years, nor are there presently proposed to be any material transactions to which we or any of our subsidiaries are or were a party and in which any Executive or Non-Executive Director, or 10% shareholder, or any relative or spouse thereof or any relative of such spouse, who had the same home as such person or who is a director or executive officer of any parent or subsidiary of British Energy had or is to have a direct or indirect material interest. Furthermore, during our most recent three fiscal years there has been no, and at present there is no, outstanding indebtedness to us or any of our subsidiaries owed or owing by any of our Executive or Non-Executive Directors or any associate thereof.

Duncan Hawthorne, who was an Executive Director of the company until February 15, 2003 was also Chief Executive Officer of Bruce Power. Following the sale of our interest in Bruce Power which was completed on that date, Mr. Hawthorne remained as Chief Executive of, and as an employee of, Bruce Power. After that date he ceased to be an Executive Director, and became a Non-Executive Director of British Energy.

ITEM 8. FINANCIAL INFORMATION

See “Item 18. Financial Statements”.

ITEM 9. THE OFFER AND LISTING

Nature of Trading Market

The principal trading market for our ordinary shares is the London Stock Exchange. In addition, American Depositary Shares, or ADSs, (each of which represents 75 ordinary shares) are issued by Morgan Guaranty Trust Company of New York, as depositary for our ADRs, or the Depositary. Prior to October 31, 1999, neither ordinary shares nor American Depositary Receipts were listed or quoted on any recognized stock exchange in the United States. The table below sets forth, for the calendar quarters of each year indicated, the highest and lowest middle-market quotations (the closing price quoted for a security on any given day on the London Stock Exchange as published in the Daily Official List of the London Stock Exchange) for the ordinary shares.

	Ordinary Shares⁽¹⁾		ADSs
	High	Low	High	Low
	(in pence)		(in dollars)
QUARTERLY
1998
Third	602.00	512.00	—	—
Fourth	687.50	554.00	—	—
1999
First	739.50	517.50	—	—
Second	617.00	512.00	—	—
Third	591.00	405.00	—	—
Fourth	444.50	345.00	24.38	23.00
2000
First	399.75	175.25	25.88	11.06
Second	205.00	119.50	12.50	7.25
Third	262.00	165.00	16.19	10.38
Fourth	258.00	162.25	14.81	9.50
2001
First	295.50	193.00	17.35	11.75
Second	324.00	228.50	19.10	13.20
Third	337.00	256.75	19.40	14.45
Fourth	293.00	219.00	16.60	12.90
2002
First	259.75	175.00	14.96	10.20
Second	190.00	161.00	10.94	9.42
Third	171.50	5.00	9.15	0.50
Fourth	16.88	5.15	1.07	0.36
2003
First	7.50	3.20	4.93	0.22
Second	7.17	3.50	8.72	4.05
MONTHLY
January	6.43	4.30	0.46	0.29
February	7.50	4.50	0.49	0.30
March	4.82	3.20	4.93	0.22
April	4.00	3.50	4.85	4.05
May	7.17	3.65	8.72	4.33
June	4.80	3.85	6.19	4.94
July	4.40	3.90	5.11	4.63
August	6.75	3.50	7.96	4.25

⁽¹⁾

The past performance of the ordinary shares is not necessarily indicative of future performance.

In order to meet the minimum price criteria set by and following discussions with the New York Stock Exchange (NYSE), on March 7, 2003 we announced that we would change the ratio of our shares traded on the NYSE. The effect of the change would be to alter this ratio from one ADR to four ordinary shares, to a new ratio of one ADR to 75 ordinary shares. This change became effective on March 18, 2003.

On September 5, 2002, our board of directors announced that it had initiated discussions with the UK Government with a view to seeking immediate financial support to implement a longer-term financial restructuring. The board of directors decided to initiate discussions with the UK Government based on several factors including: (i) its review of our revised forecast for UK nuclear generation for the fiscal year ending March 31, 2003 (which indicated output of approximately 63 TWh as compared with the original target output of 67.5 TWh, due to unplanned outages particularly those at our Torness and Dungerness B nuclear power stations), (ii) the failure of our negotiations with BNFL to reach agreement on the terms of our fuel contracts, and (iii) its review of the long-term prospects of the British Energy Group. At close of business on September 5, 2002, certain of our securities including our ordinary shares listed in London and our ADRs traded on the New York Stock Exchange were subjected to temporary trading suspensions on the London Stock Exchange and the New York Stock Exchange respectively. Our ordinary shares and our ADRs resumed trading on the London Stock Exchange and the New York Stock Exchange on September 9, 2002.

The UK Financial Services Authority, the FSA, is conducting an investigation into the circumstances leading up to our September 5, 2002 announcement. The FSA has made no announcement regarding the status of its investigation although, if the FSA determines that we have breached the provisions of, and requirements imposed by, the UK Financial Services and Markets Act 2000, we may be subject to public censure or fines and restitution orders.

ITEM 10. ADDITIONAL INFORMATION

Material Contracts

Credit Facility

A credit facility agreement (the “Credit Facility”) dated September 26, 2002 as amended and restated on March 7, 2003 and further amended by a side letter dated August 15, 2003 was entered into between the UK Secretary of State and (i) British Energy, British Energy Generation (UK) Limited (“BEG (UK)”), British Energy Generation Limited (“BEG”) and British Energy Power and Energy Trading Limited (“BEPET”) as borrowers and (ii) British Energy, BEG (UK), BEG, BEPET, British Energy Investment Limited, District Energy Limited, British Energy International Holdings Limited (“BEIHL”), British Energy US Holdings Inc., British Energy L.P. and Peel Park Funding Limited as guarantors. The borrowers and guarantors are together referred to as the “obligors”.

All guarantors except British Energy L.P., have given security for obligations under the Credit Facility.

The facilities had an initial availability period ending on March 9, 2003. This was subsequently extended on March 7, 2003 by the UK Secretary of State, to September 30, 2004, or the date on which the restructuring plan becomes effective. The total facility amount was initially £650 million and this was subsequently reduced to £200 million on March 7, 2003. The Credit Facility consists of various loan and capital facilities for UK and Canadian working capital purposes.

The UK Secretary of State can require earlier repayment if, inter alia, that is required by the European Commission or under European law. Each loan made pursuant to the Credit Facility is repayable on the earlier of September 30, 2004, or the date on which the restructuring plan becomes effective (and subject to any termination events). Mandatory prepayment events include (unless waived by the UK Secretary of State):

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if the UK Secretary of State is of the opinion that the restructuring proposals cannot be implemented in the manner or time envisaged; and

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if there is a breach of any standstill agreement that entitles a Financial Creditor (defined as BNFL, the Bondholders, the Eggborough Banks, The Royal Bank of Scotland plc in relation to the Eggborough debt service reserve letter of credit, TotalFinaElf Gas Power Limited and Teesside Power Limited and Enron Capital & Trade Resources International Corp) to terminate the standstill.

The obligors provided customary representations and warranties and have given covenants appropriate to their financial situation and the nature of their business. Events of default include, inter alia, non-payment, breach of obligations, misrepresentation, cross-default, material judgments or orders being made, distress, sequestration or other process is levied/enforced, occurrence of insolvency related events, litigation, seizure, change in control and breach of law. The Credit Facility is governed by English law.

The Bruce Disposal

A Master Purchase Agreement dated January 17, 2003 for the disposal of British Energy’s interest in Bruce Power Limited Partnership (“Bruce Power”) (“the Disposal”) was entered into between, amongst others, British Energy and (i) Cameco Corporation (“Cameo”), (ii) BPC Generation Infrastructure Trust (“BPC”) and (iii) TransCanada Pipelines Limited (“TransCanada”) (together the “Consortium”).

The Disposal was effected by the sale of the entire issued share capital of British Energy (Canada) Limited (“BECL”) to a newly incorporated Ontario Corporation funded by the Consortium.

The total consideration payable by the Consortium was C$950 million subject to certain adjustments. C$100 million of the total consideration was paid directly to the Provincial Government of Ontario, Canada as a one-off allowance and restructuring fee. A further C$100 million is contingent upon the restart of two Bruce A units. In addition, a further C$80 million is held in escrow to cover the estimated outstanding tax liabilities of the Bruce Group. We have subsequently received an interim refund of some C$3 million. Finally, an additional C$20 million is held in escrow to cover successful claims in respect of representations and warranties for such period until all claims made against British Energy and British Energy International Holdings Limited (“BEIHL”) within two years from the completion of the Disposal are resolved.

Pursuant to binding heads of agreements entered into in November and December 2002 between British Energy and certain of its subsidiaries, the Power Workers’ Union Trust No.1 and The Society of Energy Professionals Trust (together “the Unions”) have consented to the transaction under the Limited Partnership Agreement in consideration of Bruce Power Investments Inc (“BPII”) forgiving loans of approximately C$16.2 million made to the Unions to allow them to acquire their initial 2.6% interest in Bruce Power and fund subsequent capital calls, and the transfer by BPII to the Unions of an additional 2.6% interest in Bruce Power in aggregate immediately prior to the completion of the Disposal.

British Energy and BEIHL have jointly and severally given extensive representations and warranties to the Consortium in relation to, inter alia, the business and affairs of the Bruce Group. The obligations of British Energy and BEIHL to indemnify the Consortium in respect of any breach of such representations and warranties are mostly subject to a minimum claims limit of C$20 million, a maximum claims limit of C$1,175 million and customary time limits.

The Consortium have, upon completion of the Disposal, assumed responsibility for all of British Energy’s obligations as credit support provider and/or guarantor under Bruce Power’s existing Trading Contracts. The Consortium will also take over British Energy’s financial assurance obligations to Bruce Power in respect of the CNSC License upon completion of the Disposal. In addition, pursuant to the

OPG Heads, the Consortium will assume responsibility for the C$175 million guarantee granted by British Energy to OPG under the Lease and the Lease Guarantee and British Energy will be released from these obligations and the Consortium will put Bruce Power in funds to pay the C$225 million of deferred rent payment due by Bruce Power to OPG at the date of completion of the Disposal which is a further condition to the OPG Heads. British Energy will have no further obligation to OPG in respect of rent payments.

British Energy will provide support services as requested from time to time by Bruce Power to support plant operations for a period of four years on terms to be agreed between British Energy and Bruce Power, acting reasonably.

Neither British Energy nor any of its affiliates will for a period of two years from the disposal (i) solicit any of BPII or Bruce Power’s existing employees; or (ii) become involved in nuclear power generation operations in Canada.

Cameco already holds a 15% interest in Bruce Power and BPII through its subsidiary Cameco Bruce Holdings Inc. (“CBHI”) and the Unions together hold a 2.6% interest in Bruce Power. Each of the Consortium members will own a 31.6% interest in Bruce Power and a 16.7% interest in Huron Wind as a result of the disposal. The Bruce Workers’ Union Trust No. 1 will have a 4.0% interest in Bruce Power and The Society of Energy Professionals Trust will have a 1.2% interest in Bruce Power. BPII will be entirely owned by the Consortium.

The Master Purchase Agreement is governed by the laws of the province of Ontario.

Standstill Agreements

Formal Standstill Agreement

A Formal Standstill Agreement dated February 14, 2003 was entered into between British Energy and (i) the steering committee of the Eggborough Bank Syndicate, (ii) The Royal Bank of Scotland plc as provider of a letter of credit to the Eggborough Banks (“RBS”), (iii) Teesside Power Limited (“Teesside”), (iv) Total Gas & Power Limited (“TotalFinaElf”), (v) Enron Capital & Trade Europe Finance LLC (“Enron”) (collectively known as the “Significant Creditors”) and (vi) British Nuclear Fuels plc (“BNFL”).

The Formal Standstill Agreement was subject to various approvals required by March 24, 2003 and certain US bankruptcy court approvals in the case of Enron. These have now been obtained and the Formal Standstill Agreement is now binding on all parties.

During the period of the standstill, commencing on February 14, 2003 and ending on the earliest of September 30, 2004 or a termination event or the completion of the restructuring (the “Standstill Period”), Significant Creditors and BNFL have agreed with British Energy that they will not take any steps to initiate administration proceedings or demand or accelerate any amounts due and payable by British Energy.

Certain Significant Creditors will be paid interest but not principal in respect of any claims against the British Energy group. Interest will continue to be paid to the Eggborough Banks in accordance with existing arrangements. In respect of Teesside, TotalFinaElf, Enron and RBS, interest was paid first on March 25, 2003 and then on the last business day of every six-month period thereafter based on the agreed Claims Amounts (except in the case of RBS where interest payments will be based on the present value of the Claim Amount).

Under the Formal Standstill Agreement, British Energy will amend the existing power purchase agreement with Teesside so that during the Standstill Period, British Energy will continue to purchase

power from Teesside at fixed prices set at levels based on the current forward curve for electricity. On completion of the restructuring, this power purchase agreement with Teesside will terminate.

The standstill agreements contain certain covenants for the benefit of the Significant Creditors and BNFL. For example, during the Standstill Period, British Energy has undertaken that it will not, without the unanimous consent of the Significant Creditors and BNFL, inter alia, make any acquisition or disposal greater than £5 million (except for the sale of Bruce Power and AmerGen) and it will not issue equity or pay any dividends.

BNFL or any of the Significant Creditors may terminate the standstill agreement following the occurrence of a termination event. The termination events include certain insolvency events affecting British Energy, BEG, BEG (UK), BEPET or EPL, acceleration of the Facility, the required approvals under the standstill agreement not being obtained within the timescales envisaged, any of the British Energy, BEG (UK), BEG, BEPET or EPL failing to discharge certain continuing obligations and definitive documentation having not been executed by September 30, 2003.

Bondholder Restructuring Agreement

A Bondholder Restructuring (Standstill) Agreement dated February 14, 2003 was entered into between British Energy, BEG and BEG (UK) and (i) certain Bondholders owning 58% of the £109,861,000 5.949% Guaranteed Bonds due 2003 (the “2003 Bonds”), (ii) certain Bondholders owning 55% of the £163,444,000 6.077% Guaranteed Bonds due 2006 (the “2006 Series Bonds”) and (iii) certain Bondholders owning 75% of the £134,586,000 6.202% Guaranteed Bonds due 2016 (the “2016 Series Bonds”) (collectively known as the “Bondholders” and the 2003 Bonds, the 2006 Series Bonds and 2016 Series Bonds, together (the “Bonds”).

The Bonds were issued by British Energy on March 25, 1999. The principal amount outstanding of the 2003 Bonds is £109,861,000. The scheduled maturity date is March 25, 2003. Interest at 5.949% per annum is payable on March 25 in each year. The principal amount outstanding of the 2006 Bonds is £163,444,000. The scheduled maturity date is March 25, 2006. Interest at 6.077% per annum is payable on March 25, in each year. The principal amount outstanding of the 2016 Bonds is £134,586,000. The scheduled maturity date is March 25, 2016. Interest at 6.202% per annum is payable on March 25 in each year. The trustee of the Bonds is the Law Debenture Trust Corporation (the “Trustee”).

Pursuant to the Bondholder Restructuring (Standstill) Agreement, during the Standstill Period (the period commencing on February 14, 2003 and ending on the earliest of September 30, 2004, or a termination event or the completion of the restructuring), British Energy will continue to pay interest on the Bonds (at the current rate(s) on the full principal amounts outstanding on the Bonds), but on a semi-annual basis after the annual payment to be made on March 25, 2003. The scheduled redemption of the 2003 Bonds will be deferred until the end of the Standstill Period or, if later, in circumstances where there is no event of default subsisting, the date on which such Bonds would otherwise become due and payable. The holders of each series of Bonds and the other affected Significant Creditors will not be able to accelerate their claims or commence insolvency or other proceedings against British Energy and certain of its subsidiaries.

The Supplemental Trust Deeds (constituting the standstill arrangements in respect of the relevant series of Bonds) entered into by the Trustee can be terminated upon, amongst other things, the receipt by British Energy of a lawful notice of termination by the Trustee. The Trustee would serve such a notice of termination if it is requested in writing to do so by the holders of at least 50% in aggregate principal amount outstanding of the relevant series of Bonds (and provided it has been indemnified to its satisfaction) following the occurrence of a Termination Event (as defined in the Bondholder Restructuring (Standstill) Agreement), which includes failure to pay interest on the Bonds when due

and such failure continues for 20 business days. Each and every Supplemental Trust Deed also contains undertakings by British Energy, BEG and BEG (UK) concerning the way in which their business is carried on during this Standstill Period. If any of these undertakings is breached, the Supplemental Trust Deed can be terminated if such breach is not remedied within seven days of the date on which the Trustee serves a notice on British Energy (and copied to the UK Secretary of State) requiring remedy and either (i) the Trustee certifies to the Issuer that such breach is, in the opinion of the Trustee, materially prejudicial to the interests of the Bondholders or (ii) the Trustee is requested to do so by the holders of at least 50 per cent. in principal amount outstanding of the relevant series of Bonds and has been indemnified to its satisfaction.

The BNFL Contracts

(i)

The Deed of Amendment and Guarantee between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors between Nuclear Electric Limited and BNFL dated June 3, 1997, as amended.

This amendment gives effect to certain changes to the fuel supply arrangements and inserts new arrangements in relation to the supply of uranics used in the AGR fuel fabrication process and enriched uranium for on supply by BEG to its PWR fuel fabricator. The amendments contained in the deed became effective on April 1, 2003 however, (except in relation to the amendments relating to the new uranics arrangements which are not subject to conditionality), the amendments are subject to a number of termination conditions relating to the proposed restructuring of the British Energy Group. In the event that the conditions are not satisfied (or waived) by December 31, 2004, the existing agreement will continue in force as if the deed had never been entered into (except in relation to the new uranics arrangements as noted above).

The main amendments effected by the deed relate to:

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the reduction of the fixed annual payment by £5,000,000 and a discount (which is calculated across both the BEG and the British Energy Generation (UK) Limited (“BEG (UK)”) AGR fuel supply agreements as an amount equal to the higher of (a) zero and (b) the lower of £15,000,000 and (£18/MWh minus the Outturn Electricity Price (“OEP”)) x 5TWhr. The £15,000,000 and £18/MWh are expressed in 2003 money values and are subject to escalation in accordance with the UK Retail Prices Index (“RPI”). The OEP is derived from reported market prices and is intended to reflect the baseload wholesale electricity price that BEG and BEG (UK) are exposed to, so providing BEG and BEG (UK) with a partial hedge of the electricity price risk.

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the insertion of additional exceptions to the general prohibition on assignment of rights under the agreement without the consent of the other party (not to be unreasonably withheld) permitting both BNFL and BEG to assign rights under the fuel supply agreement without consent and or on certain conditions.

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an additional obligation on the parties to provide assistance to HMG in relation to the State Aid notification and to notify the agreements to the competition authorities.

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the insertion of a parent company guarantee by British Energy under which British Energy guarantees the performance of BEG under BEG’s existing AGR fuel supply agreement as amended by the deed. British Energy’s liability under the guarantee is expressed to be no greater than the liability of either BEG. Where British Energy ceases to be the ultimate holding company of BEG, it must notify BNFL and assign certain contracts which it has entered into with BNFL.

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the insertion of a new provision whereby British Energy and BEG acknowledge and agree that no member of the Group will bring any claim against BNFL that the terms of

the existing agreement/Deeds of Amendment or the heads of terms dated November 28, 2002 between BNFL and British Energy infringe competition law or that the “hardship” provisions of the existing agreements may be invoked.

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new uranics arrangements under which BNFL will supply uranics to BEG for an initial firm period of seven years which either BEG or BNFL may terminate on 12 month’s notice (but not before the end of the sixth year) or earlier for non-performance by BNFL. This initial term is divided across BEG’s existing and new post 2006 fuel supply agreements. BNFL is to supply BEG with uranics for the purposes of fabrication into AGR fuel in accordance with a procurement policy and a procurement strategy, and is required to provide certain information to BEG on a regular basis. BEG is required to pay variable charges to BNFL relating to the uranics contained in the fabricated fuel supplied to BEG, incidental services (such as transport, insurance, cylinder washing, cylinder hire or uranic analysis) (£9,000 per tonne U in respect of AGR and PWR fuel (£4,000 per tonne U in respect of PWR fuel where no cylinder hire and washing is required), administration (LIBOR plus 2%) based on the quantity of stocks held by BNFL for the purposes of supplying fuel to BEG under BEG’s fuel supply agreement and procurement and management services (£175,000 (escalated)).

Stock is to be repurchased by BEG in the event that the value of BEG’s forecast of stock cover at the end of the first month of BEG’s 12 months forecast exceeds £100,000,000 (escalated) (or £75,000,000 non-escalated in respect of the period 1 April 2003 to 31 March 2006 under the existing fuel supply contract), and BNFL is to buy back and use any stock repurchased by BEG prior to purchasing any new uranium material. BEG has rights to step into the uranics supply arrangements and procure uranics required under the agreement (at the sole cost of BNFL) in the event that the level of uranium material available for BEG for the purposes of fabricating into fuel under the fuel supply contract falls below 85% of forward months’ fuel requirements for a period of three months (subject to a grace period).

Upon the expiry or early termination of the uranics supply arrangements, BEG must repurchase all stock maintained by BNFL for the purposes of supplying fuel under BEG’s fuel supply agreement and take back all contracts novated to BNFL as well as all new contracts entered into by BNFL for the supply of uranics and/or for conversion or enrichment services in order to supply BEG with fabricated fuel (subject to consent of the counterparties). The stock repurchase will be immediate upon the expiry or elective termination of BEG or BNFL and will take place over a period of five years in accordance with an agreed schedule where BEG terminated for breach by BNFL.

(ii)

An Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy, dated March 31, 2003, (as amended on July 22, 2003).

This agreement is based on BEG’s existing AGR fuel supply agreement and incorporates the new provisions inserted into BEG’s existing AGR fuel supply agreement by way of the deed of amendment. Subject to satisfaction of the conditions described above, the agreement will take effect on April 1, 2006 and continue until the end of the fuel supply period (defined as the date following which no further AGR fuel is loaded into any AGR reactor of either BEG or British Energy Generation (UK) Limited (“BEG (UK)”).

The main differences between the new post 2006 agreement and the existing AGR fuel supply agreements as amended by the deed of amendment are:

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the annual fixed charge is £25.5 million. This charge is adjusted in the same way as described above in relation to the deeds of amendment;

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BNFL agrees to provide certain services relating to AGR fuel required as a result of the closure of a station (for example, the decommissioning or refurbishment of surplus fuel stocks and the return of or storage of surplus fuel) (on terms and conditions to be agreed); and

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the prices for the supply of ancillary components will be derived by adding a 20% engineering, procurement and warranty charge to the buying-in price of externally sourced components. The prices charged to BEG will be reviewed annually.

(iii)

A Deed of Amendment and Guarantee between British Energy Generation (UK) Limited (“BEG (UK)”), British Nuclear Fuels plc (“BNFL”) and British Energy, dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors between Scottish Nuclear Limited and BNFL dated March 30, 1995 as amended.

The amendments contained in this deed are as set out above in respect of the deed of amendment to British Energy Generation Limited’s existing fuel supply agreement, except in relation to the uranics arrangements which will essentially continue as set out in BEG (UK)’s existing fuel supply agreement. All amendments contained in this deed are subject to the same conditionality as described in relation to the deed of amendment to BEG’s existing fuel supply agreement.

(iv)

An Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation (UK) Limited (“BEG (UK)”), British Nuclear Fuels plc (“BNFL”) and British Energy, dated March 31, 2003 (as amended on July 22, 2003).

This agreement contains similar amendments to British Energy Generation Limited’s new post 2006 fuel supply agreement described above, and is subject to the same conditionality as the deeds of amendment to the BEG and BEG (UK) existing fuel supply agreements and the BEG new post 2006 fuel supply agreement.

(v)

A Deed of Sale and Purchase of Enriched and Natural Uranium Stocks between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy, dated March 31, 2003.

This deed provides for the purchase by BNFL of BEG’s existing stocks of uranium material with an approximate value of £65 million. The sale of the stocks was arranged to take place in several tranches: on March 31, 2003, July 1, 2003 and further interim sales on dates nominated by BEG (the last date being September 30, 2003) (comprising all remaining stocks which could not be transferred on the date of the second sale). A reconciliation to market prices of the stocks transferred in the second and further sales will be reconciled following audit certification.

The deed also provides for the transfer to BNFL of BEG’s third party contracts relating to the supply of uranium ore, uranium hexafluoride and/or the provision of conversion or enrichment services by September 30, 2003. An interim pass-through of the contracts applies between March 31, 2003 (the completion of the first sale) and the completion of the second sale under which BEG will perform the contracts upon BNFL’s instructions, and an ongoing pass-through of all contracts applies in respect of those contracts which the parties have not been able to novate to BNFL (e.g. because of failure to obtain counterparty consent) until the earlier of the date of expiry or early termination of the relevant contracts and the date on which the term of the uranics supply arrangement under the fuel supply agreements ends.

Reciprocal provisions apply under which the liability of BEG and BNFL is capped at £25m (except in relation to BNFL’s obligation to pay the purchase price of the stocks sold under the agreement) and indirect losses are excluded (except in relation to payments under the indemnities in connection with the pass-through arrangements described above).

(vi)

An End of Life Programme: Transmittal Letter from British Nuclear Fuels plc (“BNFL”) to British Energy dated February 14, 2003, acknowledged by British Energy on March 31, 2003.

This side letter provides for the establishment of a joint team to study the end of life optimization program for AGR power stations with a view to lowering the full costs of production of AGR fuel and sharing the benefits. The prices for AGR fuel, when this is being loaded into

three or fewer stations, will be set on the basis of the recommendations of this team (which is required to meet formally at least annually). The respective parties are to provide an update on progress towards station lifetime extension and/or station closure and progress against the Springfields Transformation Plan, and are required to submit a report to the parties containing their recommendations as to certain matters.

(vii)

An agreement dated March 31, 2003 between British Energy Generation Limited (“BEG”), Magnox Electric plc (“Magnox”), BNFL and British Energy for the implementation of the Passport 9 asset management software.

Under an agreement signed in 1996, BEG currently provides Magnox with computer services to host the asset management software entitled “Passport”, and to provide fault and maintenance support for emergency services. BEG uses Passport to manage its own power stations and has recently upgraded to a new version of the software. Under a computer services agreement signed on March 31, 2003, BEG is to assist Magnox in its upgrade to a new version of Passport. The upgrade is expected to be complete by the end of March 2005. The 1996 agreement, which was due to expire on March 31, 2004, was extended on March 31, 2003 to last until end March 2005, at a cost to Magnox of £1.5 million.

Under the new computer services agreement BEG is to receive £10 million annually from Magnox paid in equal monthly installments, which are accelerated if the project is completed ahead of schedule. A one-off amount is payable at the start of the contract period in respect of project set-up costs. Two costs are payable by Magnox during the lifetime of the project: a fixed monthly amount in respect of mainframe costs; and a variable amount in respect of external consultants’ costs. The latter are to be borne equally by BEG and Magnox up to a cap of £1 million annually for BEG. Once BEG has borne £1 million of external consultants’ costs in a year, any further costs are to be paid for entirely by Magnox. Magnox’s payment obligations are guaranteed by BNFL, its parent company. British Energy is a party to the agreement for the purposes of guaranteeing the performance of BEG’s obligations should BEG transfer its rights and obligations under the agreement or subcontract it to another group company.

(viii)

An agreement for new spent fuel management services between British Nuclear Fuels plc, British Energy Generation Limited (“BEG”), British Energy Trading Services Limited and British Energy dated May 16, 2003 (“BEG New Spent Fuel Agreement”).

This agreement is based on the current Spent Fuel Management Agreement dated June 3, 1997. It, together with the BEG (UK) New Spent Fuel Agreement described in paragraph (ix) below, (together the “New Spent Fuel Agreements”) provides for British Nuclear Fuels plc (“BNFL”) to manage irradiated AGR fuel arising from fuel which was loaded to the AGR reactors on or after the effective date, until the final delivery of irradiated fuel from the last AGR station to shut down including final cores. The effective date is the date following the date on which certain conditions relating to the proposed restructuring of the British Energy Group are satisfied or waived. These conditions apply to both the AGR Fuel Supply Agreements described above and the other spent fuel management related agreements and deeds of amendment described below. None of these spent fuel management related agreements and deeds of amendment become effective until these conditions precedent have either been satisfied or, in certain cases, waived by BNFL.

The main features of the BEG New Spent Fuel Agreement are as follows:

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Under the BEG New Spent Fuel Agreement, BNFL will take title to all irradiated AGR fuel on collection by BNFL of such fuel from the power stations. Under the current spent fuel arrangements, although risk passes to BNFL on collection of the fuel, title to the fuel and most of the waste products deriving therefrom remains with British Energy, who are therefore obliged to remove and be responsible for the ultimate disposal of these products and wastes at the end of the contracted storage period. Under the BEG New

Spent Fuel Agreement, BNFL will be responsible for managing and ultimately disposing of the irradiated AGR fuel at its sole discretion.

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The pricing provisions under the BEG New Spent Fuel Agreement differ substantially from the current arrangements. BEG will make one-off payments to BNFL in respect of the each tonne of Uranium contained in the fuel, such payments being linked to the time of first loading of such fuel into a reactor rather than the date on which it is actually delivered to BNFL as irradiated fuel, which will in most cases be some 5-10 years later. The payment structure is also subject to a rebate/surcharge mechanism linked to wholesale electricity prices, giving BEG a two-way hedge against these prices.

In relation to the main payment, BEG will pay BNFL a price of £150,000 (in 2002/03 money and thereafter escalated in accordance with RPI) per tonne. The surcharge/rebate is calculated according to a formula based on the amount of BEG/BEH(UK) output.

Invoicing will be on a monthly basis and will be based on agreed estimates of loading, coupled with an estimated rebate or surcharge. An annual reconciliation will be carried out. In the event that the annual reconciliation reveals that the payments that should have been made by BNFL to BEG exceed those from BEG to BNFL, then the reconciliation amount will be adjusted so that the total payments from BNFL to BEG equal those from BEG—i.e. there will never be a net payment from BNFL to BEG in a year.

In addition to the above, BEG must pay BNFL all those incremental costs incurred by BNFL in handling, storing and disposing of any non-standard fuel over and above those costs that BNFL would have incurred in respect of an equivalent quantity of fuel that meets the specification.

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British Energy is a signatory as guarantor in respect of its subsidiaries’ obligations (both financial and performance).

(ix)

An agreement for new spent fuel management services between British Nuclear Fuels plc, British Energy Generation (UK) Limited (“BEG (UK)”), British Energy Trading Services Limited and British Energy dated May 16, 2003 (“BEG (UK) New Spent Fuel Agreement”).

The BEG (UK) New Spent Fuel Agreement is equivalent to the BEG New Spent Fuel Agreement and is based on the Agreement for the Long-Term Storage of Irradiated Fuel dated March 30, 1995.

(x)

A deed of amendment between British Nuclear Fuels plc and British Energy Generation Limited (“BEG”) relating to the agreement for the storage and reprocessing of irradiated oxide fuel and related services between British Nuclear Fuels plc and Nuclear Electric plc dated March 31, 1995, as amended and novated (“BEG 1995 Historic Fuel Agreement”).

This deed of amendment amends and restates the BEG 1995 Historic Fuel Agreement so that, together with the amended and restated agreements (described below in paragraphs (xi), (xii) and (xiii)), (together, the “Historic Fuel Agreements”) it covers the management of irradiated AGR fuel which has already been delivered to BNFL’s Sellafield facility, which is currently in the reactors, or in spent fuel storage at the stations or which is to be loaded into the reactors prior to the effective date. The effective date is the date following the day on which certain conditions in relation to the proposed restructuring of the British Energy Group are satisfied or waived.

These services provided under this amended and restated agreement are the same as, and on the same terms as, those currently provided under the existing agreement. The primary difference between the existing agreement and this amended version are:

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consequential amendments that are necessary to reflect that while the existing BEG 1995 Historic Fuel Agreement (together with the existing versions of the other Historic Fuel Agreements) covered the lifetime arisings from the power stations, the amended and restated BEG 1995 Historic Fuel Agreement, together with the amended and restated versions of the other Historic Fuel Agreements, now only deal with fuel loaded into the reactors prior to the effective date, on which date the BEG (UK) New Spent Fuel Agreement and the BEG New Spent Fuel Agreement described above will come into play; and

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the current payment provisions have been replaced by a fixed monthly payment schedule. Payments for services, beyond the standard services, such as extended storage or treatment of non-standard fuel are not covered by the scheduled monthly payments.

•

this agreement terminates immediately upon the occurrence of the appointment of a liquidator in respect of BEG or the making of a court order, or the passing of a resolution, for the winding-up or dissolution of BEG (other than for the purposes of a solvent amalgamation or reconstruction) and BNFL shall also be entitled to terminate the Historic Fuel Agreements to which BEG is a party on the occurrence of the appointment of a liquidator or the making of a court order, or the passing of a resolution, for the winding-up or dissolution (other than for the purposes of a solvent amalgamation or reconstruction) in respect of BEG (UK) or British Energy or (where British Energy is no longer BEG’s ultimate holding company) BEG’s ultimate holding company.

(xi)

A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”) dated May 16, 2003, relating to the agreement for Spent Fuel Management Services between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG 1995 Historic Fuel Agreement.

The current payment provisions have been removed and payment for services provided under this agreement is covered by the monthly payments made by BEG pursuant to the amended and restated BEG 1995 Historic Fuel Agreement described in paragraph (x) above.

(xii)

A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”) dated May 16, 2003, relating to the agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995, as amended, and to the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG 1995 Historic Fuel Agreement.

As with the Historic Fuel Agreements, to which BEG is a counterparty, (as described above), the current payment provisions of the agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995 and the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited have been replaced by a fixed monthly payment schedule which appears in the amended and restated agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995. The net present value of all payments set out in the new payment schedule discounted at a real rate of 2.5% per annum to April 1, 2003 is £519.3 million. These payments cover the provision of services by BNFL to BEG

(UK) under the agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995 and the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited as well as the provision of services to BEG (UK) under those agreements described in paragraphs (xvii), (xviii), (xix) and (xx) below. Payments for services, beyond the standard services, such as extended storage or treatment of non-standard fuel are not covered by the scheduled monthly payments.

(xiii)

A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”) dated May 16, 2003, relating to the agreement for Oxide Flask Maintenance between BNFL and Nuclear Electric plc dated March 31, 1996, as amended and novated (“BEG Flask Maintenance Agreement”).

The amendments to the BEG Flask Maintenance Agreement and the agreements described in paragraphs (xiv), (xv), (xvi), (xvii), (xviii), (xix) and (xx) below (together the “Ancillary Agreements”) are essentially consequential amendments required to reflect the new structures of the New Spent Fuel Agreements and Historic Fuel Agreements described in paragraphs (viii), (ix), (x), (xi) and (xii) above.

Termination provisions, equivalent to those described in respect of the Historic Fuel Agreements above, appear in the amended and restated versions of this agreement and the other Ancillary Agreements. However, such termination rights are limited to the historic fuel component of such agreements—i.e. the provision of services in respect of fuel loaded into British Energy’s AGR reactors prior to the effective date. The reason for this is that these Ancillary Agreements support both the New Spent Fuel Agreements (described in paragraphs (viii) and (ix)) and the Historic Fuel Agreements (described in paragraphs (x), (xi) and (xii)). The New Spent Fuel Agreements do not contain such a termination provision and, accordingly, in the event that the Historic Fuel Agreements terminate, the services provided under the Ancillary Agreements would still be needed in respect of the New Spent Fuel Agreements.

An additional amendment has also been made in respect of this agreement and the BEG (UK) 1996 Flask Maintenance Agreement described in paragraph (xvii). Monthly payments were due under those agreements have been removed as they are now covered by the new payment schedules in the Historic Fuel Agreements described in paragraphs (x), (xi) and (xii).

(xiv)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the new agreement for Oxide Flask Maintenance between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xv)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the agreement for Rail Transport Services of Irradiated Nuclear Fuel in the United Kingdom between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xvi)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the agreement for Oxide Miscellaneous Services between BNFL and Nuclear Electric plc dated March 31, 1996, as amended and novated.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xvii)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for

Oxide Flask Maintenance between BNFL and Scottish Nuclear Limited, dated March 29,1996, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xviii)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the new agreement for Oxide Flask Maintenance Services between BNFL and Scottish Nuclear Limited, dated June 3, 1997, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xix)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for Rail Transport Services of Irradiated Nuclear Fuel in the United Kingdom between BNFL and Scottish Nuclear Limited, dated June 3, 1997, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

(xx)

A Deed of Amendment dated May 16, 2003 between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for Oxide Miscellaneous Services between BNFL and Scottish Nuclear Limited, dated March 29, 1996, as amended.

This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.

Memorandum and Articles of Association

The following is a summary of the principal provisions of our Memorandum and Articles of Association a copy of which has been filed with the Registrar of Companies. We were incorporated in Scotland on December 13, 1995 as Company Number 162273.

Memorandum of Association

Clause 6 of our Memorandum of Association states that our principal objectives are, among other things, to carry on all or any of the businesses of generators, suppliers, distributors, transformers, converters, transmitters, producers, manufacturers, processors, developers, storers, carriers, importers and exporters of, and dealers in electricity, derived from whatever source.

Articles of Association

At an Extraordinary General Meeting held on November 4, 2002, an amendment to the Articles of Association was approved, authorizing the Directors to permit the aggregate principal amount outstanding in respect of moneys borrowed by the Group to be up to an amount of £1.6 billion.

(a) Voting Rights

In the following description of the rights attaching to our shares, a “holder of shares” and a “shareholder” is, in either case, the person registered in the company’s register of members as the holder of the relevant shares. Shareholders can choose whether their shares are to be evidenced by share certificates (i.e. in a certificated form) or held in uncertified electronic form in CREST (the electronic settlement system in the United Kingdom).

Except as provided by the restrictions described below, every shareholder present at any general meeting has one vote on a show of hands and, on a poll, every shareholder present in person or by proxy has one vote for each share which they hold or represent.

Voting at all meetings of shareholders is by a show of hands unless a poll is demanded by the chairman of the meeting or by at least five shareholders at the meeting who are entitled to vote on the resolution (or their proxies), or by one or more shareholders at the meeting entitled to vote (or their proxies) and who have, between them, not less than 10% of the total votes of all shareholders who have the right to vote at the meeting; or by one or more shareholders at the meeting entitled to vote (or their proxies) who have, between them, shares conferring the right to vote on a resolution on which an aggregate sum has been paid up equal to not less than one-tenth of the total sum paid up on all the shares conferring that right.

No person is, unless the board decides otherwise, entitled to attend or vote at any general meeting or to exercise any other right conferred by being a shareholder at or in relation to meetings of the company in respect of any shares held by them if they or any person appearing to be interested in those shares have been sent a notice under section 212 of the Companies Act 1985 (which confers upon public companies the power to require information with respect to interests in their voting shares) and they or any interested person has failed to supply to the company the information requested within 14 days after delivery of that notice; and, in the case of any person who is interested or appears to us to be interested in shares representing at least 0.25% in nominal value of the issued shares of the class they shall additionally not be entitled to receive any dividend or other distribution or amount payable in respect of the default share, or to transfer or agree to transfer any of those shares or any rights in them. These restrictions continue until the earlier of:

(i)

Seven days after the earlier of the date the shareholder complies with the request to the board’s satisfaction or the company receives notice that there has been a market transfer or the shares; or

(ii)

if the board decides to waive these restrictions, in whole or in part.

At any general meeting, the necessary quorum is two persons present in person or by proxy and entitled to vote.

(b) A Shares

Our authorized share capital includes A shares, par value 60p. As of March 31, 2003, 80,908,247 A Shares were issued and outstanding. The A Shares do not carry any rights to receive notice of, attend, speak or vote at any general meeting, unless the meeting is due to consider a resolution for our winding up, or the non-cumulative preferential dividend remains unpaid six months or more after it fell due. Upon our winding up, the A Shares have preferential rights over the ordinary shares in respect of the distribution of capital. The A Shares confer no right to participate in our capital or profits beyond their nominal value. The A Shares are held in certificate and uncertificated (paperless) form.

Our authorized share capital includes one Special Share, a special rights redeemable preference share of £1. The Special Share may only be issued to, held by and transferred to one or more of Her Majesty’s Secretaries of State, another Minister of the Crown, the solicitor for the affairs of her Majesty’s Treasury or other person acting on behalf of the crown. The approval of the holder of the special share is required for certain matters, including alterations to our Memorandum of Association, certain of our Articles of Association, and certain other rights including the appointment of the chairman

of the board. The holder of the Special Share may require us to redeem the Special Share at par at any time after September 30, 2006.

(d) Limitation on Size of Shareholdings

The term “interest” is widely defined for the purpose of these provisions. It generally follows but is more extensive than the definition used in deciding whether a notification to the company would be required under Part VI of the Companies Act, 1985 (which contains requirements for the notification of interest in shares in public limited companies). Any person who has an interest in 3% or more of the voting shares in the company is required to notify the company of that interest and is otherwise required to give notices in relation to interests in voting shares as currently provided in Part VI of the Companies Act.

If, to the knowledge of the board, any person has an interest in the company’s shares which carry 15% or more of the total votes attaching to relevant share capital (as that expression is defined in the Act), the board shall send a written notice to all persons (other than certain persons referred to below) who appear to it to have such interests, and if different, to the registered holder(s) of the shares concerned. That notice will set out the restrictions referred to below and will call for the interest concerned to be reduced to less than 15% by sale or other disposal of shares within 21 days of giving the notice to the registered holder(s) (or such longer period as the board considers reasonable). No transfer of the shares comprised in the interest may be made except for the purpose of reducing the interest to less than 15% or if the notice sent by the board is withdrawn.

If that notice is not complied with to the satisfaction of the board and has not been withdrawn, the board must, so far as it is able, effect the disposal on the terms as it decides, based upon advice obtained by it for the purpose and being reasonably practicable having regard to all the circumstances.

A registered holder on whom a valid notice referred to above has been served is not entitled in respect of the share or shares comprised in the interest, until that notice has been complied with to the satisfaction of the board or withdrawn, to attend or vote at any general meeting of the company or meeting of the holders of a class of shares and those rights will vest in the chairman of the meeting who may act entirely at his discretion.

The board is not required to send a notice to any person if it does not know that person’s identity or address. Not delivering a notice in such case and any accidental error in or failure to give notice to a person to whom notice is required to be sent under this provision will not prevent the implementation of or invalidate any procedure under the relevant article. Any resolution or determination of, or decision or exercise of any discretion or power by, the board is final and conclusive.

Certain specified shareholders, including the ADR Depositary or a Clearing House, acting, in each case in that capacity are not subject to these restrictions.

(e) Variation of Rights

Whenever our share capital is split into different classes of shares, the special rights attached to any of those classes can be varied or withdrawn either:

(i)

in such manner as may be provided by those rights; or

(ii)

in the absence of such provision, either with the consent in writing of the holders of at least three-quarters in nominal value of the issued shares of that class or with the sanction of an extraordinary resolution passed at a separate general meeting of the holders of those shares validly held in accordance with the articles, but not otherwise.

Unless otherwise expressly provided by the terms of their issue, the rights attached to any class of shares shall not be deemed to be varied by the creation or issue of further shares ranking equally with them or subsequent to them or by the purchase or redemption by us of our own shares or by any other reduction of capital.

(f) Changes in Capital

We may by ordinary resolution:

(i)

increase our share capital by the creation of new shares of the amount prescribed by the resolution;

(ii)

cancel any shares which have not, at the date of the ordinary resolution, been taken or agreed to be taken by any person and which diminish the amount of our share capital by the amount of the shares so cancelled;

(iii)

consolidate and divide all or any of our share capital into shares of a larger amount than its existing shares; and

(iv)

sub-divide all or part of our share capital into shares of a smaller amount than is fixed by the memorandum or articles;

We may also:

(i)

by extraordinary resolution passed at a separate meeting, buy back our own shares; and

(ii)

by special resolution reduce our share capital, any capital redemption reserve and any share premium account.

(g) Dividends

We may declare dividends by passing an ordinary resolution. No dividend can exceed the amount recommended by the directors. The board may declare and pay such dividends as appear to be justified by the profits available for distribution. If the directors consider that our profits justify such payments, they can pay interim dividends on any class of shares of the amounts and on the dates and for the periods they decide. Fixed dividends will be paid on any class of share on the dates stated for the payments of those dividends.

The directors can (with the authority of an ordinary resolution of shareholders) offer ordinary shareholders the right to choose to receive new ordinary shares, which are credited as fully paid, instead of some or all of their cash dividend. To date, we have not sought such approval.

Any dividend which has not been claimed for 12 years after it was declared or became due for payment may be forfeited and will belong to us unless the directors decide otherwise.

We can stop paying dividends to a shareholder if payments for two dividends in a row are sent back or not cashed or have not been able to be made, until the shareholder or a person entitled to the shares by transmission claims them.

In view of British Energy’s financial situation, no interim or final dividend was paid in the financial year 2002-2003. The Board does not expect to declare or propose any dividend on the ordinary or “A” shares prior to the completion of the proposed restructuring.

(h) Distribution of Assets on Winding Up

If we are in voluntary liquidation the liquidator may, with the sanction of an extraordinary resolution passed by the shareholders, and any other sanction required by law, divide among shareholders all or any part of the assets of the company. This applies whether the assets consist of property of one kind or different kinds. For this purpose, the liquidator can place whatever value the liquidator considers fair on any property and decide how the division is carried out between shareholders or different groups of shareholders or; vest the whole or any part of the assets or class of assets in trustees upon such trusts for the benefit of shareholders as the liquidator shall determine.

(i) Transfer of Shares

Our certificated shares may be transferred in writing either by an instrument of transfer in the usual standard form or another form approved by the board. The transfer form must be signed or made effective by or on behalf of the person making the transfer. The person making the transfer will be treated as continuing to be the holder of the shares transferred until the name of the person to whom the shares are being transferred is entered in the register of members of the company. The board may, in its absolute discretion and without giving any reason for its decision, refuse to register the transfer of a certified share not fully paid up, or a certified share on which we have a lien.

The board may refuse to register any transfer of any share held in certified form:

•

which is in respect of more than one class of shares;

•

which is in favor of more than four joint holders;

•

unless it is left at the place decided by the board for registration;

•

unless the transfer form to be registered is properly stamped to show payment of any applicable stamp duty; and

•

unless the transfer has the share certificate for the shares to be transferred with it, together with any other evidence which the board asks for to prove that the person wanting to make the transfer is entitled to do this; and if the transfer form is executed by another person on behalf of the person making the transfer, evidence of the authority of that person to do so.

Transfers of uncertified shares must be carried out using a relevant system (as defined in Uncertificated Securities Regulations 1995 (the “Regulations”)). The board can refuse to register a transfer of an uncertified share in the circumstances stated in the Regulations.

If the board decides not to register a transfer of a share, they must notify the person to whom the share was to be transferred within two months of either the transfer, or the instruction from the operator of the relevant system being lodged with us.

The board can decide to suspend the registration of transfer, for up to 30 days a year, by closing the register of shareholders. The register must not be closed without the consent of the operator of a relevant system in the case of any relevant register relating to a particular security.

(j) Untraced Shareholders

We may sell any shares after advertising our intention and waiting for three months if the shares have been in issue for at last 12 years, during that period at least three dividends have become payable on them and have not been claimed and we have not heard from the shareholder or any person entitled to the dividends by transmission. We shall account for the proceeds to the former shareholder or the person entitled to them by transmission if that shareholder, or that other person, asks for them.

(k) General Meetings of Shareholders

Every year we must hold an annual general meeting. The board can call an extraordinary general meeting at any time, and, under general law, it must call one on a valid shareholder’s requisition.

(l) Limitations on Rights of Non-residents or Foreign Shareholders

There are no limitations imposed by the articles of association on the rights of non-residents on foreign shareholders.

(m) Directors

Directors’ Remuneration

The directors (other than alternate directors or those directors who hold an executive office or employment with the Company (or one of its subsidiaries), shall be paid out of the funds of the Company by way of remuneration for their services as directors such fees not exceeding in aggregate £500,000 a year (or such larger sum as British Energy may by ordinary resolution, determine) as the directors may decide to be divided among them in such proportion and manner as the board decides (or else equally). The directors shall also be paid their expenses properly incurred by them in connection with the discharge of their duties as our directors.

The board may grant special remuneration to a director who performs any special or extra services to or at the request of the board.

The board may provide pensions or other benefits to, among others, any director or former director or persons connected with them.

Directors’ Votes

A director need not be a shareholder, but a director who is not a shareholder can still attend and speak at shareholders’ meetings.

Unless the Articles of Association say otherwise, a director cannot vote on a resolution about a contract in which the director has a material interest (this will also apply to interests of a person connected with the director). The director can vote if the interest is only an interest in British Energy shares, debentures or other securities. A director can, however, vote and be counted in a quorum in respect of certain matters in which he is interested as set out in the articles.

Subject to the legislation, the shareholders can by passing an ordinary resolution suspend or relax, among other things, the provisions relating to the declaration of the interest of a director in any contract or arrangement or relating to a director’s right to vote and be counted in a quorum on resolutions in which he is interested to any extent or ratify any particular contract or arrangement carried out in breach of those provisions.

Directors’ Interests

If the legislation allows and the director had disclosed the nature and extent of the interest to the board, the director can:

(i)

have interest in a contract with or involving us (or in which we have an interest or with or involving another company in which we have an interest);

(ii)

have any interest in a company in which we have an interest;

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(iii)

hold a position (other than an auditor) in us or another company in which we have an interest or power of appointment; and

(iv)

along (or through some firm with which the director is associated) do paid professional work (other than as auditor) for us or another company in which we have an interest on terms and conditions decided by the board.

A director does not have to hand over to us any benefit received or profit made as a result of anything permitted to be done under the articles.

When a director knows that they are interested in a contract with us they must tell the other directors.

Retirement of Directors

Under the terms of the articles of association the appointment of a director or requirement for him to stop being a director is not restricted due to the fact that he has reached a particular age.

At every annual general meeting one third of the directors (or if their number is not a multiple of three, the number nearest to but not less than one third) must retire by rotation as directors. The directors to retire are selected on the basis of time in office since their last election. Any director appointed by the directors automatically retires at the next following annual general meeting, and is then eligible for election, but is not taken into account in determining which and how many directors are to retire by rotation at such meeting. A retiring director is eligible for re-election.

Exchange Controls and other Limitations Affecting Security Holders

There are no UK laws or regulations, including foreign exchange contracts that restrict the import or export of capital to or from the United Kingdom. Except as discussed in “Taxation” below, there are no restrictions on our payment of dividends or other amounts to non-UK resident holders of our securities. Except with respect to the Limitation, neither UK law nor our articles impose any restrictions on the rights of non-UK resident or non-UK citizen holders of our ordinary shares and ADSs to hold or to vote such securities.

Taxation

The following discussion describes certain US federal income tax and UK tax consequences of the acquisition, ownership and disposition of our ordinary shares or ADSs (evidenced by ADRs) to absolute beneficial owners of our ordinary shares or ADSs (as such term is used for UK tax purposes):

•

who are residents of the United States for purposes of the income tax convention between the United States and the United Kingdom;

•

whose ownership of our ordinary shares or ADSs are not, for the purposes of the income tax convention, attributable to a permanent establishment in the United Kingdom;

•

who otherwise qualify for the full benefits of the income tax convention; and

•

who are US holders (as defined below).

The statements of US federal income tax and UK tax laws set out below:

•

are based on the laws in force and as interpreted by the relevant taxation authorities as of the date hereof; and

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•

are subject to any changes in US federal income tax or UK tax law, in the interpretation thereof by the relevant taxation authorities, or in the income tax convention, occurring after the date hereof.

No assurance can be given that taxing authorities or the courts will agree with this analysis. For purposes of this discussion, the terms “we”, “us” and “our” refers to British Energy plc.

This discussion is not a complete listing of all potential tax consequences to a US Holder of the acquisition, ownership or disposition of our ordinary shares or ADSs, and does not address all aspects of UK taxation that may be relevant to a US holder and is not intended to reflect the individual tax position of any US holder, including tax considerations that rise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors.

The portions of this summary relating to US federal taxation are based upon the US Internal Revenue Code of 1986, as amended (the “Code”), its legislative history, existing and proposed US Treasury regulations promulgated thereunder, published rulings by the US Internal Revenue Service (“IRS”), and court decisions, all in effect as of the date hereof, all of which authorities are subject to change or differing interpretations, which changes or differing interpretations could apply retroactively. The portions of this summary relating to US federal taxation are limited to US Holders who hold our ordinary shares or ADSs as capital assets within the meaning of Section 1221 of the Code, generally, property held for investment, and does not purport to deal with investors in special tax situations, such as expatriates, dealers in securities or currencies, persons whose functional currency is not the US dollar and certain persons, including but not limited to life insurance companies, tax exempt entities, banks, financial institutions, traders in securities that elect to use a “mark-to-market” method of accounting for their securities holdings, regulated investment companies, persons holding our ordinary shares or ADSs as part of a hedging, integrated, conversion or constructive sale transaction or straddle or persons subject to the alternative minimum tax, who may be subject to special rules not discussed below. In particular, the following summary does not address the tax treatment to a US holder if the US holder owns, directly or by attribution, 10% or more of our outstanding voting share capital for US federal tax income purposes.

As used herein, the term “US holder” means a beneficial owner of our ordinary shares or ADSs who or which is for US federal income tax purposes:

•

a citizen or resident of the United States;

•

a corporation (or other entity treated as a corporation) created or organized in or under the laws of the United States or any political subdivision thereof;

•

an estate the income of which is subject to US federal income taxation regardless of its source; or

•

a trust (1) that is subject to the supervision of a court within the United States and the control of one or more US holders as described in section 7701(a)(30) of the Code or (2) that has a valid election in effect under applicable US Treasury regulations to be treated as a US holder.

If a partnership (or other entity treated as a partnership) holds our ordinary shares or ADSs, the US federal income tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If a US holders is a partner of a partnership holding our ordinary shares or ADSs, the US holder should consult its own tax advisors regarding the US federal income tax consequences of the partnership acquiring, owning and disposing of the shares or ADSs.

The summary does not include any description of the tax laws of any state, local or foreign governments that may be applicable to the acquisition, ownership and disposition of our

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ordinary shares or ADSs. Shareholders are urged to consult their own tax advisor regarding the US federal, state, and local tax consequences to them of the acquisition, ownership and disposition of shares or ADSs, as well as the tax consequences to them in the United Kingdom and any other jurisdictions arising from the acquisition, ownership or disposition of our ordinary shares or ADSs.

For the purposes of the income tax convention and the Code, a US holder will be treated as the owner of our ordinary shares represented by the ADSs evidenced by the ADRs.

New Income Tax Convention

The new income tax convention between the United States and the United Kingdom (the “New Convention”) has recently been ratified by the competent authorities in the two countries and entered into force on March 31, 2003. The New Income Tax Convention put in place new rules that modify the treatment of US holders under the previous income tax convention between the United States and the United Kingdom (the “Old Convention”) in several aspects. Specific references to the new rules under the New Convention have been included as appropriate throughout this summary. Each US holder should consult its own tax advisor regarding the effect of the New Convention on its investment in shares or ADSs.

Taxation of dividends

United Kingdom

No withholding tax is charged or due when a UK incorporated company pays dividends. An individual shareholder resident in the United Kingdom will generally be entitled to a tax credit in respect of any dividend received. The amount of the tax credit is equal to one-ninth of the cash dividend or 10% of the aggregate of the cash dividend and the associated tax credit. Under the terms of the Old Convention, the US holder might have been entitled to receive from the UK Inland Revenue, in respect of a cash dividend, a payment equal to the amount of the tax credit to which an individual resident in the United Kingdom for tax purposes would have been entitled had such resident received the dividend, reduced by an amount to be withheld from such payment not to exceed 15% of the sum of the dividend and the tax credit amount. However, at then applicable levels of tax credit available for a US resident individual (one-ninth of a dividend), in practice, no actual payment from the UK Inland Revenue was available. Under the New Convention, a US holder is no longer entitled to a payment from the UK Inland Revenue, in respect to the tax credit.

United States

Subject to the PFIC discussion below, generally, distributions a US holder receives from us will constitute dividend income to the extent paid out of our current and accumulated earnings and profits, as computed using US tax accounting principles, and, subject to discussions below, taxed at ordinary income tax rates applicable to the US Holder. Distributions in excess of our current and accumulated earnings and profits will first be treated as a nontaxable return on capital to the extent of the US holder’s adjusted tax basis (generally equal to the US holder’s acquisition cost of the shares or ADSs) in the shares or ADSs and then as gain from the sale or exchange of a capital asset. Dividends paid by us will not be eligible for the dividends received deduction that is applicable to US corporations. For the purposes of computing the foreign tax credit, dividends paid on our ordinary shares or ADSs are treated as income from sources outside the United States, but generally will be grouped separately, together with other items of “passive” or “financial services” income. The rules governing the foreign tax credit are complex. US holders should consult their own tax advisors regarding the availability of the foreign tax credit in their particular circumstances.

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The Jobs and Growth Tax Relief Reconciliation Act of 2003 (the “Act”) which became effective on May 28, 2003 modified various provisions of the Code relevant to the taxation of US Holders of our ordinary shares or ADSs. In particular, the Act reduces the maximum US federal income tax rate applicable to individual US Holders to a maximum 15% tax rate on certain types of dividends. The reduced rates of tax applies to the 2003 through the 2008 taxable years. Generally, dividends paid by a foreign corporation will be eligible for this reduced rate of tax if the foreign corporation (a) is not a “foreign personal holding company”, “foreign investment company” or “passive foreign investment company”, (b)(i) is eligible for benefits under a comprehensive income tax convention with the United States that satisfies certain requirements or (ii) the stock with respect to which the dividend is paid is readily tradable on an established securities market in the United States, and (c) certain other requirements met. Individual US Holders should consult their own advisors as to the eligibility of the reduced rate of tax to dividends paid by us.

During the periods the Old Convention was in effect, if a US holder were eligible for benefits under, and elected the application of, the Old Convention, the US holder would include in gross income, as dividends, an amount equal to the sum of the actual dividend plus the tax credit amount (to the extent such amount is paid out of our earnings and profits), and the US holder would be treated for US foreign tax credit purposes, as having paid UK withholding tax equal to the amount of the tax credit. A US holder could elect the application of the Old Convention by filing a timely and duly completed Form 8833 with the US holder’s income tax return for the relevant year. Subject to certain conditions and limitations, the UK deemed withholding tax could be deducted from taxable income, or instead credited against the US holder’s US federal income tax liability.

Under the New Income Tax Convention, the amount of dividends to be included in a US holder’s gross income no longer includes the amount any UK tax credit amount described above. Therefore, the amount of dividends that a US holder is treated as receiving from us will be the amount of dividends the US holder actually receive from us. US holders should consult their own tax advisors regarding the effects of the Old Convention and the New Convention on their investment in our ordinary shares or ADSs, and their eligibility for benefits under the Old Convention and the New Convention with respect to distributions from us.

The amount of any dividend paid in pounds sterling will equal the US dollar value of the pounds sterling received calculated by reference to the exchange rate in effect on the date the dividend is received by a US holder, in the case of shares, or by the Depositary, in the case of ADSs, regardless of whether the pounds sterling are converted into US dollars. If a US holder does not convert the pounds sterling received as a dividend into US dollars on the date of receipt, the US holder will have a basis in the pounds sterling equal to their US dollar value on the date of receipt. Generally, any gain or loss realized on the US holder’s subsequent conversion or other disposition of the pounds sterling will be treated as ordinary income or loss from US sources.

Taxation of capital gains

United Kingdom

If a US holder is not resident or ordinarily resident in the United Kingdom for UK tax purposes, the US holder is not be liable for UK tax on capital gains realized or accrued on the sale or other disposition of shares or ADSs unless the shares or ADSs are held in connection with the US holder’s trade or business (which for this purpose includes a profession or a vocation) carried on in the United Kingdom through a permanent establishment and the shares or ADSs are or have been used, held or acquired for the purposes of such trade or business or such permanent establishment.

A US holder who is an individual who has on or after March 17, 1998 ceased to be resident or ordinarily resident in the United Kingdom for a period of five years and who disposes of shares or

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ADSs during that period may also be liable for UK tax on capital gains notwithstanding that the person may not be resident in the United Kingdom at the time of the disposal.

United States

Subject to the PFIC discussion below, gain or loss realized by a US holder on the sale or other disposition of the shares or ADSs will be subject to US federal income tax as capital gain or loss in an amount equal to the difference between the US holder’s adjusted tax basis in the shares or ADSs and the amount realized on the disposition. The capital gain or loss will be long-term capital gain or loss if the US holder has held the shares or ADSs for more than one year at the time of the sale or exchange. In the case of individual US Holders, the Act reduces the maximum long-term capital gains tax rate to 15% for sales and exchanges occurring on or after May 6, 2003 through 2008. Gain or loss realized by a US holder generally will be treated as US source gain or loss for US foreign tax credit purposes.

Passive foreign investment company considerations

Generally, for US federal income tax purposes, we will be a “passive foreign investment company”, or a “PFIC”, for any taxable year if either (i) 75% or more of our gross income is “passive” income or (ii) 50% or more of the value of our assets, determined on the basis of a quarterly average, is attributable to assets that produce or are held for the production of passive income. Passive income generally includes dividends, interest, royalties and rents not arising from the active conduct of a trade or business, and gains from the sale of assets that produce such income. If we are a PFIC in any taxable year that a US holder owns our ordinary shares or ADSs, the US holder may be subject to tax at ordinary income rates on (a) a portion of any gain recognized on the sale of our ordinary shares or ADSs and (b) any “excess distribution” paid on our ordinary shares or ADSs (generally, a distribution in excess of 125% of the average annual distributions paid by us in the three preceding taxable years). In addition, any dividends paid by us that would otherwise be eligible for the reduced rate of tax as discussed above, will not be eligible for such reduced rate of tax if we are a PFIC.

Based on our current activities and assets, we do not believe that we are a “passive foreign investment company” or a “PFIC”, and we do not expect to become a PFIC in the foreseeable future for US federal income tax purposes. The determination of whether we are a PFIC is made annually. Accordingly, it may be possible that we will become a PFIC in the current or any future year due to changes in our asset or income composition.

UK stamp duty and stamp duty reserve tax

Subject to certain exemptions, stamp duty will be charged at the rate of 1.5% rounded up to the nearest £5, or there will be a charge to the stamp duty reserve tax at the rate of 1.5% on the amount or value of the consideration paid, or in some circumstances the issue price or open market value, on a transfer or issue of shares (1) to, or to a nominee for, a person whose business is or includes the provision of clearance services, or (2) to, or to a nominee for, a person whose business is or includes the issuing of depositary receipts. It is assumed that the UK Inland Revenue Stamp Office considers the depositary to fall within one or the other of the above two categories. The stamp duty reserve tax on the deposit of Shares with the depositary will be payable, pursuant to the terms of the deposit agreement among British Energy plc, Morgan Guaranty Trust Company of New York, as depositary, and the holders of ADRs, dated as of June 26, 1996, by the holders of the ADRs. Where stamp duty reserve tax is charged on a transfer of shares and ad valorem stamp duty is chargeable on the instrument effecting the transfer, the amount of the stamp duty reserve tax charged is an amount equal to the excess, if any, of the stamp duty reserve tax charge due on the transfer after the deduction of the stamp duty paid.

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For US federal income tax purposes, a US holder will not be entitled to a foreign tax credit with respect to any UK stamp duty or stamp duty reserve tax, but may be entitled to a deduction subject to applicable limitations under the Code. US holders are urged to consult their own tax advisors regarding the availability of a deduction under their particular circumstances.

Transfers of ADRs

No UK stamp duty will be payable on an instrument transferring an ADR or on a written agreement to transfer an ADR provided that the instrument of transfer or the agreement to transfer is executed and remains at all times outside the United Kingdom. Where these conditions are not met, the transfer of, or agreement to transfer an ADR could, depending on the circumstances, attract a charge to ad valorem stamp duty at the rate of 0.5% of the value of the consideration (rounded up to the nearest £5.00) plus interest and penalties if not stamped within 30 days of execution.

No stamp duty reserve tax will be payable in respect of an agreement to transfer an ADR, whether made in or outside the United Kingdom.

Where no sale is involved and no transfer of beneficial ownership has occurred, a transfer of shares by the depositary or its nominee to the holder of an ADR upon cancellation of the ADR is subject to UK stamp duty of £5.00 per instrument of transfer.

Issue and transfer of Shares in registered form

Except in relation to persons whose business is or includes the issue of depositary receipts or the provision of clearance services or their nominees, the allotment and issue of shares by us will not normally give rise to a charge to UK stamp duty or stamp duty reserve tax.

Transfers of shares, as opposed to ADSs, will attract ad valorem stamp duty normally at the rate of 0.5% of the value of the consideration (rounded up to the nearest £5.00). A charge to stamp duty reserve tax, normally at the rate of 0.5% of the consideration, arises, in the case of an unconditional agreement to transfers shares, on the date of the agreement, and in the case of a conditional agreement the date on which the agreement becomes unconditional. In the case of transfers effected through the CREST system, the stamp duty reserve tax is collected through the system. In other cases, the stamp duty reserve tax is payable on the seventh day of the month following the month in which the charge arises. Where an instrument of transfer is executed and duly stamped before the expiry of a period of six years beginning with the date of that agreement, any stamp duty reserve tax that has not been paid ceases to be payable, and if any stamp duty reserve tax has been paid a claim may be made for its repayment provided that the tax paid is not less than 25 pounds sterling.

Information reporting and backup withholding

Payments that relate to the shares or ADSs that are made in the United States or by a US related financial intermediary will be subject to information reporting. Information reporting generally will require each paying agent making payments, which relate to a share or ADS, to provide the US Internal Revenue Service, or the IRS, with information, including the beneficial owner’s name, address, taxpayer identification number, and the aggregate amount of dividends paid to such beneficial owner during the calendar year. These reporting requirements, however, do not apply to all beneficial owners. Specifically, corporations, securities broker-dealers, other financial institutions, tax-exempt organizations, qualified pension and profit sharing trusts and individual retirement accounts are all excluded from reporting requirements.

We may be required to withhold, as a backup against a US holder’s US federal income tax liability, a portion of each payment of dividends on our ordinary shares or ADS in the event that the US holder:

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•

fails to establish its exemption from the information reporting requirements;

•

is subject to the reporting requirements described above and fails to supply its correct taxpayer identification number in the manner required by applicable law; or

•

underreports its tax liability; or

•

if we are otherwise notified by the IRS.

This backup withholding tax is not an additional tax and may be credited against the beneficial owner’s US federal income tax liability if the required information is furnished to the IRS.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following discussions about our risk management activities include “forward-looking” statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward-looking statements.

The following tables summarize the financial instruments, derivative instruments and derivative commodity instruments held by us at March 31, 2003, which are potentially sensitive to changes in interest rates, foreign exchange rates, commodity prices and equity markets. We use foreign exchange contracts and other derivative instruments to hedge the primary market exposures associated with our underlying assets, liabilities and committed transactions. None of the instruments we have entered into are leveraged or held for speculative purposes. We use fixed rate interest rate borrowings and deposits to reduce our exposure to fluctuations in interest rates.

Financial Instruments and Risk Management

Overview

The main financial risks we face are interest rate risk (on cash deposits and borrowings), exchange rate risk (principally on fuel purchases) and, under NETA, trading risk in England and Wales in respect of both price and output volume on the sale of our electricity. We are also exposed to risk associated with fluctuations in the equity markets through the Decommissioning Funds and Pension Schemes. See “Item 4. Information on the Company—Decommissioning in the United Kingdom—Decommissioning Fund”. We have instituted policies for managing each of these risks, which have been approved by the board of directors. Each of these risks is discussed in more detail below.

Our electricity trading risks are managed by the Power and Energy Trading Division. The Power and Energy Trading Division operate within policies and procedures approved by the board of directors on the recommendation of the executive director acting on the advice of the Trading Risk Sub- Committee, which is a Sub-committee to the Group Risk Management Committee.

Non-trading risks (i.e. cash resources, debt finance and financial risks) are managed by the central treasury function (the “Treasury”). The Treasury operates within policies and procedures approved by the board of directors on the recommendation of the Finance Director acting on the advice of an executive committee. The Treasury function uses appropriate instruments, within specified limits, to manage financial risk but is not permitted to take speculative, open positions. Both the Treasury and the Power and Energy Trading Division are subject to regular scrutiny from our internal and external auditors.

Interest Rate Risk Management

We currently minimize our exposure to interest rate fluctuations by investing our funds in fixed rate instruments and by maintaining at least 50% of borrowings in fixed rate instruments. As at March 31, 2003, 100% of debt was either at a fixed or capped rate when taking into account interest rate contracts.

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Debt at March 31, 2003 comprised a project finance loan of £475 million, and bonds in an aggregate principal amount of £408 million. Debt at March 31, 2002 comprised drawn down bank facilities of £6 million, a project finance loan of £508 million, a Canadian dollar term loan of £42 million, a Canadian dollar loan from OPG relating to the Bruce lease of £104 million and bonds in an aggregate principal amount of £408 million. The bonds mature between 2003 and 2016 and bear interest at fixed rates, ranging between 5.9% and 6.2%, with a weighted average rate of 6.1%.

There were short-term foreign currency denominated borrowings totaling £6 million in place at March 31, 2002 and long-term foreign currency denominated borrowings of £146 million. There were short-term foreign currency denominated borrowings of £6 million in place at March 31, 2001.

The market value of our debt varies, with fluctuations in prevailing interest rates in the United Kingdom. The debt is analyzed as follows:

	Expected Maturity Date								Fair Value at March 31
Liabilities	2003	2004	2005	2006	2007	2008	There- after	Total	2003	2002
	(in millions of pounds, except percentages)
Fixed rate bond due 2003 at 5.949%⁽¹⁾	110	—	—	—	—	—	—	110	46	110
Fixed rate bond due 2006 at 6.077%⁽¹⁾	—	—	—	163	—	—	—	163	69	159
Fixed rate bond due 2016 at 6.202%⁽¹⁾	—	—	—	—	—	—	135	135	56	119
Long-term—project finance loan—sterling⁽¹⁾	—	42	45	48	52	56	232	475	150	508
Weighted average interest rate, %	5.95	5.34	5.34	5.91	5.34	5.34	5.66	5.68	—	—

⁽¹⁾

We have entered into the following interest rate agreements to swap £475 million of our variable rate debt to fixed rate debt.

Maturity Analysis of Interest Rate Contracts	2004		2005		2006	2007	2008	Fair Value
	(in millions of pounds, except percentages)
Variable to Fixed:
Notional Amounts	377		356		332	291	235	(47	)
Average Pay Rate	6.6%		6.6%		6.6%	6.6%	6.6%
Average Receive Rate	6M LIBOR		6M LIBOR		6M LIBOR	6M LIBOR	6M LIBOR
Notional Amounts*	30		30
Average Pay Rate	5.8%		5.8%					(3	)
Average Receive Rate	6M LIBOR		6M LIBOR

Collars:
Notional Amounts**	70		70
Collar Spread	5.3%-6.8	%	5.3%-6.8	%				(6	)

Bank has the right to cancel swap at zero cost on any cancellation date from April 2005 and every year thereafter.

Banks have the right to enter into semi-annual swap receiving 5.25% and paying 6 month LIBOR for ten years at zero cost in April 2005.

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At March 31, 2003 we also held term deposits and bank balances totaling £333 million which had maturity dates entirely due within one year. Cash not immediately required for business purposes is invested in fixed-rate term deposits. At 31 March 2003, these term deposits were due to mature within one month and earned interest at an average rate of 3.7%. Term deposits and bank balances at 31 March 2003 include £209m of cash which has been deposited in collateral bank accounts for trading purposes, availability of this cash is therefore restricted over the period of the collateralised position. At March 31, 2002 we held short-term deposits totaling £209 million which had maturity dates of within one year.

Because the deposit terms are short term, the carrying value at March 31, 2003 approximates the fair market value.

Foreign Exchange Risk Management

The Group has reduced exposure to foreign currency exchange rate movements following the disposal of its investments in Bruce Power and Huron Wind. There are potential future foreign currency receivables in respect of the retentions outstanding from the sale of Bruce Power and the potential sale of AmerGen. When these cash flows become more certain in the future, the Group will evaluate currency hedging opportunities, balancing the cost and availability of entering into such transactions against the underlying currency risk.

At March 31, 2003 we had no foreign exchange contracts in place.

At March 31, 2002 we had forward foreign exchange contracts with a principal value of £5 million which had a fair market value of £1 million (gain). In addition, at March 31, 2003, there were deferred losses of £2 million accounted for as part of stock which arose on the rollover of maturing forward contracts used for hedging the future purchase of fuel prior to and including the year ended March 31, 2003. See Note 21 to our consolidated financial statements. The equivalent deferred losses for the years ended March 31, 2002 and 2001 each accounted for as part of inventory approximated £10 million and £20 million respectively.

The underlying fuel purchase commitments as at March 31, 2003 are analyzed as follows:

	Expected Maturity Date					Fair Value at March 31
Total fuel commitments per currency (millions) as at March 31, 2003	2004	2005	2006	2007	Thereafter	Total 2003	2002
US Dollars	66.8	33.4	29.0	14.9	0	144.1	92.2
Euros	8.5	—	—	—	—	8.5	0.4

We do not have significant commodity price exposure in relation to our procurement of nuclear fuels.

Electricity Trading Risk Management

Our trading activities principally relate to supporting our generating business. Our trading operations, therefore, principally act as wholesale marketers rather than as pure financial traders, with the principal objective of increasing the return on our assets while hedging the market risk associated with the output of the plants.

Under NETA any mismatch between actual metered generation (or demand) and the notified contract position is exposed to the prices in the balancing mechanism run by the grid system operator.

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Based on experience to date prices in the balancing mechanism encourage forward contracting, as the price for spilling energy to the system tends to be lower than the forward market price, whereas the price for purchasing top-up supplies tends to be higher than the forward market price.

We manage the risks in the new wholesale market through a contracting strategy that builds a portfolio of forward contracts with a variety of terms. Contracts are sold through several routes to market including bespoke bilateral contracts, brokered over-the-counter trades in standard products, exchange trading and direct sales to industrial and commercial customers. The objective is to sell forward all of our planned nuclear generation in England and Wales ahead of delivery. Eggborough provides a flexible generation capability which fulfils three purposes designed to enhance our profitability. Firstly, it provides a means for compensating for unplanned lost output from nuclear units at short notice; secondly, it provides the capability to profile the generation shape to meet the requirements of both wholesale and directly-supplied customers; and thirdly, it provides a flexible capability that is offered to the system operator via the balancing mechanism. Output from our two stations in Scotland will continue to be sold under the terms of the NEA to ScottishPower and Scottish and Southern Energy, until April 2006, or the introduction of BETTA, whichever is earlier.

Our policy is to manage our credit exposure to trading and financial counterparties within clearly defined limits. Electricity trading activities are strictly monitored and controlled through delegated authorities and procedures, which include specific criteria for the management of counterparty credit exposures.

Equity Risk Management

The Decommissioning Fund was established to provide for the eventual decommissioning of our UK nuclear power stations. Cash contributions are made on a quarterly basis to a payment profile set out in a contract between us and the Decommissioning Fund and are invested by the trustees of the Decommissioning Fund in UK marketable fixed income debt, equity securities and property. We are solely responsible for contributions to the Decommissioning Fund. Therefore the level of future contributions, which are reviewed every five years in conjunction with our review of ultimate decommissioning costs, depend partly on the estimated long-term investment performance of the equity and debt instruments in which the contributions are invested and returns on investments in property. Income from dividends and other returns on the underlying investments are retained by the Decommissioning Fund and then invested in debt and equity securities.

At March 31, 2003 we reported a book value of £334 million in the Decommissioning Fund, which is the same as the market value as at March 31, 2003. The Decommissioning Fund included debt and equity securities with market values of £26 million and £265 million respectively.

ITEM 13. DIVIDEND ARREARAGES AND DELINQUENCIES

(a) On

June 3, 2002 the Company announced that it did not expect to pay any dividends prior to the completion of restructuring. No dividends were paid to holders of A shares on the 11 August 2003 payment date.

(b)

There has been no material default in the payment of principal, interest, a sinking or purchase fund installment, or any other material default not cured within 30 days, with respect to any of our indebtedness or to that of any of our significant subsidiaries exceeding 5% of our total assets and its consolidated subsidiaries.

(c)

There has been no material delinquency (including a material arrearage in the payment of dividends) not cured within 30 days with respect to any class of our preferred stock which is

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registered or which ranks prior to any class of registered securities or with respect to any class of preferred stock of any of our significant subsidiaries.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

(None)

ITEM 15. CONTROLS AND PROCEDURES

As recommended by the U.S. Securities and Exchange Commission, or SEC, we have established a Disclosure Controls Committee. The Disclosure Controls Committee reports to our Chief Executive Officer, Finance Director and to the Audit Committee. It is chaired by the Group Financial Controller and the members consist of senior managers from operations finance, legal, internal audit and investor relations. It has responsibility for considering the materiality of information and on a timely basis, determination of the disclosure and treatment of material information. The Disclosure Controls Committee also has responsibility for the timely filing of reports with the SEC and the formal review of the contents of our Annual Report on Form 20-F.

Our Chief Executive Officer and our Finance Director, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c)) as of a date (the “Evaluation Date”) within 90 days before the filing date of this annual report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were effective to ensure that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported in a timely manner.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of such controls and procedures. In addition, we have limited influence over the controls and procedures of entities in which we hold a minority interest. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Changes in Internal Controls

There were no significant changes in our internal controls or, to our knowledge, in other factors that could significantly affect such controls subsequent to the Evaluation Date.

ITEM 16. [RESERVED]

ITEM 17. FINANCIAL STATEMENTS

See “Item 18. Financial Statements”.

ITEM 18. FINANCIAL STATEMENTS

See pages F-1 to F-73.

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ITEM 19. EXHIBITS

1.01		Articles of Association of British Energy plc, as amended.

1.02		Memorandum of Association of British Energy plc.*

4.01		Trust Deed, dated March 25, 1999 among British Energy plc, British Energy Generation Limited, British Energy Generation (UK) Limited and The Law Debenture Trust Corporation constituting £134,586,000 6.202% Guaranteed Bonds due 2016 and £163,444,000 6.077% Guaranteed Bonds due 2006 and £109,861,000 5.949% Guaranteed Bonds due 2003 guaranteed by British Energy Generation Limited and British Energy Generation (UK) Limited.*

4.02		Master Purchase Agreement dated January 17, 2003 for the disposal of British Energy’s interest in Bruce Power Limited Partnership was entered into between, amongst others, British Energy and (i) Cameco Corporation, (ii) BPC Generation Infrastructure Trust and (iii) TransCanada Pipelines Limited.

4.03		Standstill Agreement dated February 14, 2003 between British Energy plc and (i) the steering committee of the Eggborough Bank Syndicate, (ii) The Royal Bank of Scotland plc as provider of a letter of credit to the Eggborough Banks, (iii) Teesside Power Limited, (iv) TotalFinaElf Gas and Power Limited, (v) Enron Capital & Trade Europe Finance LLC and (vi) British Nuclear Fuels plc.

4.04		Bondholder Restructuring (Standstill) Agreement dated February 14, 2003 between British Energy plc, British Energy Generation Limited and British Energy Generation (UK) Limited and (i) certain Bondholders owning 58% of the £109,861,000 5.949% Guaranteed Bonds due 2003, (ii) certain Bondholders owning 55% of the £163,444,000 6.077% Guaranteed Bonds due 2006 and (iii) certain Bondholders owning 75% of the £134,586,000 6.202% Guaranteed Bonds due 2016.

4.05		The Deed of Amendment and Guarantee between British Energy Generation Limited, British Nuclear Fuels plc (“BNFL”) and British Energy plc dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the supply of Fuel for Use in Advanced Gas Cooled Reactors between Nuclear Electric Limited and BNFL dated June 3, 1997, as amended.†

4.06		Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003, (as amended on July 22, 2003).†

4.07		Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended on July 22, 2003.)†

4.08		Deed of Amendment and Guarantee between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Nuclear Reactors between Scottish Nuclear and BNFL dated March 30, 1995 as amended.†

4.09		Nuclear Electric – Generation License.*

4.10		Scottish Nuclear – Generation License.*

4.11		Representative Nuclear Site License.*

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4.12		Credit Facility Agreement dated September 26, 2002 as amended and restated on March 7, 2003 and further amended by a side letter dated August 15, 2003 between the UK Secretary of State and (i) British Energy, British Energy General (UK) Limited, British Energy Generation Limited and British Energy Power and Energy Trading Limited as borrowers and (ii) British Energy, British Energy General (UK) Limited, British Energy Generation Limited, British Energy Power and Energy Trading Limited, British Energy Investment Limited, District Energy Limited, British Energy International Holdings Limited, British Energy US Holdings Inc., British Energy L.P. and Peel Park Funding Limited as guarantors.

8.01		List of Subsidiaries of British Energy plc.#

12.01		Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act 2002.

As filed on the registrants’ Registration Statement submitted on Form 20-FR on December 6, 1999 (File No. 1-14990).

As filed on the registrants’ Registration Statement submitted on Form 20-F on August 13, 2001 (File No. 1-14990).

†

Confidential treatment requested as to certain portions, which portions are omitted and filed separately with the Commission.

The registrant agrees to furnish to the Securities and Exchange Commission upon request a copy of any instrument which defines the rights of holders of long-term debt of British Energy and its consolidated subsidiaries.

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the Registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

BRITISH ENERGY plc

By:		/s/ KEITH LOUGH

Name:		Keith Lough
Title:		Finance Director

September 23, 2003

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CERTIFICATION

I, Mike Alexander, Chief Executive Officer of British Energy plc, certify that:

I have reviewed this annual report on Form 20-F of British Energy plc, (the “registrant”);

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

(c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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CERTIFICATION

I, Keith Lough, Finance Director of British Energy plc, certify that:

I have reviewed this annual report on Form 20-F of British Energy plc, (the “registrant”);

(a)

(b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

(c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

(a)

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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US FORM 20-F

Financials

F-1

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Members of British Energy plc:

We have audited the accompanying consolidated balance sheets of British Energy plc and its subsidiaries, together “the Group”, as of March 31, 2003 and 2002, and the related consolidated statements of profit and loss account, cash flows, and total recognized gains and losses for each of the three years in the period ended March 31, 2003. 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 in accordance with auditing standards generally accepted in the United States of America and the United Kingdom. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of British Energy plc and its subsidiaries as at March 31, 2003 and 2002, and the results of their operations and their cashflows for each of the three years in the period ended March 31, 2003 in conformity with accounting principles generally accepted in the United Kingdom.

The accompanying financial statements have been prepared assuming that the Group will continue as a going concern. As discussed in Note 1(ii) to the financial statements, the validity of this depends on the continuation of the financial assistance from the Secretary of State for Trade and Industry and the Group’s significant creditors and the successful completion of financial restructuring. In view of the significance of the uncertainty concerning the continuation of financial assistance from the Secretary of State for Trade and Industry and the Group’s significant creditors and the successful completion of financial restructuring, together with the losses from operations and net capital employed deficiency, there is substantial doubt about the Group’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1(ii). The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Accounting principles generally accepted in the United Kingdom vary in certain significant respects from accounting principles generally accepted in the United States of America. The application of the latter would have affected the determination of consolidated net income for each of the three years in the period ended March 31, 2003 and the determination of consolidated shareholders’ funds, as at March 31, 2003 and 2002 to the extent summarized in Note 37 to the consolidated financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants and Registered Auditors

Edinburgh, United Kingdom

June 2, 2003

F-2

GROUP PROFIT AND LOSS ACCOUNTS

For the years ended March 31, 2003, 2002 and 2001

	Notes	2003		2002		2001
						(restated)
		£m		£m		£m
Turnover: Group and share of joint venture		2,115		2,259		2,293
Less: Share of turnover in joint venture		(212	)	(210	)	(169	)

Turnover:
—continuing activities		1,528		1,701		1,954
—discontinued activities		375		348		170

Turnover	3	1,903		2,049		2,124

Operating costs before exceptional items	4	(1,758	)	(1,818	)	(1,898	)
Exceptional items	4	(3,947	)	(512	)	54

Operating costs after exceptional items	4	(5,705	)	(2,330	)	(1,844	)

Group operating (loss)/profit:
—continuing activities		(3,899	)	(333	)	284
—discontinued activities		97		52		(4	)

Group operating (loss)/profit		(3,802	)	(281	)	280
Share of operating profit of joint venture		43		37		6

Operating (loss)/profit: group and share of joint venture		(3,759	)	(244	)	286

(Loss)/profit on sale of investments	6	(35	)	4		(5	)

Financing (charges)/credits
—revalorization	9	(205	)	(160	)	(173	)
—net interest payable	9	(72	)	(66	)	(56	)
—exceptional items	9	(221	)	(27	)	5

(Loss)/profit on ordinary activities before taxation		(4,292	)	(493	)	57
Taxation on (loss)/profit on ordinary activities	10	378		4		(47	)
Share of taxation for joint venture		(10	)	(29	)	(1	)

(Loss)/profit on ordinary activities after taxation		(3,924	)	(518	)	9
Minority interest		(17	)	(9	)	—

(Loss)/profit attributable to shareholders		(3,941	)	(527	)	9
Dividends
—annual	12	—		(48	)	(48	)
—non-equity ‘A’ share dividend (relating to return of value)	12	—		—		—
—non-equity	12	—		(2	)	(2	)

Loss for the year		(3,941	)	(577	)	(41	)

(Loss)/earnings per share (p)
—basic	13	(654.7	)	(88.5	)	1.2
—diluted	13	(654.7	)	(88.5	)	1.2

Dividends per share (p)
—annual	12	—		8.0		8.0
—non-equity ‘A’ share dividend (relating to return of value)	12	—		—		—
—non-equity	12	—		2.3		2.9

Other gains and losses for the years are set out in the Statement of Total Recognized Gains and Losses on Page F5.

Notes 1 to 37 form part of these financial statements.

F-3

BALANCE SHEETS

as at March 31, 2003 and 2002

		Group				Company
	Notes	2003		2002		2003		2002
		£m		£m		£m		£m
Fixed assets
Tangible assets	14	686		4,714		—		39
Investment in joint venture:
—share of gross assets		477		544		—		—
—share of gross liabilities		(406	)	(457	)	—		—
	15	71		87		—		—
Other investments	15	6		108		14		19

		763		4,909		14		58

Current assets
Decommissioning fund	16	334		411		—		—
Stocks	17	360		514		—		—
Debtors: amounts falling due within one year		331		412		85		2,517
Debtors: amounts falling due after more than one year		56		320		—		—
	18	387		732		85		2,517
Investments—liquid funds	32	246		209		210		179
Cash at bank	32	87		—		83		—

		1,414		1,866		378		2,696

Creditors: amounts falling due within one year
—borrowings	20	(152	)	(153	)	(110	)	(116	)
—other	19	(1,033	)	(822	)	(3,742	)	(49	)
		(1,185	)	(975	)	(3,852	)	(165	)

Net current assets/(liabilities)		229		891		(3,474	)	2,531

Total assets less current liabilities		992		5,800		(3,460	)	2,589

Creditors: amounts falling due after more than one year
—borrowings	20	(731	)	(915	)	(298	)	(298	)
—other	19	(1,909	)	(1,858	)	—		—
Provisions for liabilities and charges	22	(1,735	)	(2,400	)	(9	)	—

Net (liabilities)/assets		(3,383	)	627		(3,767	)	2,291

Capital and reserves
Called up equity share capital	27	277		277		277		277
Share premium		76		76		76		76
Capital redemption reserve		350		350		350		350
Profit and loss account	28	(4,179	)	(213	)	(4,563	)	1,495

Equity shareholders’ interests	29	(3,476	)	490		(3,860	)	2,198

Non-equity shareholders’ interests	27	93		93		93		93
Minority interests		—		44		—		—

Capital employed		(3,383	)	627		(3,767	)	2,291

Notes 1 to 37 form part of these financial statements.

F-4

GROUP CASH FLOW STATEMENTS

for the years ended March 31, 2003, 2002 and 2001

	Notes	2003		2002		2001
		£m		£m		£m
Net cash inflow from operating activities	30	336		380		277

Interest paid		(91	)	(62	)	(65	)
Interest received		9		13		10
Fees paid		—		(2	)	(7	)
Dividends paid on non-equity shares		(2	)	(2	)	(2	)

Returns on investments and servicing of finance		(84	)	(53	)	(64	)

Taxation received/(paid)		3		4		(37	)

Payments to acquire tangible fixed assets		(282	)	(225	)	(133	)
Payments to acquire financial investments		—		—		(1	)
Receipts from sales of financial investments		—		38		7

Capital expenditure and financial investment		(282	)	(187	)	(127	)

Receipts from sale of Swalec		—		—		210
Receipts from sale of Canadian investment		262		—		—
Investment in North America		—		(129	)	(31	)

Acquisitions and disposals		262		(129	)	179

Equity dividends paid		(31	)	(46	)	(29	)

(Increase)/decrease in term deposits		(37	)	18		(190	)

Management of liquid resources	32	(37	)	18		(190	)

Minority funding of Bruce Power		12		4		—
New loans, net of repayments of amounts borrowed		(92	)	9		(9	)

Financing		(80	)	13		(9	)

Movement in cash	32	87		—		—

STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES

for the years ended March 31, 2003, 2002 and 2001

	Notes	2003		2002		2001
						(restated)
		£m		£m		£m
(Loss)/profit for the financial year		(3,941	)	(527	)	29
Translation differences on foreign currency net investments	28	(25	)	(8	)	6

Total recognized (losses)/gains for the year		(3,966	)	(535	)	35
Prior year adjustment in respect of accounting policy changes		—		(130	)	—

Total recognized (losses)/gains since last annual report		(3,966	)	(665	)	35

Notes 1 to 37 form part of these financial statements.

F-5

NOTES FOR FINANCIAL STATEMENTS

for the year ended March 31, 2003

1. BASIS OF PREPARATION

(i) Introduction

The Group accounts are a consolidation of the financial statements of the Company and all its subsidiary undertakings, and are drawn up on a non-restructured basis, i.e. on the basis of contracts and agreements in place at March 31, 2003.

On February 14, 2003, the Group disposed of its stake in Bruce Power and Huron Wind therefore their results up to the point of disposal have been classified as discontinued operations. All other activities of the Group have been shown as continuing activities.

(ii) Principles Underlying Going Concern Assumption

Having reviewed the longer-term prospects of the business, on September 5, 2002 the Directors of British Energy announced that they had no alternative but to seek financial support from the UK Government. On September 9, 2002 the UK Government granted the Company a credit facility of up to £410m to provide working capital for British Energy’s immediate requirements and to allow British Energy to stabilize its trading position in the UK and North America. On September 26, 2002 British Energy announced that the UK Government had agreed to extend a revised facility for up to £650m until November 29, 2002 to give the Company sufficient opportunity to develop a restructuring plan.

On November 28, 2002 British Energy announced that the facility agreement had been further extended until March 9, 2003.

On March 7, 2003 British Energy announced that the UK Government had agreed to extend the facility, which will now mature on the earlier of September 30, 2004 or the date on which the restructuring plan, as outlined below, becomes effective and which was reduced from £650m to £200m to provide working capital for the business and collateral to support UK trading operations. HMG is entitled to require immediate repayment of the facility if, in the opinion of the Secretary of State for Trade and Industry, the restructuring cannot be implemented in the manner envisaged. The facility agreement is cross-guaranteed by the principal Group subsidiaries (excluding Eggborough Power (Holdings) Limited and Eggborough Power Limited) and is secured by, among other things, fixed and floating charges and/or share pledges granted by those subsidiaries. The facility agreement also contains a requirement to provide further security as required by the Secretary of State for Trade and Industry provided that the creation of such security would not cause a material default under any contract to which any member of the Group is a party or is a breach of law.

On February 14, 2003 British Energy announced that it had entered into binding standstill agreements and had reached a non-binding agreement on the principles of the Company’s restructuring with certain of the bondholders, the steering committee of the Eggborough bank syndicate, The Royal Bank of Scotland plc as provider of a letter of credit to the Eggborough banks, Teesside Power Limited, TotalFinaElf and Enron Capital & Trade Europe Finance LLC.

The significant creditors and BNFL agreed with British Energy that they would not take any steps to initiate any administration proceedings or demand or accelerate any amounts due and payable by British Energy during the period commencing on February 14, 2003 and ending on the earliest of September 30, 2004 or a termination event or the completion of the restructuring.

F-6

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Under the standstill agreements certain significant creditors are paid interest but not principal in respect of any claims against the British Energy Group. The standstill agreements contain certain covenants for the benefit of the significant creditors and BNFL (including the bondholders who have signed the bondholders’ standstill agreement). For example, during the standstill period, British Energy has undertaken that it will not, without the unanimous consent of the significant creditors and BNFL, make any acquisition or disposal greater than £5 million (except for the sale of Bruce Power and AmerGen) and it will not issue equity or pay any dividends.

BNFL or any of the significant creditors may terminate the standstill agreement following the occurrence of a termination event. The termination events include certain insolvency events affecting the Company, British Energy Generation Limited, British Energy Generation (UK) Limited, British Energy Power & Energy Trading Limited or Eggborough Power Limited, acceleration of the repayment terms of the Facility, the required approvals under the standstill agreement not being obtained within the time scales envisaged, any of the British Energy companies failing to discharge certain continuing obligations and definitive documentation not having been executed by September 30, 2003.

The principal features of the proposed restructuring include:

•

the amendment and extension of the BNFL contracts for front-end and back-end related fuel services for the Group’s AGR stations announced on May 16, 2003 and the implementation of a new trading strategy

•

establishing a new Nuclear Liabilities Fund (“NLF”) for uncontracted nuclear liabilities and decommissioning costs to which British Energy would make initial and ongoing contributions

•

the Government funding liabilities relating to historic spent fuel and any shortfall in the NLF

•

compromising the existing claims of significant creditors in exchange for new bonds and new ordinary shares and settling new off-take arrangements for Eggborough

•

British Energy disposing of its interests in AmerGen as well as Bruce Power.

The Group’s ability to provide alternative credit support to parent company guarantees for our trading operations is, and will, until the completion of our proposed restructuring, be subject to our continued access to funds under the credit facility. We have retained a trading relationship with a high proportion of our existing contracted counterparties during the period since our announcement of September 5, 2002, although in most cases we have been required to provide alternative credit support to a parent company guarantee. Given the current circumstances of the Company and its subsidiaries, certain contracts may be capable of being terminated, such termination may result in termination payments being payable as well as having an adverse effect on our cash flows.

The financial statements have been prepared on a going concern basis in accordance with FRS18, because the entity has not been liquidated nor is it ceasing to trade and the Directors are currently seeking an alternative to liquidating the Company or ceasing to trade. The going concern basis assumes that the Company will continue in operational existence for the foreseeable future. The validity of this assumption depends on continuation of financial assistance from the Secretary of State for Trade and Industry and the Group’s significant creditors, and the successful completion of the proposed restructuring.

The terms of the proposed restructuring will need to be agreed definitively with the significant creditors whose entitlements are to be compromised and will need to be approved by, inter alia, the

F-7

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Secretary of State, existing shareholders (where required), the Inland Revenue and the European Commission (under State Aid rules) prior to being finally implemented. If such agreements with creditors cannot be reached, the standstill arrangements are terminated, the required approvals are not forthcoming, the assumptions underlying the restructuring proposals are not fulfilled, the UK Government credit facility is not maintained or the conditions to the restructuring are not satisfied or waived, in each case within the time scales envisaged, the Company may be unable to meet its financial obligations, in which case the Company could no longer be considered to be a going concern.

If for any reason British Energy is unable to implement the restructuring and ceases to be a going concern, adjustments may have to be made to reduce the monetary values of assets to the recoverable amounts, to provide for further liabilities that might arise and to reclassify the fixed assets and long term liabilities as current assets and liabilities.

2. ACCOUNTING POLICIES

(i) Basis of Accounting

The financial statements are prepared under the historical cost convention and in accordance with applicable accounting standards, except for the departures noted below.

Certain energy trading financial derivatives and open positions on physical energy trading contracts are marked to market using externally derived market prices. This is a departure from the general provisions of Schedule 4 of the Companies Act 1985. An explanation of this departure is given in note 2(xviii).

The income recognised by the Group in respect of the long-term rate of return of the decommissioning fund is unrealised and its recognition is a departure from one of the accounting principles set out in Schedule 4 of the Companies Act 1985. An explanation of this departure is given in note 2 (xvi).

The preparation of accounts in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the accounts and the reported amounts of revenues and expenses during the reporting period. Actual results can differ from those estimates.

In accordance with FRS18 the Directors have reviewed the Group’s accounting policies and confirm that they continue to be the most appropriate. A number of the policies require the Group to use a variety of estimation techniques. Significant factors considered when assessing the carrying value of assets include future prices, expected annual output, remaining station lives and discount rates. Estimates of output, costs and timing of associated cash flows as well as the expected regulatory framework are key factors used to apply the stated policies for long-term nuclear liabilities and decommissioning as discussed further in note 2 (xv) below.

The effect of the proposed restructuring of the Company, as noted above, will be significant and will result in, among other matters, the reassessment of estimates and assumptions which have been used to prepare these financial statements. In particular, the calculation of the carrying value of the nuclear stations will be reassessed on the basis of the new contracts with BNFL, the contribution of 65% of cash flow to the Nuclear Liabilities Fund and the likely review of the risk discount rate applied to the future cash flows.

F-8

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

In preparing these accounts, certain reclassifications and changes in presentation have been made to the accounts previously presented in the Group’s published UK Annual Report and Accounts, with the exception of the consolidated cash flow statements, in order to comply with accounting presentation and disclosure requirements applicable in the United States. A reconciliation to US GAAP is set out in note 37.

(ii) Basis of Consolidation

The Group financial statements consolidate the financial statements of British Energy and all its subsidiary undertakings. Inter-company profits, transactions and balances are eliminated on consolidation.

(iii) Turnover

Turnover represents amounts receivable for sales of electricity, and sales of other related goods, net of value added tax. Sales are recognized on an accruals basis, with reference to meter readings. Turnover includes estimates of selling prices for electricity generated in the year.

(iv) Fuel Costs—Nuclear Front End

Advanced Gas Cooled Reactors (“AGR”)

Front-end fuel costs consist of the costs of procurement of uranium, conversion and enrichment services and fuel element fabrication. Fabrication costs comprise fixed and variable elements. The fixed element is charged to the profit and loss account as incurred and the variable element, other than for unburnt fuel at shutdown, is charged to the profit and loss account in proportion to the amount of fuel burnt.

Pressurized Water Reactor (“PWR”)

All front-end fuel costs are variable and, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.

Bruce Power

Front-end fuel costs are recognized when fuel is loaded into the reactor. The reactors are continually reloaded and as such this method closely reflects fuel burnt. British Energy disposed of its interest in Bruce Power on February 14, 2003.

(v) Fuel Costs—Nuclear Back End

AGR

Spent fuel extracted from the reactors is sent for reprocessing and/or long-term storage and eventual disposal of resulting waste products. Back end fuel costs comprise the estimated cost of this process at current prices discounted back to current value in respect of both the amount of irradiated fuel burnt during the year and an appropriate proportion of unburnt fuel which will remain in the reactors at the end of their lives. All back end fuel costs, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.

PWR

Back end fuel costs are based on wet storage in station ponds followed by dry storage and subsequent direct disposal of fuel. Back end fuel costs comprise the estimated cost of this process at

F-9

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

current prices discounted back to current value. All back end fuel costs, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.

Bruce Power

Under the terms of the Bruce Power lease the responsibility for spent fuel, waste and decommissioning remains with Ontario Power Generation Inc. British Energy disposed of its interest in Bruce Power on February 14, 2003.

(vi) Unburnt fuel at shutdown

Due to the nature of the nuclear fuel process there will be some unburnt fuel in the reactors at station closure. The front end and back end costs of this fuel are charged to the profit and loss account over the estimated useful life of each nuclear station on a straight-line basis.

(vii) Fuel Costs—Coal

Fuel costs for coal are determined on a weighted average cost basis.

(viii) Research and Development

Research and development expenditure is charged to the profit and loss account as incurred.

(ix) Pensions and other Post Retirement Benefits

The Group continues to provide for UK pension costs in accordance with SSAP24. Contributions to the Group’s defined benefit pension schemes are assessed by qualified actuaries and are charged to the profit and loss account so as to spread the cost of pensions over employees’ working lives with the Group. The capital cost of ex gratia and supplementary pensions is charged to the profit and loss account, to the extent that the arrangements are not covered by the surplus in schemes, in the accounting period in which they are granted. Differences between the amounts funded and the amounts charged to the profit and loss account are included in the balance sheet.

In Canada, the charges for pensions and other post retirement benefits are determined annually by actuaries on the basis of management estimates. These costs consist of current service costs, interest and adjustments arising from plan amendments, changes in assumptions, and experience gains or losses, which are amortized on a straight-line basis over the expected average remaining service life of the employees covered by the plan. Costs are recorded in the year in which employees render services. British Energy disposed of its interest in Canada on February 14, 2003.

(x) Foreign Currencies

Transactions in foreign currencies are recorded at the rate of exchange at the date of the transaction or, if hedged forward, at the rate of exchange under the related forward currency contract. Assets and liabilities denominated in foreign currencies are translated into sterling at the rate of exchange ruling at the date of the balance sheet. All differences are taken to the profit and loss account.

Differences on foreign exchange arising from the re-translation of the opening net investment in, and results of, subsidiary and associated undertakings and joint ventures are taken to reserves and, where appropriate, are matched with differences arising on the translation of related foreign currency borrowings. Any differences are reported in the Statement of Total Recognized Gains and Losses.

F-10

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(xi) Tangible Fixed Assets and Depreciation, including Decommissioning Costs

Fixed assets comprise assets acquired or constructed by the Group. Expenditure of a capital nature incurred to improve operational performance, to improve safety or in order to meet increased regulatory standards is also capitalized. Interest on major capital projects is included in the cost of the fixed asset from the date of cash settlement until the date of commissioning. Other expenditure, including that incurred on preliminary studies and on the initiation of new technologies not yet adopted, is charged to the profit and loss account as incurred.

Fixed assets (other than assets in the course of construction) are stated in the balance sheet at cost less accumulated depreciation. Accumulated depreciation includes additional charges made where necessary to reflect impairment in value. Assets in the course of construction are stated at cost and not depreciated until brought into commission.

The carrying values of fixed assets are reviewed for impairment by assessing the present value of estimated future cash flows and net realizable value compared with net book value. The calculation of estimated future cash flows is based on the Directors’ best estimates of future prices, output and costs and is, therefore, subjective.

The charge for depreciation of fixed assets is based on the straight-line method so as to write off the costs of assets, after taking into account provisions for diminution in value, over their estimated useful lives. Upon retirement or disposal of fixed assets the related costs and accumulated depreciation are removed from the respective accounts and any gains or losses are included in the profit and loss account.

The asset lives adopted are subject to regular review and for the year ended March 31, 2003 were:

AGR power stations		25-35 years
PWR power station		40 years
Bruce power station assets		18 years
Coal power station		20 years
Other buildings		40 years
Other assets		5 years

The estimated costs for decommissioning the Group’s nuclear power stations are capitalized as part of the cost of construction and are depreciated over the same lives as the stations. These estimated costs are discounted having regard to the time-scale whereby work will take place over many years after station closure. The estimated costs include the demolition and site clearance of the stations’ radioactive facilities and the management of waste.

(xii) Fixed Asset Investments

Investments in subsidiaries are stated at the nominal value of shares allotted. Fixed asset investments are stated at cost less amortization or provisions for diminution in value. The Group’s investment in its joint venture is stated at cost plus the Group’s share of retained earnings. The carrying value of all fixed asset investments is regularly assessed for impairment and a provision made, if appropriate.

F-11

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Own shares purchased in respect of the Employee Share Option and ShareSave Option Schemes are held at cost less charges to write down the shares to the option exercise prices over the minimum lives of the options. The carrying value of all own share investments is regularly assessed for impairment and a provision made if appropriate. The Group has taken advantage of the exemption under UITF17 in respect of Save As You Earn Share Schemes.

(xiii) Stocks of Fuel, Stores and Spares

Stocks of fuel, stores and spares are valued at the lower of cost and net realizable value. The nuclear fuel stock is reduced by the provision for unburnt fuel at shutdown (note 2 (vi)). Strategic spares are amortized over the life of the asset to which they relate.

(xiv) Deferred Taxation

The Group makes full provision for deferred tax on all temporary timing differences which arise between its taxable profits and results as stated in the financial statements. The full amount of the provision is discounted using a discount rate similar to the current post tax rates of return on UK treasury gilts. The unwinding of one year’s worth of discount is included in the tax charge for the year. Deferred tax assets are recognised in the accounts to the extent to which they are considered to be recoverable in the foreseeable future.

(xv) Nuclear Liabilities

Nuclear liabilities represent provision for the Group’s liabilities in respect of the costs of waste management of spent fuel and nuclear decommissioning. The provisions represent the Directors’ best estimates of the costs expected to be incurred. They are calculated based on the latest technical evaluation of the processes and methods likely to be used, and reflect current engineering knowledge. The provisions are based on such commercial agreements as are currently in place, and reflect the Directors’ understanding of the current government policy and regulatory framework. The Directors carry out an in-depth review of the adequacy of amounts provisioned on a five yearly basis, and also review the amounts provided for significant change during the intervening years. Given that government policy and the regulatory framework on which our assumptions have been based may be expected to develop and that the Directors’ plans will be influenced by improvements in technology and experience gained from decommissioning activities, liabilities and the resulting provisions are likely to be adjusted.

In matching the costs of generating electricity against the income from sales, accruals are made in respect of the following:

(a)

Fuel costs—back-end

The treatment of back end fuel costs in the profit and loss account has been dealt with in notes 2(v) and 2(vi) above. These accruals cover reprocessing and storage of spent nuclear fuel and the long-term storage, treatment and eventual disposal of nuclear waste. They are based, as appropriate, on contractual arrangements or the latest technical assessments of the processes and methods likely to be used to deal with these obligations under the current regulatory regime. Where accruals are based on contractual arrangements they are included within creditors. Other accruals are based on long-term cost forecasts which are reviewed regularly and adjusted where necessary, and are included within provisions.

F-12

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(b)

Decommissioning of nuclear power stations

The financial statements include provision for the full cost of decommissioning the Group’s nuclear power stations. Provision is made on the basis of the latest technical assessments of the processes and methods likely to be used for decommissioning under the current regulatory regime. The provision established at the commencement of a power station’s operating life is capitalized as part of the costs of the station.

Accruals and provisions for back end fuel costs and decommissioning are stated in the balance sheet at current price levels, discounted at a long-term real rate of interest of 3% per annum to take account of the timing of payments. Each year the financing charges in the profit and loss account include the revalorization of liabilities required to discharge one year’s discount from provisions made in prior years and restate these provisions to current price levels.

(xvi) Decommissioning Fund

The Group makes contributions into an independently administered fund to cover all costs of decommissioning its UK nuclear power stations, except de-fuelling costs. The Group’s annual contributions to the fund are assessed by qualified actuaries, taking into account the amount and timing of expected decommissioning costs and the periods until station closures. The value of the asset in the balance sheet represents the contributions made by the Group, together with an estimated actuarially determined long-term rate of return on the fund. The change in value arising from applying the estimated long-term rate of return is taken to the profit and loss account and disclosed as part of the revalorization.

The revalorization of the decommissioning fund, which has been taken through the profit and loss account, is not a realized profit for the purposes of the Companies Act 1985 because the income is unrealized until the Group receives the related cash from the fund to reimburse decommissioning expenditure. The inclusion of this profit in the profit and loss account is a departure from the requirements of the Companies Act 1985. Revalorization of the accrued decommissioning provision is charged to the profit and loss account each year and accordingly, in the opinion of the Directors, it is necessary to include the estimated annual long-term rate of return of the fund in the Group’s profit and loss account in order for the financial statements to give a true and fair view. In the event that the net realizable value as indicated by the market value of the fund is lower than the value determined under the accounting policy set out above, the lower value is included in the Group accounts.

UK GAAP comprises both the provisions of the Companies Act 1985 and Accounting Standards. Within UK GAAP, a company is allowed to depart from the provisions of Schedule 4 of the Companies Act 1985 if the departure is considered necessary to give a true and fair view of the Group’s financial position. Therefore to invoke the true and fair override is not a departure from UK GAAP, but the adoption of a specific set of rules within UK GAAP.

The recognition in the profit and loss account of the actuarial gain on the investment assets of the Decommissioning Fund, which is unrealized profit, is in contradiction to Schedule 4 of the Companies Act 1985 (Schedule 4 (12a)) but is allowable by the true and fair view override provision (Companies Act §226(4)). It is the opinion of the Directors of British Energy that this departure from Schedule 4 of the Companies Act 1985 is necessary to give a true and fair view.

Under UK GAAP, without invoking the true and fair override, the Group would carry a current asset at historic cost (cash contributions made) to represent the investment assets of the Decommissioning

F-13

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Fund. This is because, under the Companies Act 1985, a current asset must be stated at the lower of historical purchase cost or valuation. The mark-to-market approach is not permitted under UK GAAP for current assets. The Decommissioning Fund is included in the financial statements at actuarial valuation, which is lower than market value. If the actuarial value exceeded market value, then the Decommissioning Fund would be stated at the lower amount. In order to give a true and fair view, the actuarial gains on the independent fund are included within the profit and loss account and disclosed according to UK GAAP (Companies Act §226(4), Schedule 4 and para. 15, UITF 7).

The effect of the departure for the UK fund is to increase the loss before tax by £82m (2002: increase the loss £4m; 2001: increase in profit £20m), and to reduce the reported loss before exceptional items for the year by £29m (2002: increase in profit £23m; 2001: increase in profit £20m). There is no impact on the net assets at March 31, 2003 as the fund has been restated at market value (2002 net assets were £82m higher; 2001: £86m higher due to this departure). There are no tax consequences of this departure.

The effect of the departure for the AmerGen Fund is to increase the loss before tax by £28m and to reduce the reported loss before exceptional items for the year by £20m. There is no impact on net assets as the AmerGen Fund has been restated at market value.

(xvii) Liquid Funds

Cash which is placed on term deposits which mature more than one day after the end of the financial year or invested in commercial paper is classified under current asset investments in the balance sheet and the movement in liquid funds is disclosed under management of liquid resources in the cash flow statement.

(xviii) Financial Instruments and Derivatives

Financial instruments and derivatives are used to hedge interest rate, foreign exchange and trading risks.

Energy trading financial derivatives, renewable obligation certificates and open positions on physical energy trading contracts are marked to market using externally derived market prices and subsequent movements in the fair value reflected through the profit and loss account. This is not in accordance with the general provisions of Schedule 4 of the Companies Act 1985, which requires that these contracts be stated at the lower of cost and net realizable value or that, if revalued, any revaluation difference be taken to a revaluation reserve. However, the Directors consider that these requirements would fail to provide a true and fair view of the results for the year since the marketability of energy trading contracts enables decisions to be taken continually on whether to hold or sell them. Accordingly the measurement of profit in any period is properly made by reference to market values. The effect of the departure on the financial statements is to reduce the loss for the year by £5m (2002: nil) and increase the net assets at March 31, 2003 by £5m (2002: nil).

Amounts payable or receivable in respect of interest rate swaps and forward rate agreements are recognized as adjustments to the net interest charge over the term of the contracts. Where derivatives used to manage interest rate risk or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction. When an anticipated transaction is no longer likely to occur, any deferred gain or loss that has arisen on the related derivative is recognized in the profit and loss account, together with any gain or loss on the terminated item.

F-14

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Profits and losses on financial instruments and derivatives are reported in the profit and loss account in the period to which underlying hedging transactions are completed. In the event that a financial instrument no longer forms part of the Group’s physical trading portfolio, the value of the instrument is estimated using discounted future cash flows, and provisions made if required. Short-term debtors and creditors have been excluded from the disclosures made under FRS13—‘Derivatives and other financial instruments’.

As noted above, UK GAAP comprises both the provisions of the Companies Act 1985 and Accounting Standards. Within UK GAAP a Company is allowed to depart from the provisions of Schedule 4 of the Companies Act 1985 if the departure is considered necessary to give a true and fair view of the Group’s financial position. Therefore, to invoke the true and fair override is not a departure from UK GAAP, but the adoption of a specific set of rules within UK GAAP.

Marking to market the Energy Trading financial derivatives, renewable obligation certificates and open positions on physical trading contracts is in contradiction to the general provisions of Schedule 4 of the Companies Act 1985 but is allowable by the true and fair view override provision (Companies Act §226(4)). It is the opinion of the Directors of British Energy that this departure from Schedule 4 of the Companies Act 1985 is necessary to give a true and fair view.

Under UK GAAP, without invoking the true and fair override, the Group would carry these contracts at the lower of cost and net realizable value and, if revalued, any difference would be taken to a revaluation reserve. This is because, under the Companies Act 1985, a current asset must be stated at the lower of historical purchase cost or valuation. The mark-to-market approach is not permitted under UK GAAP for current assets. In order to give a true and fair view, these contracts are marked to market.

(xix) Goodwill

Goodwill arising on acquisitions represents the excess of the fair value of the consideration at acquisition compared to the fair value of the identifiable net assets acquired. Goodwill is capitalized as an intangible asset on the balance sheet and amortized on a straight-line basis over its estimated useful life.

(xx) Joint Ventures

The Group’s share of the results of joint ventures is included in the consolidated financial statements based on the latest audited accounts of the joint ventures, except where the accounting reference date is not coterminous with the parent company, in which case management accounts are used, adjusted to comply with British Energy accounting policies.

(xxi) Operating Lease

The Group entered into an operating lease with Ontario Power Generation (OPG) to lease the Bruce nuclear plant in Ontario, Canada until 2018. Under the terms of the agreement a significant initial payment was made. This consideration, plus related transaction costs attributed to the operating lease prepayment, was amortized on a straight-line basis over the expected period of the lease. Other costs of the Bruce lease were charged to the profit and loss account in accordance with the rental schedule which is included in the lease agreement. The Group disposed of its investments in Bruce Power and Huron Wind on February 14, 2003. The results of Bruce Power are classified as a discontinued activity for the purpose of this report.

F-15

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

3. TURNOVER, OPERATING PROFIT AND NET ASSETS

The Group considers that it has two geographical segments, the UK and Canada, which are managed separately. In addition it separately discloses certain financial information in respect of its AmerGen joint venture.

(a) Turnover

	2003	2002	2001
	TWh	TWh	TWh
Output
United Kingdom	69.5	74.7	70.5
Canada	19.2	20.5	—

	88.7	95.2	70.5


	£m	£m	£m
Continuing activities
United Kingdom
—wholesale generation	852	1,162	1,593
—direct supply	603	522	343
—exceptional income	41	—	—
—miscellaneous income	32	17	18

	1,528	1,701	1,954
Discontinued activities	375	348	170

Turnover	1,903	2,049	2,124

The Company has agreed revised terms for the Nuclear Energy Agreement (‘NEA’) with Scottish Power and Scottish and Southern Energy. Under the terms of the revised agreement, which has now had regulatory approval, the Company is in a position to release as income a balance of £41m in respect of cash amounts previously received. This release has been treated as an exceptional item as it does not relate to current year trading.

Turnover from discontinued activities in Canada in 2002 and 2003 represent the sales by Bruce Power which was acquired on May 12, 2001 and sold on February 14, 2003.

Turnover from discontinued activities in 2001 relates to sales by Swalec which was sold on August 7, 2000.

The turnover, operating profits and net assets of the Group’s joint venture, AmerGen, relate entirely to activities in the United States of America.

(b) Operating Profit

A geographical analysis of operating profit before exceptional items is as follows:

	2003	2002	2001
	£m	£m	£m
United Kingdom	7	189	226
Canada	97	42	—

	104	231	226

F-16

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

All exceptional items applicable to operating profit relate to the U.K.

(c) Net (Liabilities)/Assets

A geographical analysis of the Group’s net (liabilities)/assets is as follows:

	2003		2002	2001
				(restated)
	£m		£m	£m
United Kingdom	(3,454	)	388	1,150
Canada	—		158	—
United States	71		81	18

	(3,383	)	627	1,168

(d) Additional Financial Information

Included within the profit and loss account of the Group (excluding AmerGen joint venture) are the following items by geographical location.

	2003					2002						2001
	UK		Canada	Group		UK		Canada		Group		UK		Canada	Group
	£m		£m	£m		£m		£m		£m		£m		£m	£m
Depreciation	273		7	280		280		5		285		277		—	277
Revalorization	209		—	209		164		—		164		175		—	175
Interest receivable	(9	)	—	(9	)	(13	)	(3	)	(16	)	(10	)	—	(10	)
Interest expense	81		—	81		74		8		82		66		—	66
Taxation	(396	)	18	(378	)	(19	)	15		(4	)	47		—	47
Exceptional items	4,162		—	4,162		535		—		535		(54	)	—	(54	)

F-17

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

4. OPERATING COSTS

	2003	2002	2001
	£m	£m	£m
Total costs
Continuing activities
—fuel	371	467	401
—materials and services	519	604	493
—staff costs (note 7)	227	212	166
—depreciation	4,011	580	277

	5,128	1,863	1,337
Amounts written off non-operational assets	115	—	—
Electricity purchases for direct supply costs	184	171	507

	5,427	2,034	1,844
Discontinued activities
—fuel	17	23	—
—materials and services	143	149	—
—staff costs (note 7)	111	119	—
—depreciation	7	5	—

	278	296	—

Total operating costs	5,705	2,330	1,844

Exceptional items
Continuing activities
—fuel	—	—	(24	)
—materials and services	94	209	—
—staff costs (note 7)	—	3	(44	)
—depreciation	3,738	300	—

	3,832	512	(68	)
Amounts written off non-operational assets	115	—	—
Energy supply costs	—	—	14

	3,947	512	(54	)

Analysis of exceptional items
—fuel	—	—	(24	)
—restructuring costs	35	—	—
—stock obsolescence	57	—	—
—staff costs	—	3	(44	)
—onerous trading contracts	2	209	14
—fixed asset write down (note 14)	3,738	300	—
—investments in own shares write down (note 15)	102	—	—
—UK decommissioning fund write down (note 16)	13	—	—

	3,947	512	(54	)

F-18

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

There were exceptional materials and services costs of £35m in respect of costs incurred on advisory fees and other costs associated with re-structuring the Group’s activities. An exceptional charge of £57m has been recorded for stock obsolescence following an extensive review of slow moving stores and spares conducted during the year.

During the year the Group had certain pre-NETA electricity trading contracts with Enron Capital & Trade Europe Finance LLC (“Enron”), Teesside Power Limited (“TPL”) and TotalFinaElf Gas and Power Limited (“TFE”). As a result of the terms inherent in these contracts and the Directors’ view of future market prices, the contracts are considered to be onerous. The Enron and TFE contracts were terminated during the year thus giving rise to claims for certain amounts which became payable. These accounts reflect the claim amounts which have been agreed in principle with Enron, TPL and TFE for the purposes of the restructuring. An exceptional charge of £2m has been made in the year to make further provision for these long-term trading contracts.

The Directors have reviewed the economic values and net realizable values of the Group’s fixed assets and compared them to their book value. As a result of this review, the carrying value of fixed assets has been written down by £3,738m.

The carrying value of the nuclear stations has been calculated by discounting the expected future cash flows from continued use of the assets, having made appropriate assumptions regarding future operating performance. The valuation of Eggborough is based on an assessment of net realizable value.

The electricity price assumptions are a very significant component of the asset value calculation. The Directors have considered the market’s views on future prices of wholesale electricity and also the forecasts specifically commissioned for the Company. They have considered the potential for rationalization of generation capacity in the UK and the potential effect on the market of changes in Government policy on renewables generation. In determining the price assumptions the Directors have also taken account of the effect on the market as a result of the dramatic fall in prices over the last two years and have taken a cautious view on there being a significant recovery in prices. As market prices are outside the Directors’ control actual prices may differ from those forecast.

In future years the Directors will review the economic assumptions underlying the calculation of fixed asset carrying values, in line with the requirements of FRS11, and make revisions as appropriate.

The 2001/02 results reported exceptional operating costs amounting to £512m, as follows:

•

a £209m provision in respect of the onerous pre-NETA contracts with Enron, TPL and TFE;

•

a charge of £3m (2001: £8m) for share option costs charged to staff costs; and

•

an asset write-down of £300m in respect of the Eggborough Power Station.

Included within operating costs in 2000/2001 were £174m of costs relating to Swalec prior to its disposal.

During 2000/2001 accounting lives of Heysham 1 and Hartlepool power stations were increased by five years from 25 years to 30 years. As a result of the life extensions there were one-off exceptional credits of £24m to fuel costs and £5m to revalorization. In accordance with FRS12, £28m of the one-off reductions in decommissioning liabilities were credited directly against the decommissioning assets within the power station assets rather than credited to the profit and loss account.

F-19

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

During April 2001 the House of Lords issued a ruling in favor of the National Grid Group in respect of the use of Electricity Supply Pension Scheme (ESPS) surplus to offset the costs of early retirement resulting from reorganization or redundancy. On the basis of the House of Lords decision a provision of £52m was released as an exceptional credit to staff costs in the year ended March 31, 2001. In addition an exceptional charge of £8m for share options costs was charged to staff costs.

There is a £14m exceptional item in 2000/2001 in energy purchased for supply in respect of an onerous power purchase agreement, which was retained following the sale of Swalec.

It is the Group’s policy to engage PricewaterhouseCoopers LLP on assignments where their expertise and experience with the Group are important, or where they win work on a competitive basis. An analysis of auditors’ remuneration on a worldwide basis is provided below:

	2003		2002		2001
	£000’s	%	£000’s	%	£000’s	%
Services as auditors	595	19	358	16	266	14
Due diligence	35	1	189	9	206	11
Tax services	331	11	1,249	57	913	49
Other non-audit services	509	17	387	18	487	26
Restructuring advice (including asset disposals)	1,608	52	—	—	—	—

Total	3,078	100	2,183	100	1,872	100

Statutory audit fees for British Energy plc were £60,000 (2002: £45,000; 2001: £40,000).

5. SHARE OF OPERATING PROFIT OF JOINT VENTURE—EXCEPTIONAL ITEM

British Energy’s joint venture, AmerGen, incurred severance costs at its three US nuclear power stations during 2000/2001. British Energy’s share of these costs totaled £7m.

6. LOSS ON DISPOSAL OF INVESTMENTS

On February 14, 2003 the Group completed the sale of its 82.4% interest in Bruce Power Limited Partnership (“Bruce Power”) and 50% share in Huron Wind Limited Partnership to a Canadian consortium led by Cameco Corporation, TransCanada and BPC Generation Infrastructure Trust.

The Group received initial consideration of C$678m upon financial close on February 14, 2003, together with a C$20m retention initially held in escrow pending confirmation of the pension deficit which was subsequently received in April 2003. In addition, there are certain amounts held in escrow which the Group may be entitled to receive pending satisfaction of various conditions related to the disposal. These amounts, which have not been recognized in these accounts, are:

•

C$100m, contingent on the restart of two Bruce A units, with C$50m to be released provided the first unit restarts by June 15, 2003 and an additional C$50m if the second unit restarts by

F-20

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

August 1, 2003. If the units do not restart on the specified dates then the contingent amounts released for each unit will be reduced by C$5m and such payment is reduced by a further C$5m if that unit is not restarted on or before the first day of each successive calendar month following the scheduled restart date.

•

C$20m, which is held in escrow from closing to cover any successful claims in respect of representations and warranties until any claims made against British Energy and British Energy International Holdings which are made within two years from the date of closing are resolved.

A further C$80m is held in an escrow account to cover the estimated outstanding tax liabilities of the Bruce Group. In the event that the sums held back to satisfy the tax liability are insufficient, then British Energy would be required to repay the amount of such excess to the Bruce Power consortium. Conversely, British Energy will be refunded any balance remaining after settlement of the tax liability.

The loss arising from the disposal and cash consideration which have been recognized in these accounts are analyzed as follows:

	£m
Net assets sold:
Tangible fixed assets	303
Investment in joint venture and associates	4
Stocks	37
Debtors	313
Cash at bank	4
Borrowings	(92	)
Creditors and provisions	(192	)

Net assets disposed	377
Minority interests	(68	)

Net assets disposed less minorities	309

Accounted for by:
Cash consideration net of transaction costs	266
Contingent consideration received post year end on determination of pension deficit	8

Loss on disposal—exceptional item	(35	)

Cash flows:
Cash consideration net of transaction costs received in 2002/03	266
Less: cash held by disposed subsidiary	(4	)

Net cash inflow	262

The Group’s disposal of its interest in Humber Power Limited during 2001/02 resulted in an exceptional profit of £4m.

On August 7, 2000, British Energy withdrew from domestic retail electricity and gas supply markets and sold its retail electricity and gas supply business, British Energy Retail Markets Limited and Swalec Gas Limited (together ‘Swalec’) to Scottish and Southern Energy plc for a cash consideration of £210m.

F-21

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The disposal of Swalec, together with the write-off of British Energy’s investment in 26% of the equity of Home Directory Limited, which ceased trading during 2000/2001, resulted in an exceptional loss of £5m.

7. EMPLOYEE INFORMATION

(a) Staff Costs

	2003		2002		2001
	£m		£m		£m
Salaries	322		314		200
Social security costs	29		26		18
Pension costs (note 26)	18		11		—
Severance charges	11		—		—
Amortization of share option costs	—		9		4
Amounts capitalized	(42	)	(32	)	(12	)
Exceptional charge/(credit)	—		3		(44	)

Total staff costs	338		331		166

(b) Employee Numbers

	2003	2002	2001
	Number	Number	Number
Average number of employees during the year
Continuing operations	5,103	4,969	5,273
Discontinued operations	2,799	2,701	37

	7,902	7,670	5,310

Average number of full time equivalent employees by category during the year were:

	2003	2002	2001
	Number	Number	Number
Power stations	3,826	3,750	3,935
Engineering, technical and corporate support	1,228	1,170	1,252
North America—continuing operations	28	32	41

	5,082	4,952	5,228
Retail market—discontinued operations	—	—	37
Canada—discontinued operations	2,798	2,701	—

	7,880	7,653	5,265

F-22

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

8. DIRECTORS’ EMOLUMENTS AND INTERESTS

(a) Summary of Directors’ Emoluments

	2003	2002	2001
	£’000	£’000	£’000
Total emoluments, including pension contributions
As Directors	585	221	293
For management services:
—salaries and other benefits	996	1,041	811
—performance related bonuses	—	343	183
—pension contributions	52	48	65

	1,633	1,653	1,352
—compensation for loss of office	98	365	285

	1,731	2,018	1,637

(b) Individual Remuneration

	Salary and fees	Contingent Fees	Compen- sation for loss of office	Other benefits	Total emoluments excluding pension
Year ended March 31	2003	2003	2003	2003	2003	2002
	£	£	£	£	£	£
A Montague(1)	100,000	300,000	—	209	400,209	—
M Alexander(2)	33,333	—	—	2,202	35,535	—
D Gilchrist(3)	183,563	—	—	20,067	203,630	183,362
D Hawthorn(3),(4)	152,978	—	—	8,046	161,024	146,876
K Lough(3)	211,250	—	—	12,886	224,136	206,537
Sir R Hill	57,500	—	—	—	57,500	57,500
I Harley(5)	25,833	—	—	—	25,833	—
C Spottiswoode(11)	53,333	—	—	—	53,333	8,333

Total emoluments for serving Directors as at March 31, 2003	817,790	300,000	—	43,410	1,161,200	602,608
R Jeffrey(6)	309,188	—	98,000	17,349	424,537	478,201
Sir R Biggam(7)	11,167	—	—	—	11,167	52,500
P Stevenson(8)	25,893	—	—	—	25,893	30,000
M Kirwan(9)	45,042	—	—	4,007	49,049	280,900
J Walsh(10)	7,325	—	—	—	7,325	25,000
Sir J Robb(12)	—	—	—	—	—	48,082
P Hollins(13)	—	—	—	—	—	87,865

Total emoluments (all Directors)	1,216,405	300,000	98,000	64,766	1,679,171	1,605,156

Compensation for loss of office:
P Hollins(13)	—	—	—	—	—	364,600
R Jeffrey	—	—	98,000	—	98,000	—

F-23

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

There were no bonuses or accommodation and relocation expenses paid in the year to March 31, 2003.

(c) Directors’ Pension Contributions

	2003	2002
	£	£
A Montague(1)	—	—
M Alexander(2)	1,385	—
D Gilchrist(3)	12,020	5,565
D Hawthorne(3),(4)	21,749	8,750
K Lough(3)	12,020	5,565
Sir R Hill	—	—
I Harley(5)	—	—
C Spottiswoode(11)	—	—

Total pension contributions serving Directors at March 31, 2003	47,174	19,880

R Jeffrey(6)	—	—
Sir R Biggam(7)	—	—
P Stevenson(8)	—	—
M Kirwan(9)	4,453	26,526
J Walsh(10)	—	—
Sir J Robb(12)	—	—
P Hollins(13)	—	2,134

Total Pension Contributions (all Directors)	51,627	48,540

Notes referred to in above tables—

(1)

Appointed on December 1, 2002.

(2)

Appointed on March 1, 2003.

(3)

Appointed as Executive Directors on September 1, 2001.

(4)

D Hawthorne’s pro rata salary to termination date of February 14, 2003 is C$357,107 and has been converted into Sterling at the average exchange rate for the year(£1 = C$2.40). Mr Hawthorne became a Non-Executive Director serving on the Board from February 15, 2003.

(5)

Appointed on June 1, 2002.

(6)

R Jeffrey resigned as a Director on February 10, 2003.

(7)

Sir R Biggam resigned as a Director on June 7, 2002.

(8)

P Stevenson resigned as a Director on February 28, 2003.

(9)

M Kirwan resigned as a Director on May 31, 2002. The salary figure for 2003 includes accrued holiday pay of £13,458.

(10)

J Walsh resigned as a Director on July 16, 2002.

(11)

C Spottiswoode appointed September 1, 2001.

(12)

Sir J Robb retired July 17, 2001.

(13)

Mr Hollins served on the Board from February 9, 1998 to June 7, 2001 when his services with the Company terminated. The compensation for loss of office payment includes a payment in lieu of 12 months contractual notice.

F-24

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(d) Executive Share Options

	Options held at April 1, 2002	Options granted	Options exercised	Options lapsed during the year	Options held at March 31, 2003	Option Exercise Price (£)	Date from which exercisable	Expiry Date
R Jeffrey	113,846	—	—	113,846	—	2.60	12/08/2000	11/08/2004
	11,538	—	—	11,538	—	2.60	12/08/2000	11/08/2007
	35,990	—	—	35,990	—	5.08	29/06/2001	29/06/2005
	32,021	—	—	32,021	—	5.295	25/06/2002	24/06/2006
	81,160	—	—	81,160	—	2.4125	14/07/2003	13/07/2007
	100,401	—	—	100,401	—	2.49	07/12/2003	06/12/2007

	374,956	—	—	374,956	—

D Gilchrist	57,692	—	—	—	57,692	2.60	15/07/2000	14/07/2004
	11,538	—	—	—	11,538	2.60	15/07/2000	14/07/2007
	19,862	—	—	—	19,862	5.08	29/06/2001	28/06/2005
	21,379	—	—	—	21,379	5.295	25/06/2002	24/06/2006
	40,659	—	—	—	40,659	2.4125	14/07/2003	13/07/2007

	151,130	—	—	—	151,130

D Hawthorne	13,269	—	—	13,269	—	2.60	15/07/2000	14/07/2004
	11,538	—	—	11,538	—	2.60	15/07/2000	14/07/2007
	17,869	—	—	17,869	—	5.08	29/06/2001	28/06/2005
	24,516	—	—	24,516	—	5.295	25/06/2002	24/06/2006
	40,559	—	—	40,559	—	2.4125	14/07/2003	13/07/2007

	107,751	—	—	107,751	—

M Kirwan	11,538	—	—	—	11,538	2.60	12/08/2000	11/08/2004
	118,077	—	—	—	118,077	2.60	12/08/2000	11/08/2007
	37,192	—	—	—	37,192	5.08	29/06/2001	28/06/2005
	33,097	—	—	—	33,097	5.295	25/06/2002	24/06/2006
	76,269	—	—	—	76,269	2.4125	14/07/2003	13/07/2007

	276,173	—	—	—	276,173

K Lough	9,433	—	—	—	9,433	3.18	14/09/2004	13/09/2011
	116,353	—	—	—	116,353	3.18	14/09/2004	13/09/2008

	125,786	—	—	—	125,786

(e) ShareSave Scheme

Options

held at

April 1,

2002

Options

granted

Options

exercised

Options

lapsed

during the

year

Options

held at

March 31,

2003

Option

Exercise

Price (£)

Date from

which

exercisable

Expiry Date

K Lough

—

7,058

—

7,058

1.36

01/09/2007

28/02/2008

Robin Jeffrey and Duncan Hawthorne ceased to be Executive Directors in 2002/03. All share options granted to them lapsed on the dates when, respectively, Mr Hawthorne ceased to be an Executive Director and when Dr Jeffrey tendered his resignation. Mike Kirwan retired in 2002/03 and his share options lapsed on May 31, 2003.

F-25

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

9. FINANCING CHARGES/(CREDITS)

	2003		2002		2001
	£m		£m		£m
Revalorization of nuclear liabilities	228		175		191
Revalorization of decommissioning fund	(29	)	(23	)	(20	)
Revalorization of other provisions	10		12		4
Share of revalorization of joint venture	(4	)	(4	)	(2	)

Revalorization charge before exceptional items	205		160		173
Exceptional item (see below)	159		27		(5	)

Revalorization charge	364		187		168

Interest:
Interest on loans repayable within five years
—banks	11		27		19
—others	24		27		17
Interest on loans repayable in five years or more
—banks	38		20		22
—others	8		8		8
Exceptional item—interest rate swaps	56		—		—
Exceptional item—borrowing costs	6		—		—
Interest receivable	(9	)	(16	)	(10	)

Net interest payable before exceptional items	134		66		56

At March 31, 2003 the market value of the UK decommissioning fund at £334m was lower than the value of £458m that would have been derived from revalorizing the amounts contributed. As a result an exceptional charge of £124m has been recognized to record the fund at market value of which £111m relates to the write-off of previous revalorization and £13m has been classified as a write off of non-operational assets. The UK Decommissioning Fund was also written down by £27m in the 2001/02 accounts, to reflect a lower market value at March 31, 2002.

The market value of the decommissioning fund of AmerGen is also lower than the value that would have been derived from revalorizing the amounts contributed. The British Energy share of the adjustment required to restate the value of the fund to market value is £48m, all of which relates to previous revalorization.

The total exceptional charge relating to the two funds amounts to £159m.

An exceptional charge of £56m has been recognized for interest rate swaps. The basis of the provision is discussed in note 24. In addition, an exceptional charge of £6m has been recorded for the write off of borrowing costs which had previously been capitalized and were being amortized over the expected duration of the loan financing the acquisition of the Eggborough power station.

The exceptional revalorization credit of £5m in 2001 results from the extension of the accounting lives at Heysham 1 and Hartlepool power stations.

F-26

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

10. TAXATION ON (LOSS)/PROFIT ON ORDINARY ACTIVITIES

	2003		2002		2001
					(restated)
	£m		£m		£m
UK corporation tax—prior year	—		(11	)	2
Deferred taxation on (loss)/profit before tax and exceptionals	(40	)	34		12
Unwinding of discount	14		14		15

(Charge)/credit on loss for the year	(26	)	48		27
Exceptional deferred tax (credit)/charge	(370	)	(56	)	18

Deferred tax charge for the year	(396	)	(8	)	45
Foreign tax—current year	18		15		—

	(378	)	(4	)	47

The deferred tax exceptional credit in 2002/03 arises mainly as a result of the write down of fixed asset carrying values. In 2001/02 the credit arose mainly as a result of the increased provision on the long-term onerous trading contracts and in 2000/01 the charge arose due to the House of Lords ruling on pensions, resulting in the release of provision as an exceptional credit to staff costs. The background to the exceptional items is explained in more detail in note 4.

A reconciliation of the effective tax rate for the current year tax charge, which solely comprises foreign tax is set out below.

	2003				2002
	Tax terms		Percentage		Tax terms		Percentage
	£m				£m
Tax credit on loss at standard rate of 30%	(1,288	)	30	%	(148	)	30	%
Deferred tax:
—current year movement pre-discounting	396		(9	)%	8		(2	)%
—impact of discounting	619		(14	)%	55		(11	)%
—deferred tax asset not recognized (note 25)	150		(4	)%	—		—

Total deferred tax pre-discounting	1,165		(27	)%	63		(13	)%
—expenses not deductible for tax purposes	140		(3	)%	108		(22	)%
—loss on sale of investment not allowable	11		0	%	—		—
—higher tax rates on overseas earnings	(6	)	0	%	3		(1	)%
—minority interests	(4	)	0	%	(3	)	1	%
—impact of joint venture	—		—		(8	)	2	%

Current tax charge for year	18		0	%	15		(3	)%

Following the introduction of FRS19 the Group discounts its deferred tax liability. This has resulted in a prior year charge of £20m to the previously disclosed deferred tax charge in the profit and loss account in the year ended March 31, 2001. The unwinding of one year’s discount is included in the tax charge for the year.

The Group’s joint venture, AmerGen, is not a tax paying entity. The share of taxation for joint venture represents the Group’s liability for its share of AmerGen’s taxable profits.

F-27

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

11. LOSS OF THE COMPANY

The Group’s results include a loss of £6,058m (2002: loss of £310m; 2001: loss of £40m) attributable to the Company, inclusive of a provision of £5,909m made in the current year for bad and doubtful inter-company debtors which is eliminated on consolidation. The Company did not have any distributable reserves at March 31, 2003 (2002: £491m). As permitted under Section 230 of the Companies Act 1985 the Company has not published a separate profit and loss account.

12. DIVIDENDS

	2003	2002	2001	2003	2002	2001
	p/share	p/share	p/share	£m	£m	£m
Annual dividend per ordinary share
Interim paid	—	2.7	2.7	—	16	16
Final proposed	—	5.3	5.3	—	32	32

Total annual	—	8.0	8.0	—	48	48

Actual cash dividends paid per Ordinary Share	—	8.0	5.0	—	46	29

Non-equity dividend	—	2.3	2.9	—	2	2

The British Energy Employee Share Trust and the QUEST elected to waive their entitlement to receive dividends for financial years ended March 31, 2001 and 2002.

13. EARNINGS PER SHARE

The basic total earnings per share for the year has been calculated on the basis of the loss on ordinary activities after taxation, minority interest and non-equity dividends of £3,941m (2002: loss £529m; 2001: profit of £7m) and by reference to a weighted average of 602 million ordinary shares (2002: 598 million; 2001: 591 million ordinary shares).

As the Group was loss making in the years ended March 31, 2003 and 2002 there is no dilutive effect attributable to any outstanding options and there is no difference between basic and diluted earnings per share. The weighted average of ordinary shares used for calculating the diluted total earnings per share in 2001 is 651 million shares.

F-28

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

14. TANGIBLE FIXED ASSETS

Group	Power stations		Other land and buildings	Other plant and equipment		Total
	£m		£m	£m		£m
Cost
As at April 1, 2002	10,793		47	408		11,248
Foreign exchange	(9	)	—	(1	)	(10	)
Additions	258		—	35		293
Disposal of Bruce Power and Huron Wind	(295	)	—	(8	)	(303	)

As at March 31, 2003	10,747		47	434		11,228

Depreciation
As at April 1, 2002	6,275		24	235		6,534
Exceptional asset write down	3,594		—	144		3,738
Charge for the year	247		—	33		280
Disposal of Bruce Power and Huron Wind	(8	)	—	(2	)	(10	)

As at March 31, 2003	10,108		24	410		10,542

Net book value
As at March 31, 2003	639		23	24		686

As at March 31, 2002	4,518		23	173		4,714

The net book value of tangible fixed assets includes the following amounts in respect of freehold land and buildings:

	2003	2002	2001
	£m	£m	£m
Cost	2,245	2,223	2,223

Net book value	107	1,120	1,163

The Directors have reviewed the economic values and net realizable values of the Group’s fixed assets and compared them to their net book values. A discount rate of 15% was applied to the economic value review. As a result of this review the value of its fixed assets has been reduced by £3,738m. The background to the review is discussed more fully in note 4.

Company		Plant and equipment
		£m
Cost
As at April 1, 2002		150
Additions		6

As at March 31, 2003		156

Depreciation
As at April 1, 2002		111
Exceptional asset write down		31
Charge for the year		14

As at March 31, 2003		156

Net book value
As at March 31, 2003		—

As at March 31, 2002		39

F-29

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

15. FIXED ASSET INVESTMENTS

Group	AmerGen joint venture		Loans to Nirex	Own shares	Other investments	Total
	£m		£m	£m	£m	£m
Cost
As at April 1, 2002	87		37	140	4	268
Foreign exchange	(11	)	—	—	—	(11	)
Share of retained profits	43		—	—	—	43

As at March 31, 2003	119		37	140	4	300

Provision for diminution in value
As at April 1, 2002	—		37	36	—	73
Charge for the year:
—exceptional items	48		—	102	—	150

As at March 31, 2003	48		37	138	—	223

Net book value
As at March 31, 2003	71		—	2	4	77

As at March 31, 2002	87		—	104	4	195

The Group is engaged in a sale process to dispose of its investment in AmerGen as required by the conditions attaching to the UK Government credit facility agreement. The investment has been classified as a fixed asset investment as the Group has not yet entered into an agreement for its disposal.

An analysis of British Energy’s share of the aggregate net assets of the AmerGen joint venture is set out below.

	2003		2002
	£m		£m
Negative goodwill	(7	)	(14	)
Tangible assets	144		107
Stocks	10		52
Cash	6		2
Decommissioning fund	306		378
Debtors	18		19
Creditors	(51	)	(67	)
Decommissioning liabilities	(321	)	(340	)
Loan notes	(34	)	(50	)

Net assets	71		87

Negative goodwill relates to AmerGen’s acquisition of Oyster Creek nuclear power station in August 2000.

The market value of the AmerGen decommissioning fund has fallen following the fall in the value of the equity markets. An exceptional charge of £48m has been recorded for British Energy’s share of the adjustment required to restate the balance sheet value to market value.

F-30

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Loans have been made to United Kingdom Nirex Limited to fund development expenditure for building an intermediate level nuclear waste repository. These loans have been fully provided for in the Group’s financial statements.

At March 31, 2003 British Energy Employee Share Trust held 21,734,839 ordinary shares at an average cost of £4.68 for a total consideration of £101m. These shares are held at cost less charges to write down the shares to the exercise price of the share options over the minimum life of the options.

At March 31, 2003 the QUEST held 5,292,103 ordinary shares at a cost of £5.32 per share (£28m) and 19,165,471 ‘A’ shares at a cost of 60p per share (£11m). These shares are held at cost less charges to write down the shares to the exercise price over the minimum life of the options.

The market value of shares held by the employee trusts at March 31, 2003 was £2m compared to a book value of £104m. As the long-term prospects of the Company have deteriorated considerably the Directors consider it appropriate to recognise a permanent diminution in the value of the shares held in employee trusts. As a result an exceptional charge of £102m has been recognised within ‘Amounts written off non-operational assets’.

Company	Subsidiary undertakings		Total
	£m		£m
Cost
As at April 1, 2002	19		19
Transfer to Group undertaking	(5	)	(5	)

As at March 31, 2003	14		14

Details of British Energy’s principal subsidiary undertakings and other holdings of more than 10% are as follows:

	Country of registration and operation	Class of share	Group share- holding	Company share- holding	Principal activity
			%	%
Subsidiary undertakings
British Energy Generation (UK) Limited	Scotland	Ordinary	100	100	Generation and sale of electricity
British Energy Generation Limited	England and Wales	Ordinary	100	—	Generation and sale of electricity
British Energy Power & Energy Trading Limited	Scotland	Ordinary	100	100	Energy trading
Eggborough Power Limited	England and Wales	Ordinary	100	—	Generation and sale of electricity
Lochside Insurance Limited	Guernsey	Ordinary	100	100	Insurance
British Energy US Holdings Inc	USA	Ordinary	100	—	Holding Company
British Energy Holdings Limited	Canada	Ordinary	100	—	Holding Company

Other holdings of more than 10 per cent
AmerGen Energy LLC	USA	Ordinary	50	—	Generation and sale of electricity
United Kingdom Nirex Limited	England and Wales	Ordinary	10.8	—	Disposal of nuclear waste

F-31

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Included in the Group accounts are the assets of British Energy Employee Share Trust and the assets of British Energy Qualifying Employee Share Trust, which are trusts set up to hold shares purchased on behalf of the Group’s employees under the Employee Share Scheme and the British Energy ShareSave Scheme respectively.

The accounting reference dates of AmerGen Energy LLC and British Energy US Holdings Inc are both December 31.

16. DECOMMISSIONING FUND

	Group
	£m
As at April 1, 2002	411
Regular contributions	18
Revalorization (note 9)	29

	458
Less exceptional item to write down to market value	(124	)

As at March 31, 2003	334

The decommissioning fund asset in the balance sheet normally represents the contributions made by the Group, together with an estimated actuarially determined long-term post-tax real rate of return on the fund of 3.5% per annum. The change in value arising from applying the estimated long-term rate of return is taken to the profit and loss account as a revalorization credit. The decommissioning fund asset is receivable after more than one year.

At March 31, 2003 the market value of the decommissioning fund’s investments was £334m (market value 2002: £411m). As a result of the market value being lower than the balance sheet carrying value an exceptional charge of £124m has been recognized in the accounts to restate the decommissioning fund receivable to market value. Of this charge £111m represents the write down of previous revalorization and has been treated as an exceptional financing charge. The balance of £13m has been included in ‘Amounts written off non-operational assets’ and classified as an operating cost.

17. STOCKS

	Group
	2003		2002
	£m		£m
Unburnt nuclear fuel in reactors	469		451
Provision for unburnt fuel at station closure	(272	)	(266	)

Net unburnt nuclear fuel in reactors	197		185
Other nuclear fuel	74		152
Coal stocks	14		15
Stores	75		162

	360		514

F-32

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

18. DEBTORS

	Group		Company
	2003	2002	2003	2002
	£m	£m	£m	£m
Trade debtors	226	294	3	5
Other debtors	89	158	—	76
Operating lease prepayment	—	176	—	—
Prepayments	72	104	1	3
Amounts due from subsidiary undertakings	—	—	81	2,433

	387	732	85	2,517

Included within the Company’s amount due from subsidiary undertakings is £81m (2002: £67m) which was denominated in foreign currencies and translated at the year-end exchange rate, and a provision for bad and doubtful debts of £6,209m relating to amounts due from UK subsidiaries.

£56m of Group debtors fall due in more than one year (2002: £320m).

19. CREDITORS

	Group		Company
	2003	2002	2003	2002
	£m	£m	£m	£m
Amounts falling due within one year
Nuclear liabilities (note 23)	355	224	—	—
Trade creditors	198	285	—	—
Retentions	5	4	—	—
Other taxes and social security	9	21	—	—
Other creditors	326	72	1	—
Accruals	140	182	20	15
Proposed dividends	—	34	—	34
Amounts due to subsidiary undertakings	—	—	3,721	—

	1,033	822	3,742	49

Other creditors: amounts falling due after more than one year Nuclear liabilities (note 23)	1,909	1,858	—	—

Other creditors include £316m in respect of claims relating to onerous trading contracts. These contracts are pre-NETA electricity trading contracts with Enron Capital & Trade Europe Finance LLC (“Enron”), Teesside Power Limited (“TPL”) and TotalFinaElf Gas and Power Limited (“TFE”). The Enron and TFE contracts were terminated during the year, which gave rise to claims for certain amounts which have become payable. Interest is payable on standstill balances at a rate of 6%, other than the bonds and the amounts due to the Eggborough banks which continue under their original terms. These accounts reflect the claim amounts which have been agreed in principle with Enron, TPL and TFE for the purposes of the proposed restructuring of the Group.

F-33

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

20. BORROWINGS

(i) Summary

The Group’s borrowings at March 31, 2003 were as follows:

	Group		Company
	2003	2002	2003	2002
	£m	£m	£m	£m
Short term—US dollar	—	6	—	6
Long term—Canadian dollar	—	42	—	—
Long term OPG loan—Canadian dollar	—	104	—	—
Long term project finance loan—Sterling	475	508	—	—
Bonds—Sterling	408	408	408	408

	883	1,068	408	414

The long-term project finance loan is secured on the assets of Eggborough Power Limited (EPL). Amounts owed by EPL to the lenders are not guaranteed by British Energy plc (BE) but BE guarantees the payment of amounts by British Energy Power & Energy Trading Limited (BEPET) to EPL. The contractual amounts payable by BEPET are calculated so as to cover EPL’s borrowing requirements and operating costs. BE also provides a subordinated loan facility to EPL. The final installment of loan principal will be repaid in 2011. The loan currently bears interest at LIBOR plus 1.25%. It is proposed that these arrangements will be restructured as part of the proposed restructuring of the Group.

The remainder of the Group’s borrowings are unsecured. The interest rate coupons on the bonds are as follows:

	2003
	Coupon rate	Principal
	%	£m
Bond 2003	5.949	110
Bond 2006	6.077	163
Bond 2016	6.202	135

		408

The March 2003 bond has not been repaid as scheduled. It is proposed that claims of bondholders will be restructured as part of the restructuring of the Group.

(ii) Risk Profile

The interest rate risk profile of the Group’s borrowings is as follows:

	Weighted average interest rate	Weighted average period for which the rate is fixed	2003			2002
	Weighted average interest rate	Weighted average period for which the rate is fixed	Floating rate	Fixed rate	Total	Total
	%	Years	£m	£m	£m	£m
Sterling	6.41	5.8	—	883	883	916
Canadian dollar	—	—	—	—	—	146
US dollar	—	—	—	—	—	6

At March 31			—	883	883	1,068

F-34

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

At March 31, 2003, the effect of the Group’s interest rate contracts is to classify £475m (2002: £508m) of borrowings as fixed rate in the above table.

(iii) Fair Values

The fair values of the Group’s borrowings at March 31, 2003 are as follows:

	2003		2002
	Book value	Fair value	Book value	Fair value
	£m	£m	£m	£m
Short term—US Dollar	—	—	6	6
Long term—Canadian Dollar	—	—	42	42
Long term OPG loan—Canadian Dollar	—	—	104	104
Long term project finance loan—Sterling	475	150	508	508
Bonds—Sterling	408	171	408	388

	883	321	1,068	1,048

The fair value of long-term bonds reflect their market value as at March 31, 2003.

There is no open market information available for the long-term project finance loan, the value of which has been severely affected by the proposed financial restructuring of the Group. Therefore, the fair value which has been attributed to the loan has been based on the Directors’ best estimate of the net realizable value of the Eggborough Station upon which this debt is secured.

(iv) Maturity of Borrowings

	2003	2002
	£m	£m
Less than one year	152	153
Between one and two years	45	41
Between two and five years	319	410
Over five years	367	464

	883	1,068

The analysis of maturity of borrowings has been prepared based on the dates when the borrowings mature under the existing contractual arrangements. However, the standstill arrangements which have been put in place have the effect of deferring the payments of certain amounts due until the Bonds and Eggborough project finance loan are replaced as part of the restructuring of the Group or earlier termination of the standstill. The maturity profile of borrowings is likely to change upon completion of the restructuring.

(v) Borrowing Facilities

At March 31, 2003 the Group had the following borrowing facilities excluding the bonds.

	Drawn	Undrawn	Total	Expiry Date
	£m	£m	£m
Long-term project finance loan	475	—	475	2011
Credit facility with UK Government	—	200	200	2004

Totals	475	200	675

F-35

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The borrowing facilities require the Group to maintain minimum levels of net worth and interest cover. The covenants are calculated in accordance with the terms of the debt agreements.

21. DERIVATIVES AND FINANCIAL INSTRUMENTS

British Energy enters into financial instruments, derivative instruments and derivative commodity instruments, which are potentially sensitive to changes in interest rates, foreign exchange rates, commodity prices and equity markets. These instruments are used to hedge the primary market exposures associated with the Group’s underlying assets, liabilities and committed transactions. These instruments are not leveraged and are not held or issued for trading purposes.

Hedge accounting is applied only where the derivative financial instrument reduces the risk of the underlying hedged item and is designated at inception as a hedge, with respect to the hedged item. If a derivative instrument ceased to meet the criteria for deferral, any gains or losses would currently be recognized in income. If a hedged item were sold, the value of the financial instrument would be recognized in income. Gains and losses on financial instruments used for hedging purposes are recognized in the Group’s Profit and Loss account in the same period as the hedged item.

A summary of off-balance sheet derivative financial instruments at March 31, 2003 and 2002 is set out below.

	2003			2002
	Notional Principal Amount	Estimated Fair value		Notional Principal amount	Estimated Fair value
	£m	£m		£m	£m
Foreign exchange forward contracts	—	—		5	1
Interest rate contracts	498	(56	)	518	(29	)

The Group uses interest rate contracts to manage exposure to interest rate fluctuations.

Fuel stock is stated after taking into account exchange movements on foreign exchange contracts associated with its purchase. The deferred loss at year end is included in stock and is being released to operating costs over the period (generally five years) during which the associated fuel will be consumed.

F-36

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

A summary table of the net losses on derivative instruments is set out in the table below:

	2003				2002
	Un- recognized		Deferred		Un- recognized		Deferred
	£m		£m		£m		£m
Net losses on derivative instruments at April 1, 2002	(28	)	(10	)	(30	)	(20	)
Net losses arising in previous period included in current period profit and loss account	28		8		—		5

Net losses arising before April 1, 2002 not included in current period profit and loss account	—		(2	)	(30	)	(15	)

Net gains/(losses) arising in current period not included in current period profit and loss account	—		—		2		5

Net losses on hedges at March 31, 2003	—		(2	)	(28	)	(10	)

Of which:
Net losses expected to be included in 2003/04 profit and loss account	—		(2	)
Net losses expected to be included in profit and loss accounts beyond 2003/04	—		—

The fair value of the Group’s forward exchange contracts has been calculated using the market rates in effect at the balance sheet dates.

Foreign currency commitments relating to the purchase of fuel are no longer hedged, but existing hedging contracts are expected to be retained to maturity. Material currency commitments on non-fuel contracts will continue to be hedged.

Financial risks associated with electricity trading are managed on a day-to-day basis by the Group’s Power and Energy Trading function which operates within policies and procedures approved by the Board. The Trading Risk Committee is a committee of the Board formerly chaired by the Executive Chairman and now chaired by an Independent Director, which meets on at least a quarterly basis to monitor and review the status of the Trading Risk Log and approve changes to Trading Limits on behalf of the Board.

In England and Wales, NETA was introduced on March 27, 2001. During the last financial year British Energy has successfully operated a policy of balancing its anticipated generation with net sales in advance of the day of delivery. In this way, British Energy’s exposure to prices in the daily spot market and the NETA Balancing Mechanism is kept small.

Sales are built up over time in a variety of ways, with a combination of contracts containing fixed and variable price elements. Direct sales to retail customers, and tailored sales to retail suppliers, typically cover periods of one to two years. Sales via the wholesale commodity market cover a range of periods, most commonly six months seasonal trades. A number of shorter-term trades are made to balance supply and demand on a continual basis.

Within the Board’s overall remit on trading strategy, both sales and purchases are made to capture opportunities from forward price movements. The impacts of such actions are continually monitored and the overall price exposure arising is kept within well-defined limits.

F-37

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Certain of the Group’s long-term trading contracts no longer form part of the Group’s physical trading portfolio. To the extent that these contracts are “out of the money” they have been treated as onerous and provided for in the Group’s balance sheet at March 31, 2003. These accounts reflect the claim amounts which have been agreed in principle with Enron, TPL and TFE for the purpose of the proposed restructuring of the Group.

Although British Energy is potentially exposed to credit risk in the event of non-performance by counter-parties, such credit risk is controlled through credit rating reviews of the counter-parties, and by limiting the total amount of exposure to any one party. The counter-parties to these instruments generally consist of financial institutions and other corporate entities with good credit ratings such that the Group does not believe it is exposed to material concentrations of credit risk and generally does not obtain collateral to support such financial instruments.

22. PROVISIONS FOR LIABILITIES AND CHARGES

	Group
	2003	2002
	£m	£m
Nuclear liabilities (note 23)	1,673	1,637
Other provisions (note 24)	62	349
Deferred taxation (note 25)	—	414

	1,735	2,400

23. NUCLEAR LIABILITIES

	Back end fuel costs contracted		Back end fuel costs uncontracted		De- commissioning	2003 Total		2002 Total
	£m		£m		£m	£m		£m
As at April 1, 2002	2,082		702		935	3,719		3,728

Charged/(credited) to profit and loss account:
—operating costs	72		33		—	105		148
—revalorization (note 9)	126		41		61	228		175
—reclassifications	97		(97	)	—	—		—

Payments in the year	(114	)	(1	)	—	(115	)	(332	)

As at March 31, 2003	2,263		678		996	3,937		3,719

The year-end balances of nuclear liabilities are included in the balance sheet as follows:

	2003	2002
	£m	£m
Creditors:
—amounts falling due within one year	355	224
—amounts falling due after more than one year	1,909	1,858
Provisions for liabilities and charges	1,673	1,637

	3,937	3,719

F-38

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Fuel costs—Back End

Accruals for AGR fuel services relating to spent AGR fuel are based on the terms of contracts with BNFL (dated March 30, 1995 and June 3, 1997), most of which include fixed prices subject to indexation, or the Group’s estimates where no contracts exist. Provisions for services relating to the disposal of nuclear waste and the storage and disposal of PWR spent fuel are based on cost estimates derived from the latest technical assessments.

Decommissioning

The costs of decommissioning the power stations have been estimated on the basis of technical assessments of the processes and methods likely to be used for decommissioning under the current regulatory regime. The estimates are designed to reflect the costs of making the sites of the power stations available for alternative use in accordance with the Group’s decommissioning strategy.

Projected Payment Details

Based on current estimates of station lives and lifetime output projections, the following table shows, in current prices, the likely undiscounted payments, the equivalent sums discounted at 3% per annum to the balance sheet date and the amounts accrued to date.

	Back end fuel costs contracted	Back end fuel costs uncontracted	Decommissioning	Group 2003 Total	Group 2002 Total
	£bn	£bn	£bn	£bn	£bn
Undiscounted	5.1	4.6	5.0	14.7	14.1

Discounted	3.3	1.0	1.0	5.3	5.2

Accrued to date	2.2	0.7	1.0	3.9	3.7

The differences between the undiscounted and discounted amounts reflect the fact that the costs concerned will not fall due for payment for a number of years. The differences between the discounted amounts and those accrued to date will be charged to the profit and loss account over the remaining station lives since they relate to future use of fuel.

Under the terms of the contracts with BNFL referred to above and in accordance with the projected pattern of payments for decommissioning and other liabilities, taking account of the decommissioning fund arrangements described in note 2 (xvi), the undiscounted payments in current prices are expected to become payable as follows:

	Back end fuel costs contracted	Back end fuel costs uncontracted	Decommissioning	Group 2003 Total	Group 2002 Total
	£m	£m	£m	£m	£m
Within 1 year	355	—	18	373	261
Within 1-2 years	234	—	19	253	264
Within 2-3 years	217	7	18	242	254
Within 3-4 years	181	8	18	207	275
Within 4-5 years	194	15	19	228	254

Total within 5 years	1,181	30	92	1,303	1,308
6 - 10 years	1,063	101	227	1,391	1,411
11 - 25 years	1,629	410	336	2,375	2,683
26 - 50 years	708	1,082	55	1,845	1,188
51 years and over	487	3,002	—	3,489	3,436

	5,068	4,625	710	10,403	10,026

F-39

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

24. OTHER PROVISIONS

	Eggborough site restoration	Interest rate swaps	Onerous trading contracts		Restructuring		2003 Total		2002 Total
	£m	£m	£m		£m		£m		£m
As at April 1, 2002	—	—	344		5		349		180
Provided in year	3	56	2		3		64		209
Revalorization	—	—	10		—		10		12
Utilized in the year	—	—	(40	)	(5	)	(45	)	(52	)
Reclassified as other creditors	—	—	(316	)	—		(316	)	—

As at March 31, 2003	3	56	—		3		62		349

The interest rate swaps provision is in respect of swap contracts which were put in place to hedge interest rate risk. The Directors have reviewed the necessity for these swaps in the context of the financial restructuring of the Group and have concluded that the swaps are no longer effective as hedges, thereby necessitating the creation of a provision of £56m, Company £9m, being the out of the money element.

25. DEFERRED TAXATION

	2003		2002
	£m		£m
Accelerated capital allowances	(56	)	1,020
Other long term timing differences	(64	)	(63	)
Short term timing differences	20		41
Corporation tax losses	(262	)	(189	)
ACT recoverable offset	—		(76	)

Undiscounted (asset)/provision for deferred tax	(362	)	733
Discount	212		(319	)
De-recognition of asset	150		—

Discounted provision for deferred tax	—		414


	Group
	2003		2002
	£m		£m
As at April 1, 2002	414		404
Provision set up on acquisition of Bruce Power assets	—		18
Release of provision set up on acquisition of Bruce Power assets	(18	)	—
Credit on exceptional items	(520	)	(56	)
De-recognition of asset exceptional item	150		—
(Credit)/charge for the loss/profit in year (note 10)	(26	)	48

As at March 31, 2003	—		414

The Company does not have a deferred tax liability at March 31, 2003 (2002: £nil).

F-40

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

26. POST RETIREMENT BENEFIT OBLIGATIONS

UK Pension Schemes

British Energy operates two separate pension arrangements in the UK within the Electricity Supply Pension Scheme (ESPS), the British Energy Generation Group (BEGG) for the majority of employees and the British Energy Combined Group (BECG) for the employees at Eggborough Power Station. The ESPS is a defined benefit scheme, which is externally funded and subject to triennial actuarial valuation. Each pension group that participates in the ESPS is financially independent from the other groups.

The most recent triennial valuations of the BEGG and BECG schemes were carried out at March 31, 2001 by the independent ESPS actuary. The valuations for accounting purposes have been carried out by a separate independent actuary using the projected unit method. The principal assumptions adopted for both these accounts valuations were that, over the long term, the investment rate of return would be 6% per annum for benefits already accrued, and 6.5% for the return achieved on future contributions. The rate of salary increase would be 4% per annum and the rate of pension increase would be 2.5% per annum. Assets were taken at market value. At the date of the valuation, the combined market value of assets of both schemes was £1,944m. This represents 119% of the benefits that had accrued to members after allowing for expected future increases in earnings.

British Energy contributed 10% to the BEGG and 15.3% to the BECG for the period from April 1, 2002 to October 31, 2002. The BEGG contribution was increased to 17.1% from November 1, 2002. Contributing members contribute 5% and 6% to the respective plans. Any deficiency disclosed in the BEGG or BECG following an actuarial valuation has to be made good by British Energy.

The Group’s UK pension costs for the year to March 31, 2003 were £6m net of surplus amortization (2002: £1m). At that date there was a SSAP24 prepayment of £72m (2002: £50m) in the UK.

Bruce Power Pension Scheme

Bruce Power Inc provides pensions, group life insurance and health care benefits for retirees in Canada. Pensions are provided through the Bruce Power Pension Plan, which is a defined benefit scheme and is externally funded and subject to triennial actuarial valuations. Members of the plan contribute on average 5% of their salaries to the scheme. Bruce Power contributed the balance of the cost of providing the pension.

Bruce Power also operates a supplemental retirement pension plan which provides additional pensions to some retirees. This plan is not funded. Retiree group life insurance and health care benefits are also not pre-funded.

The Group’s Bruce Power related pension costs for the period of ownership from April 1, 2002 to February 14, 2003 were £12m (2002: £10m).

FRS17 Disclosures

The Group has not implemented FRS17 ‘Retirement benefits’ in the accounts for the year ended March 31, 2003. The disclosures required under the transitional arrangements for UK and Canadian plans within FRS 17 as advised by the Company’s actuaries are, however, set out below.

F-41

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(i) UK Pension Schemes

a) Major assumptions for significant defined benefit schemes:

	2003	2002
	% pa	% pa
Price inflation	2.25	2.75
Rate of general increase in salaries	3.75	4.25
Rate of increase of pensions in payment*	2.25	2.75
Rate of increase of deferred pensions*	2.25	2.75
Discount rate	5.50	6.0

in excess of Guaranteed Minimum Pension (GMP) element

b) Impact of full compliance with FRS17 if the consolidated financial statements had been drawn up on the basis of the assumptions above:

	2003 (Gain)/Loss
	£m
Operating Profit
Current service cost	32
Past service cost	13

Total charge to operating profits	45

Finance income
Expected return on assets in the pension scheme	(132	)
Interest on pension scheme liabilities	107

Net credit to finance income	(25	)

Total P&L charge before tax	20

Consolidated statement of total recognized gains and losses
Actual return less expected return on post employment plan assets	410
As % of plan assets at end of year	27	%
Experience losses arising on plan liabilities	(3	)
As % of plan liabilities at end of year	—
Changes in assumptions (financial & demographic)	—

Actuarial loss recognizable in consolidated statement of total recognized gains and losses (before tax)	407

As % of plan liabilities at end of year	22	%

	2003		2002
	£m		£m
Balance sheet impact
The fair value of plan assets at March 31	1,525		1,842
The present value of plan liabilities at March 31	(1,877	)	(1,799	)

Net pension (deficit)/asset	(352	)	43
Other non-pension post retirement benefits	—		—
Related deferred tax liability	—		—

Net (deficit)/asset for post retirement benefits net of tax	(352	)	43

F-42

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

No deferred tax asset is recognizable on the pension deficit in 2003, based on application of the deferred tax accounting policy set out in note 2 (xiv).

c) Movement in plan surplus during the year:

	2003
	£m
Surplus in plan at beginning of the year	43

Contributions paid	31
Current service cost	(32	)
Past service cost	(12	)
Other finance income	25
Actuarial loss	(407	)

Deficit in the plan at the end of the year	(352	)

d) Assets in the plan together with expected long-term rate of return:

	Rate of return	Value at March 31 2003	Rate of Return	Value at March 31 2002
	%	£m	%	£m
Equities	8.5	878	8.0	1,248
Bonds	4.5	438	5.3	412
Property	6.5	183	6.7	175
Others	3.75	26	4.75	7

		1,525		1,842

F-43

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(ii) Bruce Power Pension Scheme

a) Major assumptions for significant defined benefit scheme:

	2003	2002
	% pa	% pa
Price inflation	2.75	2.75
Rate of general increase in salaries	3.75	3.75
Rate of increase of pensions in payment	2.75	2.75
Discount rate	7.0	7.0

b) Impact of full compliance with FRS17 if the consolidated financial statements had been drawn up on basis of the assumptions above:

	2003 (Gain)/Loss
	£m
Operating Profit
Current service cost	15
Past service cost	—

Total charge to operating profits	15

Gain on settlements—disposal of Bruce Power	(103	)

Finance income
Expected return on assets in the pension scheme	(26	)
Interest on pension scheme liabilities	26
Net credit to finance income	—

Total P&L (credit)/charge before tax	(88	)

Consolidated statement of total recognized gains and losses
Actual return less expected return on post employment plan assets	50
Experience gains and losses arising on plan liabilities	—
Changes in assumptions (financial & demographic)	2
Foreign exchange adjustments	(4	)

Actuarial loss recognizable in consolidated statement of total recognized gains and losses (before tax)	48

	2003	2002
	£m	£m
Balance sheet impact
The fair value of plan assets at March 31	—	422
The present value of plan liabilities at March 31	—	(396	)

Net pension asset	—	26
Other non-pension post retirement benefits	—	(64	)
Related deferred tax liability	—	(2	)

Net deficit for post retirement benefits net of tax	—	(40	)

F-44

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

c) Movement in plan surplus during the year:

	2003
	£m
Deficit in plan at beginning of the year	(38	)
Contributions paid	—
Current service cost	(15	)
Past service cost	—
Gain on settlement	103
Foreign exchange	2
Other finance income	—
Actuarial loss	(52	)

Deficit in the plan at the end of the year	—

d) Assets in the plan together with expected long-term rate of return

	Rate of Return	Value at March 31 2003	Rate of Return	Value at March 31 2002
	%	£m	%	£m
Equities	—	—	8.5	255
Bonds	—	—	6.0	151
Property	—	—	—	—
Others	—	—	5.0	16

		—		422

27. CALLED UP SHARE CAPITAL

	2003	2002	2001
	£m	£m	£m
Authorized
991,679,020 ordinary shares of 44²⁸/43p each	443	443	443
720,339,029 ‘A’ shares of 60p each	432	432	432
One special rights redeemable preference share of £1	—	—	—

	875	875	875

Allotted, called up and fully paid
620,362,444 ordinary shares of 44²⁸/43p each	277	277	277
80,908,247 ‘A’ shares of 60p each	48	48	48
74,752,351 deferred ‘A’ shares of 60p each	45	45	45
One special rights redeemable preference share of £1	—	—	—

	370	370	370

(a) Special Rights Redeemable Preferences Share of £1

The special rights redeemable preference share is redeemable at par at any time after September 30, 2006 at the option of the Secretary of State, after consulting the Company. This share, which may

F-45

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

only be held by a Minister of the Crown or other person acting on behalf of HM Government, does not carry any rights to vote at general meetings, but entitles the holder to attend and speak at such meetings. The special share confers no right to participate in the capital or profits of the Company beyond its nominal value. Certain matters, in particular, the alteration of specific sections of the Articles of Association of the Company (including the Article relating to limitations that prevent a person having the right to have an interest in 15% or more of the voting share capital), require the prior written consent of the holder of the special share.

(b) ‘A’ Shares and Deferred Shares

The ‘A’ shares are traded on the London Stock Exchange and at March 31, 2003 had a market value of 3p (2002: 51p). The deferred shares have a £nil fair value at March 31, 2003 (2002: £nil).

The ‘A’ shares and deferred shares do not carry any rights to receive notice of, attend, speak or vote at any general meeting, unless in the case of ‘A’ shares the meeting is due to consider a resolution for the winding up of the Company, or the non cumulative preferential dividend remains unpaid six months or more after it fell due. On a winding up of the Company, the ‘A’ shares have preferential rights over the ordinary shares in respect of the distribution of capital. The ‘A’ shares confer no rights to participate in the capital or profits of the Company beyond their nominal value. The deferred shares do not confer any rights to participate in the capital or profits of the Company, including on a winding up of the Company.

F-46

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(c) Share Option Schemes

Options outstanding at March 31, 2003, together with their exercise prices and earliest dates of exercise, are as follows:

	Exercise price per share	Exercise Date	No. of Ordinary Shares
	£		2003	2002
British Energy ShareSave Scheme	1.60	2001	—	21,562
	1.95	2002	—	859,398
	4.44	2001	—	6,593
	4.44	2003	174,600	199,089
	4.39	2002	—	191,805
	4.39	2004	113,268	142,757
	1.36	2003	4,895,405	5,983,552
	1.36	2005	3,624,113	4,547,742
	2.61	2004	484,116	1,644,154
	2.61	2006	485,011	2,105,241
	2.29	2005	499,455	1,761,994
	2.29	2007	453,946	1,856,523
	1.36	2005	3,726,626	—
	1.36	2007	4,616,840	—

Employee Share Scheme	2.60	2000	6,423,428	6,644,826
	4.08	2000	516,572	530,572
	5.08	2001	3,915,603	4,045,603
	5.29	2002	4,022,000	4,169,000

Senior Management Share Scheme	2.60	2000	1,099,802	1,477,875
	3.95	2000	22,264	22,264
	5.08	2001	444,425	660,531
	6.67	2002	19,865	19,865
	5.29	2002	599,337	688,582
	3.57	2002	33,952	33,952
	2.41	2003	1,636,752	1,992,092
	2.49	2003	—	100,401
	3.18	2004	125,786	125,786

28. PROFIT AND LOSS ACCOUNT

	Group						Company
	2003		2002		2001		2003		2002		2001
					(restated)
	£m		£m		£m		£m		£m		£m
As at April 1, 2002	(213	)	372		517		1,495		1,855		1,945
Loss for the year	(3,941	)	(577	)	(21	)	(6,058	)	(360	)	(90	)
Foreign currency translation adjustments	(25	)	(8	)	6		—		—		—
Prior year adjustment	—		—		(130	)	—		—		—

	(4,179	)	(213	)	372		(4,563	)	1,495		1,855

F-47

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The profit and loss account of the Group at March 31, 2003 did not include any unrealized profits (2002:£82m) (see note 2(xvi)).

The Company did not have distributable reserves at March 31, 2003 (2002: £491m).

29. RECONCILIATION OF MOVEMENT IN EQUITY SHAREHOLDERS’ FUNDS

	Group
	2003		2002
	£m		£m
As at April 1, 2002	490		1,075
Loss for the financial year	(3,941	)	(527	)
Ordinary dividend	—		(48	)
Foreign currency translation adjustments	(25	)	(8	)
Non-equity dividend	—		(2	)

As at March 31, 2003	(3,476	)	490

30. RECONCILIATION OF OPERATING PROFIT TO OPERATING NET CASH FLOWS

	Continuing activities		Discontinued activities		Group
	Continuing activities		Discontinued activities		2003		2002		2001
	£m		£m		£m		£m		£m
Operating (loss)/profit including exceptional items	(3,899	)	97		(3,802	)	(281	)	280
Exceptional items	3,906		—		3,906		512		(54	)
Depreciation charges	274		13		287		285		277
Nuclear liabilities charged to operating costs	105		—		105		156		132
Nuclear liabilities discharged	(115	)	—		(115	)	(332	)	(319	)
Other provisions discharged	(45	)	—		(45	)	(43	)	(39	)
Regular contributions to decommissioning fund	(18	)	—		(18	)	(18	)	(17	)
Decrease in stocks	72		(12	)	60		66		27
Decrease/(increase) in debtors	12		(30	)	(18	)	(117	)	97
(Decrease)/increase in creditors	(48	)	24		(24	)	152		(107	)

Net cash inflow from operating activities	244		92		336		380		277
Payments to acquire tangible fixed assets	(112	)	(170	)	(282	)	(225	)	(133	)

Net cash inflow from operating activities net of capital expenditure	132		(78	)	54		155		144

31. RECONCILIATION OF NET CASH FLOW TO MOVEMENT IN FUNDS

	2003		2002		2001
	£m		£m		£m
Increase in cash in the year	87		—		—
Increase/(decrease) in liquid resources	37		(18	)	190
Decrease/(increase) in debt	185		(111	)	16

Decrease/(increase) in net debt in the year	309		(129	)	206
Net debt at start of year	(859	)	(730	)	(936	)

Net debt at end of year	(550	)	(859	)	(730	)

F-48

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

32. ANALYSIS OF NET DEBT

	Cash at bank and in hand	Term Deposits		Debt due within one year		Debt due after more than one year		Net funds/ (debt)
	£m	£m		£m		£m		£m
As at March 31, 2001	—	227		(40	)	(917	)	(730	)
Cash flows	—	(18	)	(113	)	2		(129	)

As at March 31, 2002	—	209		(153	)	(915	)	(859	)
Cash flows	87	37		1		91		216
Disposal of Bruce Power debt	—	—		—		93		93

As at March 31, 2003	87	246		(152	)	(731	)	(550	)

Cash not immediately required for business purposes is invested in fixed rate term deposits and commercial paper. At March 31, 2003, these instruments were due to mature within one month and earned interest at an average rate of 3.7% in the UK. Term deposits and bank balances at March 31, 2003 include £209m of cash which has been deposited in collateral bank accounts for trading purposes, availability of this cash is therefore restricted over the period of the collateralized position.

33. CONTINGENT ASSETS

The Group has not recognized certain cash retentions in respect of the disposal of Bruce Power as an asset in its balance sheet at March 31, 2003, because of uncertainties regarding their realization. The conditions attached to these retentions are described more fully in note 6.

34. CONTINGENT LIABILITIES

These accounts are drawn up on a going concern basis, the basis of which is explained more fully in note 1 to these accounts. This note describes the contingent liabilities which are applicable to the Group and the Company.

The Group has been provided with a financing facility by the Secretary of State for Trade and Industry, (the “Secretary of State”) as described in note 1 to these accounts. As at March 31, 2003 the Group had drawn down no cash drawings and had not utilized collateral available under the financing facility to support trading operations in the UK.

The following security has been granted for obligations under the financing facility made available by the Secretary of State for Trade and Industry:

•

An all monies debenture creating fixed security (by way of assignment and/or fixed charge) over certain intra-group receivables, and special accounts and a floating charge between the Secretary of State and certain Group companies.

•

Fixed charges in relation to the UK nuclear power stations.

•

Pledge and mortgage of shares in certain Group subsidiaries in favor of the Secretary of State.

•

Pledge agreement between British Energy US Holdings Inc and the Secretary of State over certain membership interests in British Energy US Investments LLC and certain limited partnership interests in British Energy LP.

F-49

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Amounts owing by Eggborough Power Limited (“EPL”) to the Eggborough bank syndicate are not guaranteed by the Company. However, the Company guarantees the payment of amounts by British Energy Power & Energy Trading Limited to EPL, calculated to cover EPL’s borrowing and operating costs. In addition the Company also provides a subordinated loan facility to EPL.

The Group has entered into formal standstill agreements with certain significant creditors and BNFL and it has also reached non-binding agreement in principle regarding the recognition, compromise and allocation of certain claims under the terms of the restructuring as announced on November 28, 2002. However, while the Directors believe that the amounts of the agreed claims currently reflect the amounts legally claimable, in the event of restructuring not being completed then different amounts may be calculated as being claimable.

On September 25, 2002 the Nuclear Generation Decommissioning Fund Limited (the “Fund”) served a default notice relating to the solvency of the Company, British Energy Generation Limited and British Energy Generation (UK) Limited. Unless the default is cured to the satisfaction of the Fund, or waived, the Fund has the right to require accelerated payment of all of the contributions due to the Fund prior to the next quinquennial review in autumn 2005. Annual payments are in the region of £18m. The Fund has agreed not to take enforcement action without further notice while the Group progresses satisfactorily toward achieving restructuring.

The Directors understand that AES and Greenpeace have lodged an appeal in the Court of First Instance in Luxembourg against the EU approval of HMG’s decision to grant rescue aid to the Group. The Directors also understand that other parties may take similar action.

The Group has given certain indemnities and guarantees in respect of the disposal of its investment in Bruce Power. The Group does not currently anticipate any losses will arise in connection with them.

The Group is involved in a number of other claims and disputes arising in the normal course of business which are not expected to have a material effect on the Group’s financial position.

The Company has given certain indemnities and guarantees in respect of its subsidiary undertakings. No losses are anticipated to arise under these indemnities and guarantees, provided relevant subsidiary undertakings continue as going concerns.

35. FINANCIAL COMMITMENTS

	2003	2002
	£m	£m
Capital expenditure contracted but not provided	40	93

In addition to the reprocessing commitments there are commitments at March 31, 2003 for nuclear fuel purchase totaling £583m, at current prices, over the next 10 years. These commitments may be subject to change in the future as the Group’s contractual terms with BNFL are expected to be amended in the event of the successful completion of the restructuring proposals.

In addition to the liabilities and provisions recognized and described in the notes to the financial statements the Group has provided certain guarantees and commitments in respect of the extent of capital expenditure by Eggborough Power Limited and AmerGen. The Group also enters into commitments to purchase and sell electricity in the normal course of business.

F-50

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

36. POST BALANCE SHEET EVENTS

(i) Audited

In April 2003 the Group received payment of C$20m in respect of a pension related cash retention which formed part of the disposal proceeds of its investment in Bruce Power. The receipt of this cash has been recognized in the accounts to March 31, 2003 as being part of the disposal proceeds of Bruce Power as described more fully in note 6.

(ii) Unaudited.

On September 11, 2003 the Board of British Energy (the “Board”) announced that British Energy and certain of its subsidiaries have entered into an agreement to dispose of British Energy’s entire 50% interest in AmerGen Energy Company, LLC (“AmerGen”) to FPL Energy, LLC (“FPL Energy”) which is a wholly owned subsidiary of FPL Group (NYSA:FPL), for approximately US$277m (£174m) subject to adjustment for changes in working capital compared to agreed target amounts. The proposed transaction is subject to a right of first refusal (“ROFR”) held by Exelon Generation Company, LLC (“Exelon”), British Energy’s partner in AmerGen. Under the limited liability company agreement (the “LLC Agreement”) relating to AmerGen, Exelon has the right to purchase British Energy’s 50% interest in AmerGen on the same terms as those offered by FPL Energy by giving notice of its intention to do so within 30 days of receiving notice of FPL Energy’s agreement to purchase British Energy’s interest in AmerGen. Exelon’s ROFR will terminate on October 11, 2003. The Board expects that it will require approximately six months to obtain the necessary regulatory approvals for a disposal of its interest in AmerGen to FPL Energy.

When the Group disposed of its investment in Bruce Power C$100 of proceeds was retained in escrow contingent upon the successful restart of two of the Bruce A reactors. The master purchase agreement provided that if the restart of these two reactors were to be delayed beyond June 15, 2003 and August 1, 2003 respectively, the consideration of C$50m per reactor will be reduced on a sliding scale falling to zero after nine months. Bruce Power did not succeed in restarting the two reactors by the dates specified. Consequently, while work continues to restart the reactors as soon as possible, the amounts of deferred compensation we receive will be reduced in line with the terms of the agreement.

The Group has been provided with a financing facility by the Secretary of State for Trade and Industry, as described in note 1 to these accounts. As at September 19, 2003 the Group had utilized £20.8m of the financing facility to support trading collateral requirements in the UK.

On July 2, 2003 the Group announced that as part of its drive for enhanced operational effectiveness and reduced costs, it has concluded that 150 operational jobs based in Peel Park should be transferred to Barnwood, Gloucester to be integrated into the Company’s major operational and engineering support base. Simultaneously the Corporate Headquarters functions will be restructured but will remain in Scotland.

F-51

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

37. SUMMARY OF DIFFERENCES BETWEEN UK AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”)

(i) Notes on US GAAP Adjustments

British Energy’s consolidated statements have been prepared in accordance with UK GAAP which differs in certain significant respects from US GAAP. The effects of the US GAAP adjustments to the loss for the financial year and equity shareholders’ funds are set out in the tables below.

Effect on (Loss)/Profit of Differences Between UK GAAP and US GAAP

	Note		2003		2002		2001
			£m		£m		(restated) £m
(Loss)/profit for the year under UK GAAP			(3,941	)	(527	)	9
US GAAP adjustments:
Decommissioning costs	(a	)	(70	)	(151	)	(153	)
Decommissioning fund	(b	)	—		6		(16	)
Uncontracted back end fuel costs	(c	)	(450	)	(155	)	(71	)
Amortization of capitalized interest	(d	)	(6	)	(4	)	(6	)
Bonds renegotiation	(e	)	(9	)	(9	)	(9	)
Employee stock compensation schemes	(f	)	—		(4	)	(5	)
Employee share trusts	(g	)	102		12		12
Capitalization of Bruce costs	(h	)	(1	)	(5	)	(10	)
Pension costs	(i	)	(1	)	(8	)	10
Investment in joint venture	(j	)	42		(5	)	(4	)
FAS 133 adjustments	(l	)	(8	)	121		—
Foreign currency	(m	)	—		—		9
Write down of fixed asset carrying values	(n	)	(2,942	)	300		—
Adjustment for Bruce Power Lease	(o	)	(11	)	(11	)	—
Loss on sale of Bruce Power	(p	)	29		—		—
Deferred tax under full provision method	(q	)	(1,425	)	38		43
Tax effect of US GAAP adjustments			959		65		67

Loss for the financial year under US GAAP before cumulative adjustment for FAS133			(7,732	)	(337	)	(124	)
Cumulative adjustment for FAS 133 (net of tax)	(l	)	—		(89	)	—

Loss for the year under US GAAP			(7,732	)	(426	)	(124	)


			2003		2002		2001
Basic and diluted net loss per share under US GAAP			(1,284	)p	(71.2	)p	(21.0	)p
Basic and diluted net loss per share under US GAAP—continuing operations			(1,293	)p	(74.0	)p	—
Basic and diluted net loss per share under US GAAP—discontinued operations			8.8	p	2.8	p	—

Basic and diluted loss per share before cumulative adjustments for FAS 133			(1,284	)p	(56.3	)p	(21.0	)p
Basic and diluted loss per share arising from cumulative adjustment for FAS 133			—		(14.9	)p	—

			(1,284	)p	(71.2	)p	(21.0	)p

F-52

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Effect on Equity Shareholders’ (Deficit)/Funds of Differences Between UK GAAP and US GAAP

	Note		2003		2002
			£m		£m
Equity shareholders’ (deficit)/funds under UK GAAP			(3,476	)	490
US GAAP Adjustments:
Decommissioning costs	(a	)	(1,375	)	(1,305	)
Decommissioning fund	(b	)	—		—
Uncontracted back end fuel costs	(c	)	(1,630	)	(1,180	)
Capitalization of interest	(d	)	54		60
Bonds renegotiation	(e	)	29		38
Employee share trusts	(g	)	(2	)	(104	)
Capitalization of Bruce costs	(h	)	(16	)	(15	)
Pension costs	(i	)	(215	)	142
Investment in joint venture	(j	)	33		(9	)
Dividends	(k	)	—		32
FAS133 adjustments	(l	)	(12	)	(34	)
Write down of fixed asset carrying values	(n	)	(2,642	)	300
Adjustment for Bruce Power lease	(o	)	(22	)	(11	)
Loss on sale of Bruce Power	(p	)	29		—
Deferred tax methodology	(q	)	(1,744	)	(319	)
Tax effect of US GAAP adjustments			1,744		687

Deficit on Equity shareholders’ funds under US GAAP			(9,245	)	(1,228	)

Reconciliation of movement in deficit on equity shareholders’ funds under US GAAP

	2003		2002
	£m		£m
As at April 1, 2002	(1,228	)	(736	)
Loss for the year under US GAAP	(7,732	)	(426	)
Dividends under US GAAP	(32	)	(48	)
Employee Share Trusts under US GAAP	—		18
Employee Stock Compensation Schemes under US GAAP	—		4
Cumulative translation adjustments	(25	)	(8	)
Other comprehensive income—FAS 133	21		(21	)
Additional minimum pension liability	(249	)	—
Unrealized loss on available-for-sale securities	—		(11	)

As at March 31, 2003	(9,245	)	(1,228	)

(ii) Notes on US GAAP Adjustments

(a) Decommissioning Costs

The estimated costs of decommissioning the Group’s power stations are provided for when stations begin operating commercially and are capitalized as part of the costs of construction and are depreciated over the same lives as the stations. Under UK GAAP these estimated costs are initially recorded in the balance sheet at current prices and discounted at a long-term real rate of interest of 3% per annum to take account of the time scale whereby the work will take place many years after station

F-53

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

closure (this equates to a present value calculated by assuming an inflation rate of 2% and a risk free discount rate of 5.1%). In each subsequent year, the provision is revalorized to reflect the movement in current price levels and the unwinding of one year’s discount.

This revalorization is classified as a financing charge in the income statement. Under US GAAP such uncontracted liabilities require to be recognized on an undiscounted basis and the annual movement in current price levels is capitalized each year.

The scale of the depreciation adjustment required in the 2003 results is smaller than in prior years, reflecting the fact that the UK GAAP and US GAAP results in 2003 include an impairment charge on decommissioning assets.

The reconciling item relating to decommissioning costs is analyzed below, showing the effect on separate line items in each year.

	2003		2002		2001
	£m		£m		£m
*Balance Sheet*
Fixed assets
Cost	4,913		4,769		4,661
Depreciation	(2,326	)	(2,199	)	(2,000	)

Net book value (before impairment charge see note (n))	2,587		2,570		2,661

Decommissioning liability	(3,962	)	(3,875	)	(3,815	)

Total shareholders’ funds adjustment	(1,375	)	(1,305	)	(1,154	)

	2003		2002		2001
	£m		£m		£m
*US GAAP adjustments to Profit and Loss Account*
Depreciation expense of undiscounted decommissioning costs	(127	)	(199	)	(190	)
Revalorization of decommissioning liability	57		48		37

Total profit and loss adjustment	(70	)	(151	)	(153	)

(b) Decommissioning Fund

The amount of the Group’s decommissioning fund as recorded in its UK GAAP balance sheet represents the contributions made by the Group, together with an estimated actuarially determined long-term rate of return on the fund. The change in amount arising from applying the estimated long-term rate of return is taken to the profit and loss account and disclosed as part of revalorization. See note 2(xvi). If the actuarial value exceeds the market value of the investment in the fund then the decommissioning fund is stated at the lower amount.

Under US GAAP, the debt and equity securities held by the Group’s independently administered decommissioning fund are classified as “available-for-sale” securities within Investments (non-current) and stated at market value. Under UK GAAP an exceptional charge of £124m was made in the year ended March 31, 2003 (2002: £27m) to write down the carrying value of the investments to market value. Consequently there is no difference between the carrying amount of these investments on an UK GAAP and a US GAAP basis in the year ended March 31, 2003.

In accordance with Statement of Financial Accounting Standard (FAS) 115, “Accounting for Certain Investments in Debt and Equity Securities”, these securities are reported at their estimated fair

F-54

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

value of £334m as of March 31, 2003 and £411m as of March 31, 2002 in the Group’s Consolidated Balance Sheet under “Decommissioning Fund”. Realized gains and losses from these securities are included in profit. Unrealized gains and losses are excluded from profit until realized and reported as a separate component of equity shareholders’ funds unless the unrealized loss is deemed to be “other-than-temporary”. At March 31, 2003 the decline in value was deemed to be “other-than-temporary” by the Directors, and a charge of £94m was recorded in the profit and loss account for US GAAP. This charge represents the sum of the exceptional and revalorization charge recorded for UK GAAP in the year ended March 31, 2003.

Information on investments in securities held by the decommissioning fund by major security type (in millions):

	March 31, 2003							March 31, 2002
	Gross gains/(losses) (£m)							Gross gains/(losses) (£m)
	Cost	Unrealized Gain	Unrealized Loss		Realized Loss		Fair value	Cost	Unrealized Gain	Unrealized Loss		Fair value
UK equities	225	8	(4	)	(62	)	167	199	37	(32	)	204
Non-UK equities	123	8	(2	)	(30	)	99	108	27	(12	)	123
Index linked gilts	23	3	(1	)	—		25	36	3	—		39
Property	43	2	—		(2	)	43	46	1	(2	)	45

	414	21	(7	)	(94	)	334	389	68	(46	)	411

Using the specific identification method to determine cost, the gross realized gains and losses were:

	2003		2002
	£m		£m
Gross realized gains	—		—
Gross realized losses	(94	)	—

	(94	)	—

Proceeds from sales of available-for-sale securities were £69m and £58m during the years ended March 31, 2003 and 2002 respectively. These proceeds were not withdrawn from the fund.

(c) Uncontracted Back End Fuel Costs

Back end fuel costs comprise the estimated costs of reprocessing and storage of spent nuclear fuel and the long-term storage, treatment and eventual disposal of resulting waste products. The vast majority of these costs relate to reprocessing, treatment and storage services that are the subject of contracts with BNFL. The other costs, which are not subject to fixed contractual arrangements, primarily represent estimated disposal costs and are based on long-term cost forecasts which are regularly reviewed and adjusted where necessary.

Under UK GAAP both contracted and uncontracted back end fuel cost liabilities are recorded in the balance sheet at current price levels and discounted at a real rate of interest of 3% per annum to take account of the timing of payments (this equates to a present value calculated by assuming an inflation rate of 2% and a risk free discount rate of 5.1%). US GAAP requires uncontracted back end

F-55

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

fuel liabilities to be recognized in the accounts on an undiscounted basis, because the precise amount and timing of the related payments are not fixed or reliably determinable, and this change in methodology gives rise to the significant adjustments to the profit and loss account and shareholders’ funds under US GAAP.

The table below analyzes the effect on profit before tax of differences between UK GAAP and US GAAP with regard to uncontracted back-end fuel costs.

	2003		2002
	£m		£m
Adjustments from UK to US GAAP (i.e. recognizing liability on an undiscounted basis)	(450	)	(155	)

US GAAP Adjustments:
Uncontracted back-end fuel costs	(460	)	(150	)
Reclassifications	32		—
Revalorization of uncontracted back-end fuel costs	(22	)	(5	)

Uncontracted back-end fuel costs	(450	)	(155	)

The 2003 adjustment for uncontracted back end fuel costs is higher than in prior years to reflect a management assumption that the disposal repository for Intermediate Level Waste will not now be available prior to 2040. The 2001/02 annual accounts were drawn up on the assumption of repository availability from 2012.

(d) Capitalization and Amortization of Interest

Under UK GAAP, interest payable may be capitalized where borrowings are specifically financing the construction of a major capital project with a long period of development. British Energy has not elected to capitalize interest. US GAAP requires that interest incurred on borrowings, which could have been avoided if the expenditure on the asset had not been made must be included in tangible fixed assets and depreciated over the lives of the related assets. For US GAAP purposes the amount of interest capitalized is determined by reference to average interest rates on outstanding long-term borrowings. Under US GAAP, the gross amount of capitalized interest is £2,037m (2002: £2,037m), and the total accumulated depreciation is £1,983m (2002: £1,977m).

(e) Bonds Renegotiation

Under UK GAAP, gains and losses on linked transactions should be recognized only where justified by a change in the substance of the entity’s assets and liabilities. The Group concluded that the repurchase and sale of bonds constituted two distinct transactions that caused a significant change in the substance of its commitments due to the increase in the bond principal and changes in underlying covenants.

For US GAAP purposes, only gains and losses arising from an exchange of debt instruments with a substantially different economic substance should be recognized. A modification of debt is considered substantially different if the present value of the cash flows under the terms of the new debt instrument differ by at least ten percent from the present value of the remaining cash flows under the terms of the original instrument. The renegotiation occurred immediately before March 31, 1999. The increase in principal of £66m is amortized, on a weighted average basis, over the life of the bonds.

F-56

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(f) Employee Stock Compensation Schemes

The Group has three stock compensation schemes—a ShareSave Scheme, an Employee Share Scheme, and an Executive Share Option Scheme. Under UK GAAP, the ShareSave Scheme is specifically exempt by Inland Revenue from the requirement to recognize compensation cost. For the Employee Share Scheme and the Executive Share Option Scheme, the total compensation charge is recognized as the difference between the cost of the shares and the price at which the options can be exercised. This charge is amortized over the period from the grant date to the earliest date of exercise.

Under US GAAP, the Group has elected to account for its stock compensation schemes in accordance with statement of Financial Accounting Standards (FAS) No. 123 using the Black-Scholes option-pricing model, under which a fair value is calculated for the share option schemes as at the date of grant of the options. This fair value, less amounts to be contributed by employees is charged to the profit and loss account over the period from the date the options were granted to the date at which the options are expected to vest on the employees. The corresponding credit is included in Shareholders’ Funds.

A reconciliation of the options outstanding is as follows:

	ShareSave Scheme				Employee Share Scheme				Executive Share Option Schemes
	Number of Shares		Weighted Average Exercise Price per Share		Number of Shares		Weighted Average Exercise Price per Share		Number of Shares		Weighted Average Exercise Price per Share
Outstanding March 31, 1998	19,890,979		£	1.65	9,079,470		£	2.71	2,759,036		£	2.70
Options granted	1,825,404		£	4.44	4,665,713		£	5.08	1,052,389		£	5.13
Options exercised	(318,388	)	£	1.64	(13,188	)	£	3.08	(142,307	)	£	2.60
Options forfeited	(672,506	)	£	1.80	(207,172	)	£	3.01	—			—

Outstanding March 31, 1999	20,725,489		£	1.89	13,524,823		£	3.52	3,669,118		£	3.40
Options granted	3,271,462		£	4.39	4,900,000		£	5.30	1,071,356		£	5.24
Options exercised	(6,108,101	)	£	1.61	(129,355	)	£	2.83	(5,788	)	£	6.67
Options forfeited	(1,054,809	)	£	3.63	(291,028	)	£	4.31	(215,464	)	£	3.38

Outstanding March 31, 2000	16,834,041		£	2.37	18,004,440		£	4.00	4,519,222		£	3.83
Options granted	11,495,507		£	1.36	—			—	2,450,097		£	2.41
Options exercised	(1,300,699	)	£	1.95	—			—	—			—
Options forfeited	(4,669,408	)	£	4.44	(1,097,945	)	£	4.50	(691,665	)	£	4.70

Outstanding March 31, 2001	22,359,441		£	1.52	16,906,495		£	3.96	6,277,654		£	3.18
Options granted	7,368,479		£	2.45	—			—	125,786		£	3.18
Options exercised	(8,818,218	)	£	1.60	(647,282	)	£	2.60	(166,682	)	£	2.60
Options forfeited	(1,589,292	)	£	4.40	(869,210	)	£	4.50	(1,115,410	)	£	4.70

Outstanding March 31, 2002	19,320,410		£	1.80	15,390,003		£	3.99	5,121,348		£	3.05
Options granted	9,194,761		£	1.36	—			—	—			—
Options exercised	(13,348	)	£	1.36	—			—	—			—
Options forfeited	(9,428,443	)	£	1.91	(512,400	)	£	4.04	(1,139,165	)	£	3.21

Outstanding March 31, 2003	19,073,380		£	1.53	14,877,603		£	3.99	3,982,183		£	3.00

F-57

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

At March 31, 2003 the option groups outstanding, based on a range of exercise prices, were as follows:

	Options Outstanding
	Number Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price
ShareSave Scheme
£1.36 to £2.29	17,816,395	2.9	1.41
£2.30 to £4.44	1,256,995	2.5	3.02

Employee Share Scheme
£2.60 to £4.07	6,423,428	4.3	2.60
£4.08 to £5.29	8,454,175	5.7	5.10

Executive Share Option Schemes
£2.41 to £3.17	2,736,554	4.0	2.49
£3.18 to £5.08	626,427	3.1	4.58
£5.09 to £6.67	619,202	6.2	5.33

Using the Black-Scholes option-pricing model, the weighted average fair values on the date the options were granted were as follows:

	ShareSave Scheme		Employee Share Scheme		Executive Share Option Schemes
	2003	2002	2003	2002	2003	2002
	£	£	£	£	£	£
Weighted average fair value of those options for which the exercise price:
—exceeded market price on date of grant	0.27	—	—	—	—	—
—equaled market price on date of grant	—	0.80	—	—	—	1.29
—was below market price on date of grant	—	1.41	—	—	—	—

The following assumptions were used in the Black-Scholes option-pricing model:

	ShareSave Scheme				Employee Share Scheme		Executive Share Option Schemes
	2003		2002		2003	2002	2003	2002
Risk free interest rate	4.5-4.7	%	4.7-5.3	%	—	—	—	4.8	%
Expected dividend yield	5.7	%	3.4	%	—	—	—	3.4	%
Expected volatility	55	%	50-55	%	—	—	—	55	%
Expected life (years)	3.1-5.1		3.1-5.2		—	—	—	5

The risk free rate is the yield on the date of grant of an UK government bond with the closest maturity to the expected term of the option.

(g) Employee Share Trusts

Under current UK GAAP, the Company’s shares held in Employee Share Trusts are classified as “own shares” within fixed assets. The cost of these shares to the Employee Share Trusts is

F-58

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

subsequently written down to the amount expected to be received from employees over the period at the end of which the underlying options are exercisable by the employees, and in 2002/03 as the long-term prospects of the Company had deteriorated considerably a charge of £102m was recorded to recognize a permanent diminution in the value of the shares held. Under US GAAP, the issuance or sale of the Company’s shares to the Employee Share Trust is recorded as a debit balance within equity shareholders’ funds, therefore the UK GAAP amortization and impairment have been reversed. This account is subsequently credited as options are exercised, based on the cost of the shares to the Employee Share Trusts.

(h) Capitalization of Bruce Costs

UK GAAP allows for certain direct and indirect costs attributable to bringing an asset into working condition to be capitalized. Such costs would be written off over the estimated useful life of the associated asset. Certain of these costs would not be permitted to be capitalized under US GAAP and would be expensed as incurred. British Energy disposed of its interests in Bruce Power on February 14, 2003.

(i) Pension Costs

Under UK GAAP, the cost of providing pension benefits is expensed over the average expected service lives of eligible employees in accordance with the provisions of Statement of Standard Accounting Practice (SSAP) 24, which aims to produce an estimate of cost based on long-term actuarial assumptions. Variations from the regular pension cost arising from, for example, experience deficiencies or surpluses, are charged or credited to the income statement over the expected average remaining service lives of current employees in the schemes.

Under US GAAP, employee pension costs are recognized in accordance with FAS 87. FAS 87 requires the use of an actuarial method for determining defined benefit pension costs and provides for the deferral of actuarial gains and losses (in excess of a specified corridor) that result from changes in assumptions or actual experience differing from that assumed. FAS 87 also provides for the prospective amortization of costs related to changes in the benefit plan, as well as the obligation resulting from the transition. US GAAP also requires disclosure of the components of periodic pension cost and the funded status of the pension plans.

F-59

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The subsequent analysis sets out the disclosures applicable to discontinued and continued operations. The discontinued operations amounts relate to Bruce Power (which was sold on February 14, 2003) and are set out on a 100% holding basis. British Energy’s share in Bruce Power was 82.4% prior to disposal.

	2003						2002
	Discontinued Canadian Operations		Continued Operations		Total		Discontinued Canadian Operations		Continued Operations		Total
	£m		£m		£m		£m		£m		£m
Change in benefit obligation:
Projected benefit obligation at beginning of year	402		1,821		2,223		—		1,640		1,640
Foreign exchange movement	(42	)	—		(42	)	—		—		—
Bruce obligation transferred in	—		—		—		364		—		364
Service cost	13		28		41		15		33		48
Interest cost	22		107		129		22		96		118
Contributions by plan participants	4		10		14		2		9		11
FAS 88 termination cost	—		13		13		—		12		12
Net actuarial loss	—		6		6		—		109		109
Benefits paid	(1	)	(80	)	(81	)	(1	)	(78	)	(79	)
Settlement of benefit obligation	(398	)	—		(398	)	—		—		—

Benefit obligation at end of year	—		1,905		1,905		402		1,821		2,223

Change in plan assets:
Fair value of plan assets at beginning of year	423		1,842		2,265		—		1,954		1,954
Foreign exchange movement	(44	)	—		(44	)	—		—		—
Fair value of Bruce assets transferred in	—		—		—		415		—		415
Actual return on plan assets	(24	)	(278	)	(302	)	7		(59	)	(52	)
Employer contributions	—		31		31		—		16		16
Non participants contributions	4		10		14		2		9		11
Benefits paid	(1	)	(80	)	(81	)	(1	)	(78	)	(79	)
Settlement of plan asset	(358	)	—		(358	)	—		—		—

Fair value of plan assets at end of year	—		1,525		1,525		423		1,842		2,265

F-60

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

	2003						2002
	Discontinued Canadian Operations		Continued Operations		Total		Discontinued Canadian Operations		Continued Operations		Total
	£m		£m		£m		£m		£m		£m
Net pension asset recognized:
Funded status	—		(380	)	(380	)	21		21		42
Unrecognized transition (asset)	—		(46	)	(46	)	—		(58	)	(58	)
Unrecognized prior service cost	—		41		41		—		44		44
Unrecognized net actuarial loss	—		600		600		19		196		215
Adjustment for prior year redundancies	—		—		—		—		(10	)	(10	)

Net amount recognized	—		215		215		40		193		233

Minimum additional liability	—		(397	)	(397	)	—		—		—

Net pension (liability)/asset	—		(182	)	(182	)	40		193		233

Net periodic pension cost:
Service cost	13		29		42		15		33		48
Interest cost	22		107		129		22		96		118
Expected return on plan assets	(25	)	(131	)	(156	)	(26	)	(135	)	(161	)
Amortization of transition asset	—		(12	)	(12	)	—		(11	)	(11	)
Amortization of prior service costs	—		3		3		—		3		3

Net periodic pension charge/(credit)	10		(4	)	6		11		(14	)	(3	)
FAS 88 termination cost—current year	27		13		40		—		12		12
FAS 88 termination cost—prior year	—		—		—		—		10		10

Net periodic pension cost	37		9		46		11		8		19

	2003	2002
	%	%
Assumptions used to determine pension costs were as follows:
UK
Discount rate	5.50%	6.00%
Expected return on plan assets	7.00%	7.25%
Rate of compensation increase	3.75%	4.50%
Pension increases	2.25%	2.50%

Canada
Discount rate	7.00%	7.00%
Expected return on plan assets	7.50%	7.50%
Rate of compensation increase	3.75% plus merit	3.70% plus merit
Pension increases	2.75%	2.75%

F-61

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Under US GAAP the cost of other post retirement benefits (excluding pension costs) are recognized in accordance with FAS106. FAS106 requires the use of an actuarial method for determining other post retirement benefits. FAS106 only applies to our Canadian operation. The disclosures required under US GAAP are set out below on a 100% holding basis, British Energy’s share of Bruce Power was 82.4% prior to disposal.

	2003		2002
Changes in benefit obligation	£m		£m
Bruce obligation transferred in	46		47
Service costs	2		2
Interest cost	3		3
Amendments	7		—
Settlement of benefit obligation	(58	)	—

Benefit obligation at end of year	—		52

Net amount recognized
Funded status	—		52

Net period benefit cost
Service cost	—		2
Interest cost	—		4

Net periodic benefit cost	—		6

There are no plan assets during the period for the purposes of FAS 106.

(j) Investment in Joint Venture

The management accounts of AmerGen are prepared on a US GAAP basis and these are translated into a UK GAAP basis when they are reported through to the Group for incorporation into the Group’s UK statutory accounts. There are a number of differences between US GAAP and UK GAAP, primarily relating to the acquisition of AmerGen nuclear power stations, and the subsequent valuation of decommissioning fund assets and decommissioning liabilities. These differences impact on reported income and the carrying values of its investment in AmerGen on the Group’s balance sheet.

(k) Dividends

Under UK GAAP ordinary dividends are recognized in the financial year in respect of which they are recommended by the Board of Directors for approval of shareholders as required by UK company law. Under US GAAP, such dividends are not recognized until the period during which dividends are formally declared by the Board of Directors and subsequently approved by the shareholders.

Under UK law, dividends payable are restricted to the distributable reserves of the Group parent company (see note 28). No dividend has been declared for the 2002/03 financial year.

(l) FAS 133 Adjustments

The Group uses derivative instruments in the normal course of business, to offset fluctuations in earnings and cash flows associated with movements in exchange rates, interest rates and commodity prices. As explained more fully in Note 2 (xviii), energy trading financial derivatives and open positions on

F-62

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

physical energy trading contracts are recognized as either assets or liabilities and are marked to market each reporting period using externally derived market prices under UK GAAP. Subsequent movements in their fair value are reflected in the profit and loss account. Interest rate swaps and forward rate agreements are not marked to market each reporting period. Rather profits and losses on such derivatives are reported in the profit and loss account in the period in which the underlying hedging transactions are completed. When an anticipated transaction is no longer likely to occur, any deferred gain or loss that has arisen on the related derivative is recognized in the profit and loss account together with any gain or loss on the terminated item. FAS 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by FAS 137 and FAS 138 was adopted by the Group with effect from April 1, 2001. FAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities.

US GAAP requires that an entity recognize all derivatives as either assets or liabilities and measure those instruments at fair value each reporting period. US GAAP prescribes specific requirements for designation and documentation of hedging relationships and ongoing assessments of effectiveness in order to qualify for hedge accounting.

Derivative instruments are generally not held by the Company for speculative trading purposes. To the extent that such instruments are held for speculative trading purposes they are measured at fair value with gains and losses recorded in earnings. The fair value of trading derivatives at March 31, 2003 was £4m positive (2002: £2m positive).

The remaining £21m of the cumulative effect of adopting FAS133 at April 1, 2001 that was reported in other comprehensive income was recognized in earnings at March 31, 2003. This was due to the reduced term of the underlying debt and the resulting ineffectiveness of such interest rate swaps.

Certain contracts that meet the definition of derivative under FAS 133 may qualify as a normal purchase or a normal sale and be excluded from the scope of FAS 133. Specific criteria must be met in order for a contract that would otherwise be regarded as a derivative to qualify as a normal purchase or a normal sale. The Group has evaluated all commodity contracts to determine if they meet the definition of a derivative and qualify as a normal purchase or a normal sale. The Group also evaluates contracts for “embedded” derivatives, and considers whether any embedded derivatives have to be separated from the underlying host contract and accounted for separately in accordance with FAS 133 requirements. Where embedded derivatives have terms that are not clearly and closely related to the terms of the host contract in which they are included, they are accounted for separately from the host contract as derivatives, with changes in the fair value recorded in earnings, to the extent that the hybrid instrument is not already accounted for at fair value.

(m) Foreign Currency Hedges

Certain of the Group’s forward foreign currency contracts do not meet the specific criteria for US GAAP hedge accounting, because the underlying fuel contracts have variation clauses. Accordingly, these contracts have been marked-to-market for US reporting purposes. Following the introduction of FAS 133 these adjustments now form part of the FAS 133 adjustment discussed above.

(n) Write Down of Fixed Asset Carrying Values

In the March 31, 2003 UK GAAP accounts the Directors undertook a review of the carrying value of our fixed assets compared with the economic value and net realizable value of those assets. In

F-63

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

carrying out the economic valuations significant estimates were made of the future cash flows being generated by the assets, taking into account current and expected future market conditions and the expected lives of the Group’s power stations and in arriving at the economic values thereof. The assessment of future market conditions includes, for example, a view of likely over-capacity in the market over a number of years and the likely timing of the market returning to new entrant prices. The actual outcome can vary significantly from these future forecasts, thereby affecting the Group’s assessment of expected future cash flows. The expected future cash flows were discounted at a rate approximating the Group’s weighted average cost of capital as this is the rate most representative of those assets. The impairment review resulted in the value of our power stations being written down by £3,738 million for UK GAAP reported results.

In addition, the Directors have also performed an impairment review of the Group’s fixed assets under US GAAP, using consistent assumptions and estimates as those used for purposes of the impairment review under UK GAAP. However under US GAAP, fixed assets are written down to their fair value only when their carrying value exceeds their undiscounted future cash flows. In the current year the US GAAP impairment test indicated that the carrying value of the Group’s power stations exceeded their undiscounted future cash flows. As a result, the Group was required to record an additional impairment charge of £2,942 million for purposes of US GAAP in the year ended March 31, 2003. The additional impairment charge is due to the different treatment of certain plant costs, such as capitalized interest and decommissioning. Significant estimates are made when performing an impairment review. A change in any estimates of the future cash flows or in the method of determining the fair value of the Group’s power stations could result in a different impairment charge under US GAAP.

In the March 31, 2002 UK GAAP accounts, following a review of the economic values and net realizable value of the Group’s assets compared with their carrying value in the accounts, Eggborough power station was written down by £300m for UK GAAP purposes. Under US GAAP the economic value must be compared with carrying value on an undiscounted basis in order to be impaired. As a result Eggborough power station was not impaired on a US GAAP basis and the write down was reversed for the purposes of arriving at US GAAP profit and net assets.

(o) Adjustment for Bruce Power Lease

Under UK GAAP the Bruce Power lease is treated as an operating lease. As a result the lease is not capitalized in the Group balance sheet and the lease obligations are not recognized as a liability in the balance sheet. Rental payments are charged in the period to which they relate. Under US GAAP the lease is treated as a capital lease with interest and depreciation charges being recognized in the Group profit and loss account. British Energy disposed of its interests in Bruce Power on February 14, 2003.

The following is an analysis of the leased property under the lease by major classes.

	At March 31, 2003	At March 31, 2002
	£m	£m
Tangible assets (Bruce power station)	—	313
Less accumulated depreciation	—	(16	)

	—	297

Obligation under Capital Lease	—	316
Creditors	—	(8	)

	—	308

F-64

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

(p) Loss on Sale of Bruce Power

The UK GAAP results for the year ended March 31, 2003 include a loss of £35m in respect of the disposal of our interests in Bruce Power and Huron Wind. However, the book value of the Bruce Power assets which were disposed as recorded under US GAAP differed from the UK GAAP book value as a result of the accounting adjustments described in (h), (i), (l) and (o) above, and exclusion of a pension payment received after the balance sheet date which had been recorded in the UK GAAP results at March 31, 2003.

(q) Deferred Income Taxation

British Energy has applied the discounting provision of the UK’s standard on deferred tax accounting. This means that the amount provided is less than the full potential deferred tax liability or asset. Additionally, deferred tax assets are recognized only when they are expected to be recoverable within the foreseeable future.

Under US GAAP, deferred tax is provided for on a full liability basis. Under the full liability method, deferred tax assets or liabilities are recognized for all differences between the financial and tax bases of assets and liabilities and for tax loss carry forwards at the statutory rate when they are expected to be utilized, including the enacted change in future rates. Valuation allowances are provided against all deferred tax assets to the extent that realization of the assets is not considered to be more likely than not.

Profit before tax under US GAAP is calculated as follows at March 31:

	2003		2002
	£m		£m
(Loss) before tax under UK GAAP	(4,292	)	(493	)
Effect of US GAAP adjustments	(3,325	)	87

(Loss) before tax under US GAAP	(7,617	)	(406	)

The provision/(benefit) for income taxes under US GAAP is calculated as follows:

	2003		2002
	£m		£m
Deferred tax provision under UK GAAP	—		414
Adjustment under full provision method	(362	)	319
Tax effect of US GAAP adjustments	(1,744	)	(687	)
Valuation allowance	2,106		—

Deferred tax provision under US GAAP	—		46

There is a current income tax charge for the year ended March 31, 2003 of £28m and £33m in the year ended March 31, 2002. There are UK tax losses carried forward of £874m and £632m at March 31, 2003 and 2002 respectively, giving rise to a potential undiscounted deferred tax asset of £262m and £189m. The discounted deferred tax asset under UK GAAP of £150m and nil at March 31, 2003 and 2002, respectively, have not been recognised for US GAAP purposes. There was no utilization of losses in either year. The full amount of the deferred tax provisions in 2003 relate to continuing operations, £18m of the deferred tax provision at March 31, 2002 related to Bruce Power. There are no overseas tax losses brought forward or carried forward.

F-65

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The components of the net deferred tax liability, valued at the enacted UK tax rate of 30% (2002—30%) under US GAAP are as follows at March 31:

	2003		2002
	£m		£m
Current assets:
Tax credits carried forward	—		76
Other	—		(31	)

	—		45

Non-current assets:
Tax losses carried forward	262		189
Pensions	65		—
Book depreciation in excess of tax depreciation	849		—
Nuclear liabilities	1,741		1,580

	2,917		1,769

Non-current liabilities
Tax depreciation in excess of book depreciation	—		(1,020	)
Decommissioning asset	(777	)	(771	)
Pensions	—		(43	)
Capitalized interest	(16	)	(18	)
Other	(18	)	(8	)

	(811	)	(1,860	)

Net deferred tax asset/(liability) under US GAAP	2,106		(46	)

Valuation allowance	(2,106	)	—

	—		(46	)

The reconciliation between the statutory tax rate in the United Kingdom and the effective tax rate is as follows on an UK GAAP basis:

	2003		2002		2001
	%		%		%
Provision/(benefit):
United Kingdom statutory tax rate	30		30		30
Differences relating to:
—impact of discounting	(14	)	(11	)	31
—deferred tax asset not recognized	(3	)	—		—
—decommissioning liabilities	(1	)	(2	)	7
—decommissioning fund	(1	)	—		(11	)
—write down of QUEST	(1	)	—		—
—overseas tax in excess of UK rates	—		(4	)	12
—write down of Eggborough	(1	)	(18	)	—
—adjustment in respect of prior years	—		2		(4	)
—other	—		(2	)	17

Effective income tax rate	9		(5	)	82

Under US GAAP the effective income tax rate is approximately nil and 22% for the years ended March 31, 2003 and March 31, 2002 respectively.

F-66

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

Tax losses arising in the United Kingdom are available for carry forward and utilization in future years. There is no expiry date.

(iii) Additional Disclosures

a) Consolidated Statement of Cash Flows

The consolidated statement of cash flows prepared in accordance with FRS 1 (Revised) presents substantially the same information as that required under US GAAP. US GAAP requires presentation of cash flows from (i) operating; (ii) investing; and (iii) financing activities. Under FRS 1 (Revised), cash flows are presented separately for (i) operating activities; (ii) dividends received from joint ventures and associates; (iii) returns on investment and servicing of finance; (iv) taxation; (v) capital expenditures and financial investment; (vi) acquisitions and disposals; (vii) equity dividends paid; (viii) management of liquid resources; and (ix) financing activities. Cash flows from taxation and returns on investments and servicing of finance would be included as operating activities under US GAAP. Equity dividends paid would be included in financing activities.

Under US GAAP, cash equivalents consist of highly liquid investments that are readily convertible into cash and have maturities of 90 days or less at the time of purchase. Cash and cash equivalents are not offset by book overdrafts repayable within twenty-four hours from the date of the advance, as is the case under UK GAAP, and instead book overdrafts are classified within financing activities. The US GAAP definition of cash and cash equivalents does not include the amounts which the group has deposited in collateral bank accounts for trading purposes as availability of this cash is restricted over the period of the collateralized position. Non-cash equivalent components of net debt under UK GAAP consist of term deposits having maturities of 90 days or greater. Short-term debt represents the book overdraft in the UK accounts at the end of the year.

The table below summarizes the statement of cash flows for the Group as if presented in accordance with US GAAP.

	Year ended March 31
	2003		2002		2001
	£m		£m		£m
Cash inflow from operating activities	336		380		277
Returns on investment and servicing of finance	(84	)	(53	)	(64	)
Ordinary taxation	3		4		(37	)

Net cash provided by operating activities	255		331		176

Acquisitions and disposals	262		(129	)	179
Amounts placed on restricted use term deposit	(209	)	—		—
Capital Expenditure and financial investment	(282	)	(187	)	(127	)

Net cash used in investing activities	(229	)	(316	)	52

Financing	(80	)	13		(9	)
Movement in book overdraft	(54	)	55		(1	)
Equity dividends paid	(31	)	(46	)	(29	)

Net cash provided by financing activities	(165	)	22		(39	)

Net (decrease)/increase in cash and cash equivalents	(139	)	37		189
Cash and cash equivalents at beginning of year	270		233		44

Cash and cash equivalents at end of year	131		270		233

F-67

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

The US GAAP cash flow reconciles to the UK GAAP net funds figures are analyzed as follows:

	Year ended March 31
	2003		2002
	£m		£m
Cash	87		—
Term deposits with maturities less than 90 days at end of year	44		270

Cash and cash equivalents under US GAAP at end of year	131		270
Restricted use term deposits	209		—
Book overdraft at end of year	(7	)	(61	)
Long-term debt at the end of year	(883	)	(1,068	)

Net debt under UK GAAP at the end of the year	(550	)	(859	)

The decrease of term deposits for 2003 under UK GAAP is £37m. This is represented within the US GAAP cash flow as follows:

	2003		2002		Movement
	£m		£m		£m
Term deposits with maturities less than 90 days at end of year	44		270		(226	)
Restricted use term deposits	209		—		209
Book overdraft at end of year	(7	)	(61	)	54

Term deposits under UK GAAP	246		209		37

There are no significant non-cash investing or financing activities during the period.

b) Information about Major Customers

In the year ended March 31, 2003 there were two UK customers who each accounted for more than 10% of Group turnover. The largest customer accounted for 14% of turnover, the other accounted for 11%.

In the year ended March 31, 2002 there were three UK customers who each accounted for more than 10% of Group turnover. The largest customer accounted for 20% of turnover and the others accounted for 15% and 11% respectively. In 2001 there was one customer in Scotland who accounted for more than 10% of Group turnover, sales to that customer accounted for 12% of turnover.

Prior to the introduction of NETA on March 27, 2001 wholesale electricity trading in England and Wales was conducted according to a multilateral agreement between the electricity generators and the wholesale electricity purchasers. The electricity generated by the Group’s six English nuclear power stations was sold into the competitive wholesale market in England and Wales via the Pool, which operated a daily clearing account for supervising and settling all payments and charges in relation to this trading. The customers of a specific generator were identified collectively as the purchasers who have signed the multilateral agreement, therefore, it was not possible to quantify the actual sales to any one specific purchaser in England and Wales.

In Canada all the output from Bruce Power was sold to OPG (Ontario Power Generation Inc) prior to the market opening on May 1, 2002. These sales totaled £375m or 20% of Group turnover in the year ended March 31, 2003 and totaled £348m or 17% of Group turnover in the year ended March 31, 2002. British Energy disposed of its interests in Canada on February 14, 2003.

F-68

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

c) Income and Cost Recognition

The revenues from the sale of electricity are recognized on the basis of the metered output supplied by the Group’s power stations during the accounting period. The income is matched with the cost of fuel burnt and other associated generation costs in each accounting period on an accrual basis. The revenues arising from direct supply sales are based on the metered consumption of each customer during the period and matched with the associated cost of purchasing this volume of electricity.

d) (Loss)/Earnings per Share

The following table sets forth the computation of basic US GAAP (loss)/earnings per share:

	Year ended March 31,
	2003		2002		2001
	£m		£m		£m
Numerator for basic earnings per share—(loss) available to shareholders	(7,732	)	(426	)	(124	)

Denominator for basic and fully diluted loss per share—weighted average shares (millions)	602		598		591

e) Exceptional Items

Under UK GAAP, income and expenses from non-recurring but significant transactions arising otherwise than in the course of the Group’s ordinary activities are recorded as exceptional items. Items classified as exceptional for purposes of UK GAAP generally do not meet the definition of “extraordinary” under US GAAP and, under US GAAP, would be classified as operating income or expenses. However, costs and expenses resulting from debt extinguishments and exchanges of debt instruments with substantially different terms and that are essentially debt extinguishments are classified as extraordinary under US GAAP. See the discussion of SFAS 145 in note (iii) (j) on page F-72.

F-69

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

f) Statement of Comprehensive Income

FAS 130, “Reporting Comprehensive Income”, requires the presentation of comprehensive income (net income plus all other changes in equity shareholders’ funds from non-owner sources) and its components. Comprehensive income and other changes in equity are as follows:

	Total		Retained Losses		Other Compre- hensive Income		Treasury Stock		Additional Paid in Capital	Non- Equity	Common Stock
	£m		£m		£m		£m		£m	£m	£m
Balance at April 1, 2000	(452	)	(1,234	)	102		(189	)	499	93	277

Net income	(124	)	(124	)	—		—		—	—	—
Translation adjustments	6		—		6		—		—	—	—
Unrealized (losses) on securities	(50	)	—		(50	)	—		—	—	—

Total comprehensive income	(168	)	(124	)	(44	)	—		—	—	—

Dividends declared on common stock	(31	)	(31	)	—		—		—	—	—
Treasury stock	3		—		—		3		—	—	—
Compensation plans	5		—		—		5		—	—	—

Balance at March 31, 2001	(643	)	(1,389	)	58		(181	)	499	93	277

Cumulative adjustment for FAS 133 (net of £10m tax charge)	(23	)	—		(23	)	—		—	—	—
Net income	(426	)	(426	)	—		—		—	—	—
Translation adjustments	(8	)	—		(8	)	—		—	—	—
FAS 133 (net of £1m tax credit)	2		—		2		—		—	—	—
Unrealized (losses) on securities	(11	)	—		(11	)	—		—	—	—

Total comprehensive income	(466	)	(426	)	(40	)	—		—	—	—

Dividends declared on common stock	(48	)	(48	)	—		—		—	—	—
Treasury stock	18		—		—		18		—	—	—
Compensation plans	4		—		—		4		—	—	—

Balance at March 31, 2002	(1,135	)	(1,863	)	18		(159	)	499	93	277

Net income	(7,732	)	(7,732	)	—		—		—	—	—
Translation adjustments	(25	)	—		(25	)	—		—	—	—
FAS 133 (net of £9m tax credit)	21		—		21		—		—	—	—
Pensions (net of £107m tax charge)	(249	)	—		(249	)	—		—	—	—

Total comprehensive income	(7,985	)	(7,732	)	(253	)	—		—	—	—

Dividends declared on common stock	(32	)	(32	)	—		—		—	—	—

Balance at March 31, 2003	(9,152	)	(9,627	)	(235	)	(159	)	499	93	277

F-70

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

g) Discontinued Operations

On February 14, 2003 the Group completed the sale of its 82.4% interest in Bruce Power Limited Partnership, its majority-owned Canadian subsidiary, and its 50% share in Huron Wind Limited Partnership (collectively referred to as “Bruce”). Under US GAAP the results and subsequent disposal of Bruce would be classified as a discontinued operation in accordance with the provisions of SFAS 144 “Accounting for the Disposal and Impairment of Long-Lived Assets”. Proceeds from the sale of Bruce totaled C$698m which included a C$20m retention initially held in escrow pending confirmation of the pension deficit which was subsequently received in April 2003. The loss on disposal of Bruce totaled £6m under US GAAP. The difference between the loss on disposal of Bruce under US and UK GAAP was due to the different treatment of certain costs incurred at Bruce as described in paragraphs (h), (i), (l) and (o) of Note 37 (ii), the additional derivatives recorded at Bruce for US GAAP and the recognition of the C$20m retention payment received which were recognized for UK GAAP but not for US GAAP at March 31, 2003. The following table sets forth turnover and net income of Bruce Power for each of the last two years that are reclassified as discontinued operations under US GAAP on an 82.4% holding basis.

	Years ended March 31
	2003	2002
	£m	£m
Turnover	309	287
Net income (before tax)	69	27

Net income from continuing operations and the discontinued operations of Bruce under US GAAP can be reconciled as follows:

	Years ended March 31
	2003		2002
	£m		£m
Loss from continuing operations before income taxes	(7,703	)	(531	)
Income taxes on continuing operations	(82	)	88

Loss from continuing operations	(7,785	)	(443	)
Discontinued operations:
Net income before tax from operations of Bruce	69		27
Income taxes on discontinued operations	(16	)	(10	)

Profit on discontinued operations after tax	53		17

Loss for year under US GAAP	(7,732	)	(426	)

h) Provisions for Unburnt Fuel at Shutdown

		£m
Provision for unburnt fuel at March 31, 2001		254
Charges to profit and loss account		12

Provision for unburnt fuel at March 31, 2002		266
Charges to profit and loss account		6

Provision for unburnt fuel at March 31, 2003		272

F-71

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

i) Presentation of Prior Year Results

Certain reclassifications have been made to prior year presentation of results to conform to the current year presentation.

j) New US Accounting Standards

In July 2001, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No.143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets”. This standard will be effective for the Group for the year ending March 31, 2004. The standard provides the accounting requirements for retirement obligations associated with tangible long-lived assets. The standard requires that the obligation associated with the retirement of the tangible long-lived assets be capitalized into the asset cost at the time of initial recognition.

The liability is then discounted to its fair value at the time of recognition using the guidance provided by the standard. The Group has not yet quantified the impact that adoption of the statement will have on the results of operations and financial position, however, it is expected that adoption will significantly reduce the GAAP divergence for these liabilities.

On April 30, 2002, the FASB issued FASB Statement No.145 (“SFAS 145”), Rescission of FASB Statements No.4, 44 and 64, Amendment of FASB Statement No.13, and Technical Corrections. FAS 145 rescinds both FASB Statement No.4 (FAS 4), “Reporting Gains and Losses from Extinguishment of Debt”, and the amendment to FAS4, FASB Statement No.64 (FAS 64), “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements”. FAS 145 will be effective for the Group for the year ended March 31, 2004; however, early adoption is encouraged. This statement is not expected to have a material impact on the Group financials.

In December 2002 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No.148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an Amendment of SFAS No.123”. SFAS 148 provides two additional transition methods for companies electing to adopt the fair value accounting provisions of SFAS 123, “Accounting for Stock-Based Compensation”, but does not change the fair value measurement principles of SFAS 123. This statement also requires additional disclosures for entities continuing to measure compensation expense pursuant to APB 25, “Accounting for Stock Issued to Employees”. SFAS 148 is not expected to have any impact on our financial position or results of operations as we already measure compensation expense in terms of the fair value accounting provisions of SFAS 123.

In April 2003 the Financial Accounting Standard Board issued Statement of Financial Accounting Standards (“SFAS”) No.149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively, referred to as derivatives) and for hedging activities under SFAS 133. This statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. We are currently assessing the effect that the adoption of SFAS 149 will have on our results of operations or financial position.

In May 2003 the Financial Accounting Standard Board issued Statement of Financial Accounting Standards (“SFAS”) No.150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS 150 establishes standards for how a Company classifies and measures

F-72

NOTES FOR FINANCIAL STATEMENTS—(Continued)

for the year ended March 31, 2003

certain financial instruments with characteristics of both liabilities and equity. The statement requires that a Company classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) if certain criteria are met. Many of those instruments were previously classified as equity. This statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective for the first fiscal period beginning after December 15, 2003. We have not yet determined the effect that the adoption of SFAS 150 will have on our results of operations or financial position.

In November 2002, the Financial Accounting Standards Board issues FASB Interpretation No.45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an Interpretation of FASB Statements No.5, 57 and 107 and Rescission of FASB Interpretation No.34”. FIN 45 clarifies the requirements of a guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees by requiring that the guarantor recognize a liability for the fair value of the obligation it assumes under a guarantee. We have adopted the disclosure provisions of FIN 45 for our financial year ended March 31, 2003. The initial recognition and measurement provisions of FIN 45 are effective on a prospective basis for guarantees that are initiated or modified after December 31, 2002. The adoption of FIN 45 did not have a material effect on our consolidated financial position or cash flows for the financial year ended March 31, 2003.

In January 2003 the Financial Accounting Standards Board issued FASB Interpretation No.46 (“FIN 46”), “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No.51”. FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and, therefore, we do not expect that the adoption of FIN 46 will have a material effect on our consolidated financial position, result of operations or cash flows.

F-73

1.01		Articles of Association of British Energy plc, as amended.

1.02		Memorandum of Association of British Energy plc.*

4.01		Trust Deed, dated March 25, 1999 among British Energy plc, British Energy Generation Limited, British Energy Generation (UK) Limited and The Law Debenture Trust Corporation constituting £134,586,000 6.202% Guaranteed Bonds due 2016 and £163,444,000 6.077% Guaranteed Bonds due 2006 and £109,861,000 5.949% Guaranteed Bonds due 2003 guaranteed by British Energy Generation Limited and British Energy Generation (UK) Limited.*

4.02		Master Purchase Agreement dated January 17, 2003 for the disposal of British Energy’s interest in Bruce Power Limited Partnership was entered into between, amongst others, British Energy and (i) Cameco Corporation, (ii) BPC Generation Infrastructure Trust and (iii) TransCanada Pipelines Limited.

4.03		Standstill Agreement dated February 14, 2003 between British Energy plc and (i) the steering committee of the Eggborough Bank Syndicate, (ii) The Royal Bank of Scotland plc as provider of a letter of credit to the Eggborough Banks, (iii) Teesside Power Limited, (iv) TotalFinaElf Gas and Power Limited, (v) Enron Capital & Trade Europe Finance LLC and (vi) British Nuclear Fuels plc.

4.04		Bondholder Restructuring (Standstill) Agreement dated February 14, 2003 between British Energy plc, British Energy Generation Limited and British Energy Generation (UK) Limited and (i) certain Bondholders owning 58% of the £109,861,000 5.949% Guaranteed Bonds due 2003, (ii) certain Bondholders owning 55% of the £163,444,000 6.077% Guaranteed Bonds due 2006 and (iii) certain Bondholders owning 75% of the £134,586,000 6.202% Guaranteed Bonds due 2016.

4.05		The Deed of Amendment and Guarantee between British Energy Generation Limited, British Nuclear Fuels plc (“BNFL”) and British Energy plc dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the supply of Fuel for Use in Advanced Gas Cooled Reactors between Nuclear Electric Limited and BNFL dated June 3, 1997, as amended.†

4.06		Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003, (as amended on July 22, 2003).†

4.07		Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended on July 22, 2003.)†

4.08		Deed of Amendment and Guarantee between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Nuclear Reactors between Scottish Nuclear and BNFL dated March 30, 1995 as amended.†

4.09		Nuclear Electric – Generation License.*

4.10		Scottish Nuclear – Generation License.*

4.11		Representative Nuclear Site License.*


4.12		Credit Facility Agreement dated September 26, 2002 as amended and restated on March 7, 2003 and further amended by a side letter dated August 15, 2003 between the UK Secretary of State and (i) British Energy, British Energy General (UK) Limited, British Energy Generation Limited and British Energy Power and Energy Trading Limited as borrowers and (ii) British Energy, British Energy General (UK) Limited, British Energy Generation Limited, British Energy Power and Energy Trading Limited, British Energy Investment Limited, District Energy Limited, British Energy International Holdings Limited, British Energy US Holdings Inc., British Energy L.P. and Peel Park Funding Limited as guarantors.

8.01		List of Subsidiaries of British Energy plc.#

12.01		Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act 2002.

As filed on the registrants’ Registration Statement submitted on Form 20-FR on December 6, 1999 (File No. 1-14990).

As filed on the registrants’ Registration Statement submitted on Form 20-F on August 13, 2001 (File No. 1-14990).

†

Confidential treatment requested as to certain portions, which portions are omitted and filed separately with the Commission.