Edgar Filing: BRITISH ENERGY GROUP PLC

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

The Securities Exchange Act of 1934

For the month of September 2005

BRITISH ENERGY GROUP PLC

Systems House, Alba Campus,

Livingston, EH54 7EG

Scotland

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F X Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Indicate by check mark whether by furnishing the information contained in the Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes No X

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82- .

BRITISH ENERGY GROUP PLC

QUARTER ENDED JULY 3, 2005

INDEX


Item
	Introduction	1

	Exchange Rates	1

	Technical Terms	1

	Information Regarding Forward-Looking Statements	1

	Non-GAAP Financial Measures	1

	PART I - FINANCIAL INFORMATION

1.	Financial Statements

	Consolidated Balance Sheets as of July 3, 2005 and March 31, 2005	3

	Consolidated Statements of Operations for the Three-Months Ended July 3, 2005 (Successor) and June 30, 2004 (Predecessor)	4

	Consolidated Statements of Cash Flows for the Three-Months Ended July 3, 2005 (Successor) and June 30, 2004 (Predecessor)	5

	Consolidated Statement of Shareholders’ Equity/(Deficit) and Comprehensive Income/(Loss) as of July 3, 2005 (Successor) and June 30, 2004 (Predecessor)	6

	Notes to Consolidated Financial Statements	7

2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	14

3.	Quantitative and Qualitative Disclosures About Market Risk	22

4.	Controls and Procedures	23

	PART II - OTHER INFORMATION

1.	Legal Proceedings	24

	Signatures	25

	PART III

	Interim Report and Results for the Three Months Ended 3 July 2005 (IFRS)	30

Introduction

In this quarterly report, except as otherwise specified, “British Energy”, the “British Energy Group”, the “Company”, the “Group”, “we”, “us” or “our” refer to British Energy Group plc, or, in the context of events on or prior to January 14, 2005 (“Restructuring Effective Date”), British Energy plc (the former ultimate holding company of the Group now re-registered as a private limited company and re-named British Energy Limited (“BE Ltd”)) and its subsidiaries, and any of their respective predecessors in business, as the context may require. We were incorporated under the United Kingdom Companies Act 1985, as amended (the “Companies Act”) on July 2, 2004. References in the consolidated financial statements to “Predecessor” are to BE Ltd. References to “Successor” are to the Company.

Our registered office is located at Systems House, Alba Campus, Livingston, EH54 7EG, Scotland, and our telephone number is 011 44 1506 408700. Our website address is www.british-energy.com. The information on our website is not a part of this quarterly report.

Exchange Rates

We publish our financial statements in pounds sterling. In this quarterly report, references to “pounds sterling”, “£”, “pence” or “p” are to UK currency. References to “US dollars”, “US$” or “$” are to US currency, references to “Canadian dollars”, or “C$” are to Canadian currency and reference to “Euros” or “€” are to the currency of the European Union.

Technical Terms

This quarterly 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”).

Unless stated otherwise, references to statutes, regulations, government or regulatory bodies or officers of government refer to the appropriate statutes, regulations, and bodies of officers of the United Kingdom.

Information Regarding Forward-Looking Statements

Certain statements in this quarterly report are “forward-looking” statements as defined in Section 21E of the US Securities Exchange Act of 1934. Such forward-looking statements include, among others:

•

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” in our Form 20-F for the year ended March 31, 2005 filed on July 28, 2005. Due to the uncertainties and risks associated with these forward-looking statements, which apply only as of the date hereof, we are claiming the benefit of the safe harbor provision contained in Section 21E of the US Securities Exchange Act of 1934.

Non-GAAP Financial Measures

Realized Price

We calculate our realized price for electricity by dividing revenue (before energy supply costs recharged to customers and miscellaneous income) by total output for the period. Realized price is not derived in accordance with Generally

Accepted Accounting Principles in the United States (“US GAAP”) and should not be exclusively relied upon when evaluating our business. Realized price constitutes a Non-GAAP financial measure because we eliminate energy supply costs, which are recharged to our customers, and miscellaneous income from total revenue. We make these adjustments to revenue because we believe that they allow our management team and our investors to better understand the net price that customers are paying for our electricity.

EBITDA

EBITDA means earnings before interest, taxes, depreciation and amortization. EBITDA is a supplemental measure of our liquidity that is not required by, or presented in accordance with, US GAAP. EBITDA is not a measurement of our liquidity under US GAAP and should not be considered as an alternative to cash flow from operating activities as a measure of our liquidity.

Nevertheless, EBITDA has limitations as an analytical tool, and you should not consider it in isolation from, or as a substitute for analysis of, our financial condition or results of operations, as reported under US GAAP. Some of these limitations are:

•

EBITDA measure does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

•

EBITDA measure does not reflect changes in, or cash requirements for, our working capital needs;

•

EBITDA measure does not reflect the interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

•

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA measure does not reflect any cash requirements for such replacements;

•

EBITDA measure does not reflect certain non-cash items; and

•

other companies in our industry may calculate these measures differently from us, limiting their usefulness as a comparative measure.

Because of these limitations, EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by focusing on our US GAAP results and using EBITDA only as supplemental measures.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BRITISH ENERGY GROUP PLC

CONSOLIDATED BALANCE SHEETS (unaudited)


	July 3, 2005		March 31, 2005
	(In £ millions)
ASSETS
Current Assets
Cash and cash equivalents	255		230
Restricted cash	255		226
Accounts receivable – net	81		105
Unbilled revenues	196		166
Inventory – net	56		64
Prepaid assets	31		21
Other current assets	19		40

Total current assets	893		852

Property, Plant and Equipment – net	3,895		3,923
Nuclear liabilities fund	840		782
Nuclear liabilities receivable	2,303		2,312
Other assets	68		7

Total Assets	7,999		7,876

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	50		50
Accounts payable	128		129
Accrued expenses	260		255
Asset retirement obligations due within one year	185		181
Other current liabilities	433		270

Total current liabilities	1,056		885

Long-Term Debt – net of current portion	626		626

Deferred Credits and Other Liabilities
Asset retirement obligations	4,244		4,215
Pension obligation	451		456
Deferred tax	—		57
Other long-term obligations	490		220

Total deferred credits and other liabilities	5,185		4,948

Commitments and Contingencies
Shareholders’ Equity
Common stock, £0.10 par value, 2,800,000,000 shares authorized 566,039,567 issued and outstanding at July 3, 2005 and 561,315,459 issued and outstanding at March 31, 2005	57		56
Additional paid in capital	1,449		1,435
Warrants	42		51
Retained losses	(413	)	(122	)
Treasury stock, 434,701 shares of common stock, par value £0.10 at July 3 and March 31, 2005, respectively	(3	)	(3	)

Total shareholders’ equity	1,132		1,417

Total Liabilities and Shareholders’ Equity	7,999		7,876

See the accompanying notes to Consolidated Financial Statements.

BRITISH ENERGY GROUP PLC

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions, except per-share amounts)
Operating Revenues
Operating revenues	517		372

Operating Expenses
Fuel costs	(137	)	(155	)
Staff costs	(78	)	(78	)
Operating and maintenance expense	(89	)	(111	)
Depreciation and amortization	(81	)	(29	)
Energy supply costs	(82	)	(70	)
Loss from movements in derivative contracts	(458	)	(91	)
Other operating income	3		—

Total operating expenses	(922	)	(534	)

Operating Loss	(405	)	(162	)

Interest income	5		5
Interest expense	(12	)	(20	)

Loss before Income Tax Benefit	(412	)	(177	)
Income tax benefit	121		18

Net Loss	(291	)	(159	)

Loss per share – basic and diluted (£)	(0.52	)	(0.26	)

See the accompanying notes to Consolidated Financial Statements.

BRITISH ENERGY GROUP PLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
Cash Flows from Operating Activities
Net loss	(291	)	(159	)
Adjustments to reconcile net loss to net cash provided by/(used in) operating activities:
Depreciation and amortization	81		29
Net loss on sale of equity investments and other assets	—		(4	)
Loss on disposal of property, plant and equipment	1		—
Deferred tax	(121	)	(18	)
Pension expense	(5	)	10
Employee severance provision	(1	)	8
Loss from movements in derivative contracts and interest rate swaps	458		87
Loss from movements in other contracts	(3	)	—
Accretion of nuclear liabilities	70		85
Changes in operating assets and liabilities:
Accounts receivable	14		27
Unbilled revenues	(30	)	—
Nuclear liabilities receivable	9		—
Liabilities discharged	(47	)	(37	)
Liabilities incurred	10		—
Inventory	8		(3	)
Other assets	(49	)	—
Fuel asset	(12	)	—
Accounts payable and accrued expenses	4		(77	)
Other liabilities	6		(4	)

Net cash provided by/(used in) operating activities	102		(56	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds on sale of investments	—		4
Amounts placed on restricted use term deposit	(29	)	(24	)
Contribution to nuclear liabilities fund	(11	)	(5	)
Purchase of property, plant and equipment	(42	)	(15	)

Net cash used in investing activities	(82	)	(40	)

CASH FLOWS FROM FINANCING ACTIVITIES
Exercise of warrants	5		—

Net cash provided by financing activities	5		—

Net increase/(decrease) in cash and cash equivalents	25		(96	)
Cash and cash equivalents at beginning of period	230		276

Cash and cash equivalents at end of period	255		180

See the accompanying notes to Consolidated Financial Statements.

BRITISH ENERGY GROUP PLC

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY/(DEFICIT) AND COMPREHENSIVE INCOME/(LOSS) (unaudited)

(In millions)


	‘A’ Shares		Common Stock		Treasury Stock			Additional Paid in Capital	Accumulated Other Comprehensive (Loss)/Income	Warrants		Retained Losses		Total		Comprehensive (Loss)/Income
	Shares No.	Amount £	Shares No.	Amount £	Shares No.	Amount £		£	£	£		£		£		£
Successor
Balance at April 1, 2005	—	—	561	56	0	(3	)	1,435	—	51		(122	)	1,417
Net loss for period	—	—	—	—	—	—		—	—	—		(291	)	(291	)	(291	)
Share-based payments	—	—	—	—	—	—		1	—	—		—		1		—
Exercise of warrants	—	—	5	1	—	—		13	—	(9	)	—		5		—

Other comprehensive income																—

Total comprehensive loss																(291	)

Balance at July 3, 2005	—	—	566	57	0	(3	)	1,449	—	42		(413	)	1,132


	‘A’ Shares		Common Stock		Treasury Stock				Additional Paid in Capital	Accumulated Other Comprehensive (Loss)/Income		Warrants	Retained Losses		Total		Comprehensive (Loss)/Income
	Shares No.	Amount £	Shares No.	Amount £	Shares No.		Amount £		£	£		£	£		£		£
Predecessor
Balance at April 1, 2004	156	93	620	277	(46	)	(159	)	499	(129	)	—	(2,050	)	(1,469	)
Net loss for period	—	—	—	—	—		—		—	—		—	(159	)	(159	)	(159	)
Other comprehensive income, net of tax:
Unrealized gains on securities for year, net of tax	—	—	—	—	—		—		—	8		—	—		8		8

Other comprehensive income																	8

Total comprehensive loss	—	—	—	—	—		—		—	—		—	—		—		(151	)

Balance at June 30, 2004	156	93	620	277	(46	)	(159	)	499	(121	)	—	(2,209	)	(1,620	)

See the accompanying notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. General

(i) Organization

British Energy completed its restructuring on January 14, 2005 (referred to as the “Restructuring”) and on that date was acquired by British Energy Group plc (the “Company”), a new parent company for the Group. The Company is the UK’s largest generator of electricity, producing approximately one fifth of the UK’s electricity and employing over 5,400 staff. The Company owns and operates eight nuclear power stations and one coal fired power station in the UK. The Company’s power stations have a combined capacity of approximately 11,600 MW.

The Company uses a variety of sales channels in the UK, including the wholesale market, direct sales and long term contract sales.

(ii) Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”). Effective April 1, 2005 the Company has operated a 4:4:5 week reporting cycle for quarterly reporting, with reporting periods ending on a Sunday. Accordingly, this set of quarterly results has been prepared to July 3, 2005. The annual results will be prepared to March 31, 2006.

The consolidated financial statements include, after eliminating inter company transactions and balances, the accounts of the Company and all its subsidiaries. The Company consolidates all majority-owned and controlled subsidiaries.

The Company completed its Restructuring on January 14, 2005 (the “Restructuring Effective Date”). Pursuant to the Restructuring a new entity (the Company) was created and was used to acquire British Energy plc, now BE Ltd. The Restructuring was thus accounted for as a business combination under FASB Statement No. 141, Business Combinations (“SFAS 141”). The carrying values of the assets and liabilities were adjusted to their fair values. Since the Restructuring materially changed the carrying values recorded in the Company’s consolidated balance sheet, the terms “Successor” and “Predecessor” are used to distinguish the consolidated financial statements for periods after the Restructuring from the consolidated financial statements prior to the Restructuring. The term “Predecessor” refers to the Company and its subsidiaries for periods prior to and including January 14, 2005. The term “Successor” refers to the Company and its subsidiaries for periods including and subsequent to January 15, 2005. As a result of the Restructuring, the financial statements of the Company subsequent to January 14, 2005 are not comparable to the Company’s financial statements for prior periods.

The accounting policies being applied by the Successor are, in some cases, different to those which were applied by the Predecessor and are set out in the Consolidated Financial Statements in our Form 20-F for the year ended March 31, 2005 filed on July 28, 2005. There have been no material changes in our accounting policies in the quarter.

In the opinion of management, the accompanying unaudited consolidated financial statements of the Company contain all adjustments including usual recording adjustments necessary to present fairly, in all material respects, the Company’s consolidated balance sheets as of July 3, 2005 and March 31, 2005, the consolidated statements of operations for the three-months ended July 3, 2005 and June 30, 2004, the consolidated statements of cash flows for the three-months ended July 3, 2005 and June 30, 2004 and the consolidated statements of shareholders’ equity and comprehensive income for the three-months ended July 3, 2005 and June 30, 2004. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto in the Company’s annual report on Form 20-F for the year ended March 31, 2005 filed on July 28, 2005. The results of operations for the three-months ended July 3, 2005 are not necessarily indicative of the results to be expected for the full year.

(iii) Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include amounts for Restructuring activity, nuclear liabilities and decommissioning, property, plant and equipment and pensions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

2. Earnings/(Loss) Per Common Share

Basic earnings/(loss) per share is based on a weighted average of common shares outstanding. Diluted earnings/(loss) per share reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance awards and convertible debt were exercised or converted into common stock. The numerator for the calculation of both basic and diluted earnings per share is earnings available for common shareholders. The Company does not currently have any outstanding dilutive securities at a price which would have a dilutive effect on earnings/(loss) per share.

The following table sets forth the computation of basic earnings/(loss) per share:


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
Numerator for basic loss per share – loss available to shareholders	(291	)	(159	)

Denominator for basic loss per share – weighted average shares (millions)	564		602

3. Stock-Based Compensation

Prior to the Restructuring, the Company had three stock compensation plans - a Sharesave Scheme, an Employee Share Option Plan and an Executive Share Option Plan (collectively, the “Old Share Plans”). Upon Restructuring, the Successor Company adopted an additional three compensation plans - an Interim Deferred Bonus Plan, a Long Term Deferred Bonus Plan (“LTIP”) and a Share Incentive Plan (“SIP”) (together with the Old Share Plans, the “New Share Plans”).

The Company has elected to account for its stock compensation schemes in accordance with Statement of Financial Accounting Standards No. 123 Accounting for Stock-Based Compensation, (“SFAS 123”) Black-Scholes option-pricing model, under which a fair value is calculated for the share option schemes as at the grant date of the options. The fair value is charged to operations over the period from the date the options were granted to the date at which the options are expected to vest. £1 million has been charged to income in the quarter in respect of share-based payments.

4. Inventory

Inventory consists primarily of coal held for electrical generation and stores. Inventory is held at the lower of cost or market value. Inventory cost is accounted for using the weighted average basis.


	July 3, 2005	March 31, 2005
	(In £ millions)
Coal stock	6	14
Stores	50	50

	56	64

5. Employee Benefit Obligations

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. In addition, eligible senior employees are provided additional retirement benefits. The ESPS is a defined benefit scheme, which is externally funded. Each

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

pension group that participates in the ESPS is financially independent from the other groups. The following table shows the components of the net periodic pension costs for the BEGG and BECG pension schemes.


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
Service cost	14		10
Interest cost	32		29
Expected return on plan assets	(34	)	(32	)
Amortization of prior service costs	—		1
Amortization of transition asset	—		(3	)
Amortization of actuarial loss	—		5

Net periodic pension charge	12		10

6. Severance Costs

Included within accrued expenses of £260 million is a provision of £25 million in respect of severance costs in relation to the Company’s Restructuring. The Company does not expect to incur any more severance costs in connection with the Company’s Restructuring. The accrual comprises the costs to the Company of employees who receive redundancy under the Company’s Restructuring plan. Substantially all remaining severance accruals will be settled through cash payments by the end of the financial year 2006.


	£ millions
Balance as at April 1, 2005	26
Credit	(1	)
Utilization	—

Balance as at July 3, 2005	25


	£ millions
Balance as at April 1, 2004	—
Charges	8
Utilization	—

Balance as at June 30, 2004	8

Severance costs are accounted for in staff costs.

7. Income Taxes

The component of the provision for income taxes is as follows:


	July 3, 2005	March 31, 2005
	(In £ millions)
Deferred tax liability	—	57
Deferred tax asset	64	—

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

The effective tax rate reconciliation is as follows:


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
UK statutory rate	30	%	30	%
Effect of:
Expenditure not allowed for tax purposes	(1	)%	(20	)%

Effective rate	29	%	10	%

The effective rate for the three-months ended June 30, 2004 is lower than the effective rate for the three-months ended July 3, 2005 as a result of an estimate of expenditure not allowed for tax purposes in 2004. This estimate was subsequently revised in later quarters.

8. Segmental Analysis

Through consideration of our product, geographic area and regulatory environment, we have concluded that we have one business, being the generation and sale of electricity in the UK, resulting in one operating segment of Generation and Trading.

From April 1, 2005 revenues and operating profits/(losses) are measured on a segmental basis in accordance with International Financial Reporting Standards (“IFRS”). This is the basis on which management information is prepared and is reconciled to the primary statements prepared in accordance with US GAAP. Prior to April 1, 2005 management information was prepared under Generally Accepted Accounting Principles in the United Kingdom (“UK GAAP”). The chief operating decision maker evaluates segment performance and makes decisions on the basis of IFRS profit and loss information. Net asset information is not reviewed by the chief operating decision maker and so has not been presented in the segmental analysis.

The following table presents segment revenues and net operating profit prepared under IFRS for the period ended July 3, 2005, and segment revenues and net operating profit prepared under UK GAAP for the period ended June 30, 2004, together with operating profit as set out in the Consolidated Statements of Operations. All segment revenues arise from external customers:


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
Segmental analysis
Generation and Trading revenues	512		366
Other revenues
Energy purchases	4		—
Miscellaneous revenue	5		6

Consolidated revenues	521		372
Operating profit/(loss) before interest and taxes (IFRS/UK GAAP)	77		(36	)
Operating profit/(loss) before interest and taxes (US GAAP)	(405	)	(162	)
Included within segmental operating profit/(loss) before interest and taxes (IFRS)
Depreciation	43		18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

9. Commitments and Contingencies

Bruce A Restart

The Company has certain contingent assets as a result of its disposal of its 82.4% interest in Bruce Power LP. In addition to the consideration payable by the consortium under the master purchase agreement, up to a further C$100 million was payable to British Energy contingent upon the restart of two of the Bruce A units under a trust agreement (the “Trust Agreement”) entered into on the same date. Had the first unit restarted by June 15, 2003, C$50 million would have been released to us and an additional C$50 million would have been released to us had the second unit restarted by August 1, 2003. An amount of C$5 million was to be deducted from the C$50 million payable in respect of each unit for its failure to restart by the scheduled restart date or by the first day of each successive calendar month following the scheduled restart date. We received C$20 million on March 22, 2004 and C$10 million on May 25, 2004 in partial consideration under the Trust Agreement. We commenced arbitration proceedings in Ontario against the Ontario Provincial Government (the “Province”) in December 2004 seeking the payment of additional consideration under the Trust Agreement on the basis that Bruce A Units 3 and 4 restarted earlier than the dates claimed by the Province. No additional amounts appear on our balance sheet at July 3, 2005 because of uncertainties regarding their realization. The amounts recoverable in respect of the restarted units will be substantially lower than the maximum C$100 million but the amounts and timing of the payments have still to be confirmed.

Claims by Bruce Power Investors

On February 12, 2004 British Energy Limited received a notice of warranty claims from the consortium which purchased the Group’s 82.4% interest in Bruce Power LP alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce Power Station.

The principal tax claim relates to the treatment of expenditure at the Bruce Power Station during the period of our part ownership and is currently being considered by the Canadian tax authorities. The treatment proposed by us could result in a rebate of a material amount of tax to the Group that has not been recognized in the financial statements. The consortium claims that allowance of the expenditure for that period would cause it to lose future deductions. We have rejected the tax claim and expect to defend it if it is pursued further. We are confident that the amount of the claim should not, in any event, materially exceed the amount of the rebate, and that the tax claim should have no material cash flow impact on the Group.

The claim relating to the condition of the plant is based upon alleged erosion of certain parts of the steam generators, including the support plates, through which boiler tubes pass, which it is alleged resulted in an extended outage of one unit at the plant to carry out repair works and loss of revenues and costs of approximately C$64.5 million. The consortium also claims that the alleged erosion may reduce the operating life of the unit and/or result in further repairs involving further losses. We have rejected the claim and expect to defend it if it is pursued further.

Under the agreement with the consortium C$20 million is retained in trust to meet any representation and warranty claims, and this may be retained pending agreement or determination of the claims.

Other Claims

The Company has given certain indemnities and guarantees in respect of the disposal of its investment in AmerGen.

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 on a going concern basis.

The Company 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.

10. Derivative Instruments

The Company 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. The Company generally recognizes all derivatives which do not qualify for the Normal Purchase Normal Sale exemption on the balance sheet at their mark to market value with the change in mark to market value recognized in the Consolidated Statements of Operations.

At the Restructuring Effective Date, all derivative contracts outstanding at that time, including those which qualify for the Normal Purchase Normal Sale exemption, were recorded on the balance sheet at fair value.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

11. Other Comprehensive Income

Prior to Restructuring, realized gains and losses on securities held by our independently administered decommissioning fund are included in profit but unrealized gains and losses are excluded from profit until realized and were reported as a separate component of equity shareholders’ funds, being other comprehensive income. Subsequent to Restructuring, unrealized gains and losses are included in income.

12. Subsequent Events

On September 15, 2005, the Group announced the completion of the necessary technical and economic evaluation regarding the potential life extension at Dungeness B. This has resulted in the accounting life of Dungeness B being extended by 10 years to 2018, five years beyond the extension assumed as part of the restructuring related fair value exercise.

On September 12, 2005, the Company announced it had elected to maintain the shutdown of two reactors at Hartlepool and to shutdown two reactors at Heysham 1 as a result of inspections to boiler closure units. The return to service of all four units is dependent on the successful outcome of further inspections and a programme of work at each unit. As a consequence, the return to service of the four units is expected during mid to end October 2005. As a result, the net additional unplanned losses are currently expected to increase by 0.5 TWh to around 1.5 TWh. Whilst more challenging, the Company reconfirms it expects the average annual nuclear output over the next two years to be 63 TWh.

On September 21, 2005, the Department for Environment Food and Rural Affairs issued an update regarding the implementation of the Large Combustion Plant Directive (“LCPD”) pending a formal decision by the Government expected before the end of this year. The update indicated that the Government will apply emission limit values to control emissions of sulphur dioxide, nitrogen oxides and particulates from power stations in the UK from January 2008. The update repeated the European Commission’s view that existing plants whose waste gases are discharged through a common stack should be considered as a single plant for the purposes of the LCPD, however it gave no further clarification of whether multiple generating units each with their own separate flue (as at Eggborough) can be treated as separate plants for the purposes of the LCPD pending further discussions with the European Commission.

If the final decision is to consider the four units at Eggborough as a single plant for LCPD purposes then there could be a requirement to materially restrict the operations of the two non-FGD units from 2008 in order to comply with the proposed emission limit values.

13. New US GAAP Pronouncements

In December 2004 the Financial Accounting Standards Board (“FASB”) issued Financial Accounting Standard No. 151, Inventory Costs - an amendment of ARB No. 43, Chapter 4 (revised) (“SFAS 151”). SFAS 151 amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). SFAS 151 requires that those items be recognized as current-period charges. In addition, SFAS 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for British Energy for its year ending March 31, 2007. British Energy is in the process of determining whether SFAS 151 will have a material impact on its financial position or results of operations.

In December 2004 the FASB issued Financial Accounting Standard No. 123R, Share-Based Payment (“SFAS 123R”). SFAS 123R requires that companies expense the value of employee stock options and other awards. SFAS 123R allows companies to choose an option pricing model that appropriately reflects their specific circumstances and the economics of their transactions, and allows companies to select from three transition methods for adoption of the provisions of the standard. It is expected that SFAS 123R will impact British Energy post-Restructuring, although the financial impact has not yet been quantified.

In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 which provides public companies additional guidance in applying the provisions of SFAS 123R. The SAB expresses the views of the SEC staff regarding the interaction between SFAS 123R and certain existing SEC rules and regulations and provide the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. The SAB would be applied upon the adoption of SFAS 123R.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued)

In April 2005, the SEC amended the date for compliance with SFAS 123R so that each entity that is not a small business issuer will be required to prepare financial statements in accordance with Statement 123R beginning with the first interim or annual reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005. The Company is currently evaluating the requirements of SFAS 123R.

In December 2004 the FASB issued Financial Accounting Standard No. 153, Exchanges of Nonmonetary Assets (“SFAS 153”). SFAS 153 amends APB Opinion No. 29, Accounting for Nonmonetary Transactions, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for British Energy for nonmonetary exchanges occurring after July 1, 2005. It is not expected that SFAS 153 will have a material impact on British Energy’s financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections (“SFAS 154”). This Statement replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, but early adoption is permitted.

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

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements for the three-month period ended July 3, 2005 and the notes thereto which are included in this report. There have been no changes to our critical accounting policies or assumptions since March 31, 2005.

We have also prepared quarterly financial statements under IFRS for the three-month period ended July 3, 2005.

OVERVIEW

This report contains our results prepared under US GAAP for the first quarter ended July 3, 2005, with comparatives for the quarter ended June 30, 2004.

This is the first time after completion of the Restructuring of the British Energy Group on January 14, 2005 that British Energy has published results for its first quarter. Accordingly, references to the period ended July 3, 2005 relate to the Successor company and references to the period ended June 30, 2004 relate to the Predecessor company.

In the following discussion the “three-month period” or the “quarter” refers to the three-months ended July 3, 2005 unless otherwise stated. The “prior three-month period” or “prior quarter” refers to the respective period ended June 30, 2004, unless otherwise stated. In this discussion references to “British Energy” or the “Company” are to British Energy Group plc. References to the “Group” are to the Company and its subsidiaries.

Electricity demand in the UK is seasonal, in that demand and prices are generally lower in summer than in winter. As a result, we (and other generators) schedule a significant proportion of planned outages for the summer months. This seasonality in both prices and output has a direct effect on financial performance and cash flows.

Key points on results

•

We have recorded an operating loss of £405 million and a loss before tax of £412 million in the three-month period compared to an operating loss of £162 million and a loss before tax of £177 million in the prior quarter.

•

Total output for the quarter was 17.4 TWh. Nuclear output in the quarter (94 days) was up by 5% to 15.7 TWh, compared with 15.0 TWh in the prior quarter (91 days). Coal output was 1.7 TWh in the quarter compared to 1.4 TWh in the prior quarter.

•

Realized price (which is calculated by dividing revenue, before energy supply costs recharged to customers and miscellaneous income, by total output during the period) was £24.7/MWh for the three-month period, up from £18.0 MWh in the same quarter in the prior year.

•

As at July 3, 2005 we had cash amounting to £510 million, of which £250 million was deposited as collateral in support of trading and operating activities.

•

Cash provided by operating activities in the quarter was £102 million compared to cash used in operating activities in the prior quarter of £56 million.

Performance Improvements

Work continues to implement our Performance Improvement Programme (“PiP”), with the aim to improve the reliability of the nuclear power stations and reduce the level of unplanned nuclear losses. Last year the focus was on improvements relating to people, plant and processes and is now on implementation with an emphasis on integrating PiP across the business.

Considerable progress has been made during the quarter in putting the processes and support in place. Managers are carrying out task observations across all sites to allow the identification and removal of obstacles from the daily activities of staff that affect safety and reliability.

Non-outage defect backlog has reduced by 11% in the quarter as a result of focusing on equipment reliability, work management and improved operational focus. Both nuclear reportable events and unplanned trips show an improving trend in the quarter.

Independent of internal improvement monitoring arrangements, a number of favorable World Association of Nuclear Operations (“WANO”) assessments have been received recently, with positive reports received from recent reviews at Sizewell B, Hinkley Point and Heysham 1 and 2.

Investment Expenditure

During the quarter, investment expenditure across the whole Company on plant projects, major repairs and strategic spares, including costs associated with PiP, totaled £41 million, of which £18 million has been capitalized. In addition, £24 million of overhaul costs were capitalized in the quarter. The main investment in plant in the period included additional safety work at Hartlepool and Heysham 1, turbine work at Heysham 1, low pressure rotor refurbishment at Heysham 2 and Hunterston and generator transformer refurbishment at Hartlepool. Based on its current expectations of future electricity prices and output, and therefore financial resources, the Company reconfirms that investment in plant projects, major repairs and strategic spares including costs associated with PiP across the whole Group is expected to be in the range of £230 million to £250 million for the year ending March 31, 2006.

Quinquennial review

The quinquennial review of our nuclear liabilities is underway and the results of this review will be finalized towards the end of 2005. The review may result in a significant change in value of the nuclear liabilities due to changes in strategy and cost estimates and, having determined that this is not an adjusting event for the first quarter, we are in the process of determining how any change in the nuclear liabilities will be dealt with in the context of our earlier fair value and acquisition accounting applied at the Restructuring Effective Date.

Factors affecting results of operations

We have a total of eight nuclear power stations and one coal-fired power station in the United Kingdom. The results of operations are principally affected by changes in plant output (nuclear and fossil fuel) and electricity prices. Each of these factors is discussed below.

Plant output

Nuclear output was 15.7 TWh (a 73% load factor) for the quarter (94 days). The nuclear output for the quarter ended June 30, 2004 (91 days) was 15.0 TWh (a 72% load factor). During the period a statutory outage was completed at Sizewell B, and one started at each of Heysham 1 and Hunterston B. Since successfully completing its statutory outage, following an overrun, Sizewell B has operated continuously at full power. There were planned outages amounting to 3.8 TWh of lost output. Unplanned losses for the quarter were 1.8 TWh leading to reduced UCLF at most stations, offset by the Sizewell B statutory outage overrun.

Output from the coal-fired power station at Eggborough was 1.7 TWh during the quarter. For the quarter ended June 30, 2004, the output was 1.4 TWh. As Eggborough is operated primarily as a flexible mid-merit plant, its output level is influenced by market prices, the Company’s contracted trading position and the extent to which it is operated as cover for unplanned outages at the nuclear power stations.

Trading position

Forward market prices for electricity for winter 2005/06 delivery have increased during the quarter, however they continue to show considerable volatility. As at September 25, 2005, the Company had fixed price contracts in place for approximately 85% of planned output for the financial year 2005/06 at an average contract price of approximately £31.8/MWh. This price includes the impact of capped price arrangements of approximately 5 TWh at around £30/MWh and the benefit of higher prices achieved as a result of Eggborough taking advantage of the differential between peak and baseload prices. This price excludes Balancing Services Use of System and other electricity market participation charges of around £0.7/MWh, market costs incurred through output variation and unreliability expected to be around £1.0/MWh. The level of output at fixed prices has been impacted by unplanned losses at Heysham 1 and Hartlepool and the requirement to manage collateral. The Company intends to progressively close out its exposure to market prices for the financial year 2005/06 subject to limits on trading collateral which are easing and has made satisfactory progress in fixing prices for the financial year 2006/07.

Realized price (which is calculated by dividing revenue, before energy supply costs recharged to customers and miscellaneous income, by total output during the period) was £24.7/MWh for the quarter.

Unrestricted Subsidiaries

At March 31, 2005 and July 3, 2005 the only Unrestricted Subsidiaries, as defined by the terms of the Bonds, were Eggborough Power Holdings Limited (“EPHL”) and Eggborough Power Limited (“EPL”). By virtue of the terms of the Capacity and Tolling Agreement (“CTA”) between EPL and British Energy Power and Energy Trading Limited, a Restricted Subsidiary of the Group, the consolidated financial condition of the Group is considered to be not materially different from the consolidated financial condition of the Group excluding the Unrestricted Subsidiaries. There would be certain reclassifications on the balance sheet to show EPHL as an investment in subsidiary, equivalent to the carrying value of the EPHL and EPL assets and liabilities excluding inter company balances contained in the consolidated Group results. The relevant inter company balances would be separately reflected. The US GAAP value of property, plant and equipment of EPL and EPHL within the consolidated results at March 31, 2005 and July 3, 2005 was £213 million and £212 million respectively. The net loss would be higher annually by £10,000, being the expected profit to be made by EPL under the CTA. The financial statements of the Group’s subsidiaries for the year ended March 31, 2005 have not been finalized or their audits completed so the EPL and EPHL inter company balances with the rest of the Group are not yet available.

RESULTS OF OPERATIONS

Three-months ended July 3, 2005 compared to the results for the three-months ended June 30, 2004

Effective April 1, 2005 the Company has operated a 4:4:5 week reporting cycle, with quarterly reporting periods ending on Sundays. Accordingly, this set of quarterly results has been prepared to July 3, 2005.

On January 14, 2005, the Company completed its Restructuring, accounted for as a business combination under US GAAP. Accordingly, the acquired assets and assumed liabilities were recorded at fair value. In addition, the terms of the Restructuring required certain items to be accounted for which had not been done previously. As a result, the Company’s results of operations subsequent to the Restructuring Effective Date are not comparable to results reported in prior periods because of the differences in the bases of accounting and the capital structure for the Predecessor and the Successor.

Revenue

Revenue increased £145 million or 39% to £517 million for the three-months ended July 3, 2005 compared to £372 million for the three-months ended June 30, 2004. Revenue is analyzed as follows:


	Successor	Predecessor	Variance
	Three-months ended July 3, 2005	Three-months ended June 30, 2004	Variance
	(In £ millions)		£		%
Wholesale generation sales	226	153	73		48
Direct supply sales net of energy supply costs	204	143	61		43

	430	296	134		45
Energy supply costs recharged to customers	82	70	12		17
Miscellaneous income	5	6	(1	)	(17	)

Revenue	517	372	145		39

Per cent split of sales:	%	%
Wholesale	53	52
Direct supply	47	48

The increase in revenue in the three-month period of £145 million reflects an increase of £134 million in sales, an increase of £12 million in energy supply costs being recharged to customers and a decrease of £1 million in miscellaneous income. £116 million of the increase in sales is a result of a rise in price, with realized price increasing from £18.0/MWh in the prior quarter to £24.7/MWh in the current quarter. £18 million of the increase in sales is a results of a rise in output in the quarter compared to the prior quarter, with total output for the quarter at 17.4 TWh and total output for the prior quarter at 16.4 TWh.

Wholesale generation sales

The level of wholesale generation sales for the three-months ended July 3, 2005 reflects the increase in output and higher prices compounded by an increase in proportion of total sales being made to wholesale customers, compared with the prior period.

Direct supply sales

The direct supply business, with a core market of industrial and commercial customers, continues to be an integral part of our business. Direct supply sales increased by 43% over the corresponding period in the prior year. This increase is primarily the result of the rise in electricity prices in the quarter.

Operating expenses

Total operating expenses were £922 million for the three-months ended July 3, 2005, up £388 million or 73% from £534 million in the corresponding three-month period in the prior year. These are further analyzed as follows:


	Successor		Predecessor	Variance
	Three-months ended July 3, 2005		Three-months ended June 30, 2004	Variance
	(In £ millions)			£		%
Fuel costs	137		155	(18	)	(12	)
Staff costs	78		78	—		—
Operating and maintenance expense	89		111	(22	)	(20	)
Depreciation and amortization	81		29	52		179
Energy supply costs	82		70	12		17
Loss from movements in derivative contracts	458		91	367		403
Other operating income	(3	)	—	(3	)	(100	)

Total operating expenses	922		534	388		73

Fuel cost

Total fuel costs amounted to £137 million for the three-months ended July 3, 2005 compared to £155 million for the three-months ended June 30, 2004, which is a decrease of £18 million or 12%. Nuclear fuel costs were £84 million and coal costs were £53 million during the current quarter compared to £132 million and £23 million respectively in the corresponding quarter in the prior year. Accretion of nuclear liabilities increased during the period, with the charge in the three-month period amounting to £70 million, down from £85 million in the prior quarter. The movement in accretion is due to the reduction in the credit-adjusted risk-free rate from 12.2% in the prior quarter to 3% in the current quarter as a result of completion of the Restructuring and revised commercial arrangements.

Staff costs

Staff costs were £78 million for both the three-months ended July 3, 2005 and the three-months ended June 30, 2004. £1 million of severance costs were credited to income in the quarter, reducing the severance provision to £25 million. In the prior quarter, a charge of £8 million was made against income in relation to the severance provision. Net periodic pension costs were £12 million in the current quarter compared to £10 million in the prior quarter. £1 million was charged to staff costs in the quarter in relation to share-based payments made from the LTIP and the SIP.

Operating and maintenance expense

Operating and maintenance expenses comprise the operating expenses of our power stations and support functions. Operating and maintenance expenses during the three-months ended July 3, 2005 were £89 million, including £3 million of expenditure on research and development, compared to £111 million in the prior quarter, which included £4 million of expenditure on research and development. £5 million of costs were incurred in the prior quarter in relation to the Restructuring. Following the Restructuring, the accounting policy for the outage costs is to capitalize them on the balance sheet, and this has resulted in a reduction of £18 million to operating expenses in the quarter. Prior to the Restructuring, outage costs were expensed through operating and maintenance expense.

Depreciation and amortization

Depreciation and amortization charges were £81 million for the three-months ended July 3, 2005, a £52 million or 179% increase over the £29 million charged for the three-months ended June 30, 2004. The increase is due to the higher value of depreciable assets which arose as a result of the fair value exercise, in purchase accounting, carried out as part of the Restructuring.

Energy supply costs

Energy supply costs mainly comprise the costs incurred for the use of the distribution and transmission systems and are fully recovered through revenue. Energy supply costs also include costs related to meeting the cost of compliance with the United Kingdom’s Renewables Obligation which is also fully recovered through revenue. We are required to

comply with the Renewables Obligation as part of the regulations governing climate change. Total energy supply costs were £82 million and £70 million for the three-months ended July 3, 2005 and June 30, 2004 respectively. The increase in the period reflects the growth in the direct supply business.

Loss from movements in derivative contracts

Due to our trading strategy of selling forward a high proportion of output, we have a number of contracts for delivery in the future with prices that are different to current market prices, which require to be marked to market at each reporting date. A loss of £458 million has been recorded in the three-months ended July 3, 2005, largely as a result of increases in electricity prices. In the prior three-month period, a loss of £91 million was recognized. The significant increase in the loss reflects the continued increase in market prices of energy and coal for which we carry unfavorable positions.

Other operating income

At the Restructuring Effective Date, as part of purchase accounting, we fair valued all our trading contracts which are not marked to market under SFAS 133. The £3 million other operating income relates to the unwind of the fair value of those contracts in the period ended July 3, 2005.

Financing charges

Interest expense was £12 million for the quarter ended July 3, 2005 and £20 million for the quarter ended June 30, 2004, a decrease of £8 million or 40%. The decrease is due to the lower level of debt in place, following the cancellation of the Predecessor debt on Restructuring and the issuing of new debt following the Restructuring. Interest received was £5 million in both the quarter and prior quarter.

Taxation

There was a deferred tax benefit of £121 million in the quarter, resulting in a deferred tax asset of £64 million at the quarter end, which is included in the other assets line item. In the prior quarter there was a deferred tax benefit of £18 million. The movement of £103 million is largely as a result of the significant decrease in the mark to market value of the trading contracts in the quarter compared to the prior quarter.

Net loss

As a result of the factors discussed above, there was a loss after tax for the three months of £291 million compared with a loss after tax for the three-months ended June 30, 2004 of £159 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows

A reconciliation of operating income/(loss) to EBITDA and of EBITDA to cash flow from operating activities is illustrated in the table below:


	Successor		Predecessor
	Three-months ended July 3, 2005		Three-months ended June 30, 2004
	(In £ millions)
Operating income/(loss)	(405	)	(162	)
Depreciation and amortization	81		29

EBITDA	(324	)	(133	)
Accretion of nuclear liabilities	70		85
Pension expense	(5	)	10
Employee severance provision	(1	)	8
(Profit)/loss from movements in derivative contracts and other contracts	455		87
Gains/(losses) on sale of assets	1		(4	)
Working capital movements	(94	)	(109	)

Cash flow from operating activities	102		(56	)

Cash flow from investing activities	(82	)	(40	)

Cash flow from financing activities	5		—

EBITDA for the quarter is a loss of £324 million compared with a loss of £133 million in the prior quarter, a decrease of £191 million. This reduction is primarily a result of the increased loss of £367 million on derivative contracts in the quarter, offset by an increase in revenue of £145 million, mainly due to the rise in electricity prices in the quarter, and a reduction in operating and maintenance expense, mainly as a result of capitalizing £18 million of outage costs in the quarter which were expensed in the prior quarter.

The operating cash flows for the three-months ended July 3, 2005 and June 30, 2004 were an inflow of £102 million and an outflow of £56 million respectively, an overall increase of £158 million. The movement in cash flows from operating activities is largely explained by the increase in the loss incurred on the derivative contracts in the quarter.

The investing cash outflows for the three-months ended July 3, 2005 and June 30, 2004 increased by £42 million, from £40 million in the prior quarter to £82 million in the current quarter. £24 million of the increase is due to the classification of expenditure as strategic spares in the quarter. Strategic spares were classified as operating expenditure in the prior quarter when strategic spares were categorized as inventory, but following a change in accounting policy on Restructuring, strategic spares are now categorized as property, plant and equipment, causing expenditure in the period to be classified as investing activities. A further £6 million of the increase is due to additional contributions made to the Nuclear Liabilities Fund (“NLF”) as a result of the terms of the Restructuring, increasing contributions in the quarter to £11 million compared to £5 million in the prior quarter.

The financing cash inflows for the quarter were £5 million, resulting from the exercise of 472,000 warrants in the quarter. There were no cash flows resulting from financing activities in the prior quarter.

Capital resource

On January 14, 2005 we issued £550 million of bonds due from 2005 to 2022 and a Project Finance Loan of £150 million in connection with the Restructuring. As at both July 3, 2005 and March 31, 2005 the total outstanding obligations were £676 million representing bonds of £531 million and the Project Finance Loan of £145 million.

We continue to maintain our receivables facility agreement with Barclays Bank plc. As at July 3, 2005 the facility is undrawn.

Future liquidity and commitments

At July 3, 2005 we had cash and cash equivalents and restricted cash, including amounts posted as collateral, amounting to £510 million, of which £250 million was deposited as collateral in support of trading activities. Together with the collateral of £250 million and cash and cash equivalents of £255 million is £5 million of restricted cash.

Our main source of liquidity is our operating businesses. Cash generation by the operating businesses is dependent upon the reliability of our power stations in producing electricity, the realized selling price for electricity, operational risk and investment expenditure and maintenance requirements.

The lack of an investment grade credit rating has meant that we continue to provide significant levels of collateral to counterparties in order to cover their trading exposures and maintain trading arrangements, thereby substantially reducing the levels of cash resources available to us.

Our strategy for securing part of our income through fixed price contracts means that in a volatile and rising electricity market the collateral requirements are also volatile and rising. Our ability to secure longer term certainty on our income is limited by the amount of collateral and headroom available to cover collateral volatility. We mitigate a certain amount of this risk by selling electricity through a number of routes to market including through our direct supply business (to large industrial and commercial customers) which does not require collateral and also through the use of financial products which provide electricity price protection but require less collateral.

Our future liquidity may also be impacted by the additional employer pension contributions set out in note 10, “Post Retirement Benefit Obligations” of item 18 “Financial Statements” to our March 31, 2005 20-F filed on July 28, 2005.

The terms of the Nuclear Liabilities Agreement entered into as part of the Restructuring also require that once the cash reserve (being £490 million plus the amount by which the cash employed as collateral exceeds £200 million) is funded, the Company must make cash sweep payments to the NLF. The NLF Cash Sweep payment was originally defined as 65% of the movement in cash, cash equivalents and other liquid assets during the year after adjusting for, among other things, certain payments made to the NLF or dividends paid in the year. The requirement to make the NLF Cash Sweep payment greatly reduces the amount of cash available for distribution to shareholders.

The NLF Cash Sweep percentage was 64.80% at July 3, 2005, down from 64.99% at March 31, 2005 as a result of the exercise of a number of the Company’s warrants. No accrual for any potential Cash Sweep Payment has been made in the quarter.

We believe that our current available working capital is sufficient to meet our present requirements.

Contingent liabilities

On February 12, 2004, British Energy Limited and certain of its subsidiaries received a notice of warranty claims from the consortium which purchased the Group’s 82.4% interest in Bruce Power LP alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce power station.

The principal tax claim relates to the treatment of expenditure at the Bruce Power plant during the period of our part ownership and is currently being considered by the Canadian tax authorities. The treatment proposed by British Energy could result in a rebate of a material amount of tax to the Company that has never been recognized in the financial statements. The consortium claims that allowance of the expenditure for that period would cause it to lose future deductions. British Energy has rejected the tax claim and expects to defend it if it is pursued further. We are confident that the amount of the tax claim should not, in any event, materially exceed the amount of the rebate, and that the tax claim should have no material cash flow impact on the Company.

The claim relating to the condition of the plant is based upon alleged erosion of certain parts of the steam generators, including the support plates, through which boiler tubes pass, which it is alleged resulted in an extended outage of one unit at the plant to carry out repair works and loss of revenues and costs of approximately C$64.5 million. The consortium also claims that the alleged erosion may reduce the operating life of the unit and/or result in further repairs involving further losses. British Energy has rejected the claim and expects to defend it if it is pursued further. No provision has been made in the financial statements at July 3, 2005 for either claim.

Under the agreement with the consortium C$20 million is retained in trust to meet any representation and warranty claims, and this may be retained pending agreement or determination of the claims.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk, see Item 11, “Quantitative and Qualitative Disclosures About Market Risk,” of our annual report on Form 20-F for the year ended March 31, 2005 filed on July 28, 2005. Our exposures to market risk have not changed materially since March 31, 2005.

Item 4. Controls and Procedures

Our management, including the Chief Executive Officer and Finance Director, have evaluated the effectiveness of our disclosure of controls and procedures (as defined in Exchange Act Rule 13(a) – 15(f)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this report. Our disclosure of controls and procedures are effective in ensuring that information required to be disclosed in our reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and Finance Director, as appropriate to allow timely decisions regarding required disclosure.

No change in our internal control and procedures (as defined in Exchange Act Rule 13(a) – 15(f)) over financial reporting occurred during our most recent fiscal quarter that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For additional information concerning litigation and other contingencies, see note 9 to the Consolidated Financial Statements in this Report and Item 4 “Information on the Company”, note 32 “Contingent Assets” and note 33 “Contingent Liabilities” of Item 18 “Financial Statements” to our March 31, 2005 20-F filed on July 28, 2005.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BRITISH ENERGY GROUP PLC

Date: September 28, 2005	By:	/s/ William Coley
		William Coley
		Chief Executive

Date: September 28, 2005	By:	/s/ Stephen Billingham
		Stephen Billingham
		Finance Director

CERTIFICATION

I, William Coley, certify that:

I have reviewed this quarterly report for the period ended July 3, 2005 of British Energy Group plc (“Registrant”);

Based on my knowledge, this 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 report;

Based on my knowledge, the financial statements, and other financial information included in this 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 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-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting(s), to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.


Date: September 28, 2005		/s/ William Coley
	Name:	William Coley
	Title:	Chief Executive

CERTIFICATION

I, Stephen Billingham, certify that:

I have reviewed this quarterly report for the period ended July 3, 2005 of British Energy Group plc (“Registrant”);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.


Date: September 28, 2005		/s/ Stephen Billingham
	Name:	Stephen Billingham
	Title:	Finance Director

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, William Coley, Chief Executive of British Energy Group plc (“Registrant”), certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The quarterly report for the quarter ended July 3, 2005 (the “Report”) of the Registrant fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of the Registrant.


Date: September 28, 2005		/s/ William Coley
		William Coley
		Chief Executive

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Stephen Billingham, Finance Director of British Energy Group plc (the “Registrant”), certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The quarterly report for the quarter ended July 3, 2005 (the “Report”) of the Registrant fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of the Registrant.


Date: September 28, 2005		/s/ Stephen Billingham
		Stephen Billingham
		Finance Director

PART III

British Energy Group plc

Interim Report and Results for the Three Months Ended

3 July 2005

(IFRS)

BRITISH ENERGY GROUP PLC

RESULTS FOR THE FIRST QUARTER ENDED 3 JULY 2005 OF THE FINANCIAL YEAR

ENDING 31 MARCH 2006 (Q1 05/06)

In the following discussion the ‘three-month period’ or the ‘quarter’ refers to the quarter ended 3 July 2005 unless otherwise stated. In this discussion references to ‘British Energy’, the ‘Company’ or the ‘Group’ are to British Energy Group plc.

This set of quarterly results has been prepared to 3 July 2005 and reflects the four:four:five week quarterly reporting cycle.

This is the first time since completion of the restructuring on 14 January 2005 that British Energy has published results for its first quarter. Therefore this report does not contain any comparative quarterly financial information but, where appropriate, does contain comparative quarterly non-financial information.

Highlights


	Quarter ended 3 July 2005 before re-measurement*	Quarter ended 3 July 2005 after re-measurement
Revenue (£m)	521	487
Operating costs (£m)	444	442
Operating profit (£m)	77	45
Profit before tax (£m)	64	32
EBITDA – continuing activities (£m)	121	89

Cash and liquid funds (£m)	510	510
Net Debt (£m)	166	166

Realised price (£/MWh)	24.7	23.0
Operating unit cost (£/MWh)	20.6	20.7
Operating margin (£/MWh)	4.1	2.3
Earnings per share (p)	6.7	2.8


	Quarter ended 3 July 2005	Quarter ended 30 June 2004
Output (TWh)	17.4	16.4
Nuclear (TWh)	15.7	15.0
Coal (TWh)	1.7	1.4

Items marked * represent the results of operations adjusted to reflect the result before exceptional charges and other movements arising from re-measurement. During the quarter there were no exceptional charges. For the first quarter the re-measurement adjustments relate solely to the re-measurement impact of IAS 39 on the results for the quarter. British Energy believes that the results before re-measurement provide a better indication of the underlying business performance.

•

EBITDA for the quarter was £121m* before re-measurement impact, £89m after re-measurement impact.

•

Results reflect a return to profitability and the benefit of higher electricity prices with an operating margin of £4.1/MWh at contracted summer prices.

•

Realised price was £24.7/MWh for the quarter up 37% compared to the first quarter 2004/05.

•

Operating cash inflow from operations was £59m for the quarter. Net debt decreased in the quarter by £54m to £166m.

•

Total output for the quarter was 17.4 TWh in line with plan (Nuclear 15.7 TWh, Coal 1.7 TWh) compared to 16.4 TWh (Nuclear 15.0 TWh, Coal 1.4 TWh) in the first quarter of 2004/05.

•

Second quarter output as of 25 September 2005 was 14.8 TWh (Nuclear 14.0 TWh, Coal 0.8 TWh).

•

As at 25 September 2005, approximately 85% of planned output for the year ending 31 March 2006 fixed at an average contracted price of £31.8/MWh. This includes the impact of capped price arrangements and higher prices for Eggborough taking advantage of the differential between peak and baseload prices.

•

Net additional losses from Heysham 1 and Hartlepool expected to increase by 0.5 TWh to around 1.5 TWh.

•

The Nuclear Liabilities Fund (NLF) Cash Sweep percentage was 64.80% at 3 July 2005, down from 64.99% at 31 March 2005 as a result of the exercise of a number of the Company’s warrants.

•

No accrual for any potential NLF Cash Sweep payment has been made in these quarterly financial statements in line with the Group’s accounting policy.

•

In accordance with the dividend policy set out within the accounts for the period ended 31 March 2005, no dividend has been declared for the quarter.

Bill Coley, Chief Executive Officer said:

“The results reflect underlying improvement in our performance as a result of the changes we are making. We remain tightly focused on improving the operational reliability of our plant - and resolving the current issues at Hartlepool and Heysham 1 is another step toward that objective. The Company’s improved profitability and positive cash contribution in the first quarter reflects higher realised prices for summer power contracts and underlines our confidence in British Energy’s prospects.”

Review and Outlook

Total output for the quarter was 17.4 TWh of which nuclear output was 15.7 TWh, and output from Eggborough was 1.7 TWh. Second quarter output as of 25 September 2005 was 14.8 TWh of which nuclear output was 14.0 TWh in line with plan. During the quarter, statutory outages were completed at Sizewell B and outages commenced at Heysham 1 and Hunterston B. During the planned outages the Group completed various plant improvements which were scheduled as part of the Performance Improvement Programme (PiP). Unplanned losses for the quarter were 1.8 TWh leading to reduced Unplanned Capability Loss Factor (UCLF) at most stations, partially offset by an overrun of the Sizewell B statutory outage. Statutory outages at Heysham 1 and Hunterston B were completed during the second quarter and the statutory outage at Dungeness B commenced. The statutory outage of one unit at Dungeness B is progressing and the other unit at Dungeness B is shut down for an unplanned outage and may require further work before their return to service.

On 12 September 2005, the Company announced it had elected to maintain the shutdown of two reactors at Hartlepool and to shutdown two reactors at Heysham 1 as a result of inspections to boiler closure units. The return to service of all four units is dependent on the successful outcome of further inspections and a programme of work at each unit. As a consequence, the return to service of the four units is expected during mid to end October 2005. As a result, the net additional unplanned losses are currently expected to increase by 0.5 TWh to around 1.5 TWh. Whilst more challenging, the Company reconfirms it expects the average annual nuclear output over the next two years to be 63 TWh.

Operating profit before depreciation and amortisation (EBITDA) for the quarter was £121m before the IAS 39 re-measurement impact reflecting the benefit of increased electricity prices. Operating costs were in line with plan and reflect increased revenue spend associated with investment in plant during 2005/06. As at 3 July 2005 the Group had cash and cash equivalents and restricted cash balances amounting to £510m, of which £250m was deposited as collateral in support of trading and operating activities.

Forward market prices for electricity for winter 2005/06 delivery have increased during the quarter, however they continue to show considerable volatility. As at 25 September 2005, the Company had fixed price contracts in place for approximately 85% of planned output for the financial year 2005/06 at an average contract price of approximately £31.8/MWh. This price includes the impact of capped price arrangements of approximately 5 TWh at around £30/MWh and the benefit of higher prices achieved as a result of Eggborough taking advantage of the differential between peak and baseload prices. This price excludes Balancing Services Use of System and other electricity market participation charges of around £0.7/MWh, market costs incurred through output variation and unreliability expected to be around £1.0/MWh. The level of output at fixed prices has been impacted by unplanned losses at Heysham 1 and Hartlepool and the requirement to manage collateral. The Company intends to progressively close out its exposure to market prices for the financial year 2005/06 subject to limits on trading collateral which are easing and has made satisfactory progress in fixing prices for the financial year 2006/07.

On 15 September 2005, the Group announced the completion of the necessary technical and economic evaluation regarding the potential accounting life extension at Dungeness B. This has resulted in the accounting life of Dungeness B being extended by ten years to 2018, five years beyond the accounting life extension assumed as part of the fair value exercise related to the restructuring on 14 January 2005.

During the quarter, investment expenditure across the whole Group on plant projects, major repairs and strategic spares, including costs associated with PiP, totalled £41m, of which £18m has been capitalised. In addition, £24m of overhaul costs were capitalised in the quarter. Based on its current expectations of future electricity prices and output, and therefore financial resources, the Company reconfirms that investment in plant projects, major repairs and strategic spares including costs associated with PiP across the whole Group is expected to be in the range of £230m to £250m for the year ending 31 March 2006.

On 21 September 2005, the Department for Environment Food and Rural Affairs issued an update regarding the implementation of the Large Combustion Plant Directive (“LCPD”). The update indicated that the Government will apply emission limit values to control emissions from power stations in the UK from January 2008. The update gave no further clarification as to whether Eggborough would be treated as having separate plants for the purposes of LCPD. If the final decision is to consider the four units at Eggborough as a single plant for LCPD purposes then there could be a requirement to materially restrict the operations of the two non-FGD units from 2008 in order to comply with the proposed emission limit values.

Explanatory notes

These results for British Energy have been prepared under International Financial Reporting Standards (IFRS) for the quarter ended 3 July 2005. This is the first set of quarterly results prepared under IFRS. As part of the transition from United Kingdom Generally Accepted Accounting Principles (UK GAAP) to IFRS, a Restatement of Results for Transition to International Financial Reporting Standards was published on 21 September 2005.

Electricity demand in the UK is seasonal, in that demand and prices are generally lower in summer than in winter. As a result, British Energy (and other generators) schedule a significant proportion of planned outages for the summer months. This seasonality in both prices and output has a direct effect on financial performance and cash flows.

A summary of the results is set out below:


Output and Unit Costs	Quarter ended 3 July 2005 before re-measurement (£m)	Quarter ended 3 July 2005 after re-measurement (£m)
Output (TWh)
- Nuclear	15.7	15.7
- Coal	1.7	1.7

Total Output	17.4	17.4
Realised price (£/MWh)	24.7	23.0

Total operating unit cost (£/MWh)	20.6	20.7

Margin (£/MWh)	4.1	2.3

(All numbers rounded)


Income Statement Summary	Quarter ended 3 July 2005 before re-measurement (£m)	Quarter ended 3 July 2005 after re-measurement (£m)
Revenue	521	487
Operating costs	444	442
Operating profit	77	45
Profit before tax	64	32


EBITDA⁽¹⁾ Summary	Quarter ended 3 July 2005 before re-measurement (£m)	Quarter ended 3 July 2005 after re-measurement (£m)
Operating profit	77	45
Add: Depreciation	43	43
Add: Amortisation	1	1
EBITDA	121	89

Details of cash and net debt are summarised in the table below.


Cash Balances	As at 3 Jul 05 (£m)		As at 31 Mar 05 (£m)
Cash not used for collateral Cash used for collateral	260 250		240 216
Cash, cash equivalents and restricted cash	510		456
Total Debt	(676	)	(676	)
Net Debt	(166	)	(220	)

Safe Harbour

This document contains certain “forward-looking” statements as defined in Section 21E of the US Securities Exchange Act of 1934, including statements with respect to British Energy’s business plans, the performance of its stations, electricity prices and other matters that are not historical facts concerning the business operations, financial condition and results of operations of British Energy. These forward-looking statements typically contain words such as “intends”, “expects”, “anticipates”, “estimates”, “aim”, “believe”, “assume”, “should” and words of similar import, which are predictions of or indicate future events or future trends. These forward-looking statements involve known and unknown risks, uncertainties and other factors, which are in some cases beyond the control of British Energy and may cause actual results or performance to differ materially from those expressed or implied from such forward-looking statements. British Energy has identified some important factors that may cause such differences in its Form 20-F, filed with the US Securities and Exchange Commission, for the financial year ended 31 March 2005 and the report and accounts for period ended 31 March 2005.

Due to the uncertainties and risks associated with these forward-looking statements, which speak only as to the date hereof, we are claiming the benefit of the safe harbour provision referred to above.

Management Presentation and Conference Call

Management will host a conference call for analysts, institutional investors and bondholders at 2.00pm (UK time) today, 28 September 2005 and dial in facilities can be accessed by:


UK local rate no:		0845 113 0049
UK international no:		+44 (0) 1452 542 303
US no:		1866 389 9778


Replay facility – 7 days, UK dial in:
UK local rate no:		0845 245 5205
UK International no:		+44 (0) 1452 550 000
UK PIN (access) no:		9732439 #

For further information please contact:


John Searles, Investor Relations:		01506 408 715
Andrew Dowler, Media:		020 7831 3113

A copy of this release and a copy of the presentation in pdf file format can be found on the Company’s web site at www.british-energy.com.

Notes:

EBITDA is defined by the Company as operating profit before interest, income taxes, depreciation and amortisation and has been presented both including and excluding the effects of re-measurement. The Company has included information concerning EBITDA because it believes that it is used by certain investors as one measure of the Company’s financial performance. EBITDA is not a measure of financial performance under IFRS and is not necessarily comparable to similarly titled measures used by other companies. EBITDA should not be construed as an alternative to operating income or to cash flows from operating activities (as determined in accordance with IFRS) as a measure of liquidity.

Management’s Discussion and Analysis – Financial Condition and Results Of Operations

Overview and Outlook

In the following discussion the ‘quarter’ refers to the quarter ended 3 July 2005 unless otherwise stated. In this discussion references to ‘British Energy’ or the ‘Company’ are to British Energy Group plc. References to the ‘Group’ are to the Company and its subsidiaries. The results of operations have been adjusted to reflect the result before exceptional charges and other movements arising from re-measurement for the impact of IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39) for the quarter. During the quarter there were no exceptional charges. British Energy believes that the adjusted measures provide a better indication of the underlying business performance.

The Group was successfully restructured on 14 January 2005 and continues to own and operate eight nuclear power stations and one coal-fired power station in the UK. The Company’s three imperatives are achieving world-class nuclear operational performance; improving its financial stability; and pursuing life extensions for its stations.

To achieve these goals the Group is investing in activities required to improve output and reliability of its nuclear power stations while managing energy price risk through its electricity trading division. To support this, investment in plant projects, major repairs and strategic spares including costs associated with the Performance Improvement Programme (PiP) for the quarter was £41m and the Company confirms that investment is expected to be in the range of £230m to £250m for the financial year 2005/06. Safety and environmental performance also continue to be a fundamental priority of the Company.

Total output for the quarter was 17.4 TWh of which nuclear output was 15.7 TWh, in line with plan, and output from Eggborough was 1.7 TWh. Second quarter output as of 25 September 2005 was 14.8 TWh of which nuclear output was 14.0 TWh in line with the Company’s expectation to generate nuclear output of 63 TWh per annum on average over the current and next financial year. During the quarter, statutory outages were completed at Sizewell B and outages commenced at Heysham 1 and Hunterston B. During the planned outages the Group completed various plant improvements which were scheduled as part of PiP. Unplanned losses for the quarter were 1.8 TWh leading to reduced Unplanned Capability Loss Factor (UCLF) at most stations, partially offset by an overrun of the Sizewell B statutory outage. Statutory outages at Heysham 1 and Hunterston B were completed during the second quarter and the statutory outage at Dungeness B commenced.

Forward market prices for electricity for winter 2005/06 delivery have increased during the quarter, however they continue to show considerable volatility. As at 25 September 2005, the Company had fixed price contracts in place for approximately 85% of planned output for the financial year 2005/06 at an average contract price of approximately £31.8/MWh. This price includes the impact of capped price arrangements of approximately 5 TWh at around £30/MWh and the benefit of higher prices achieved as a result of Eggborough taking advantage of the differential between peak and baseload prices. The level of output at fixed prices has been impacted by unplanned losses at Heysham 1 and Hartlepool and the requirement to manage collateral. The Company intends to progressively close out its exposure to market prices for the financial year 2005/06 subject to limits on trading collateral which are easing and has made satisfactory progress in fixing prices for the financial year 2006/07.

In accordance with the dividend policy set out within the accounts for the period ended 31 March 2005 and in the Dividend Policy section below, no dividend has been declared for the quarter.

On 15 September 2005, the Group announced the completion of the necessary technical and economic evaluation regarding the potential life extension at Dungeness B. This has resulted in the accounting life of Dungeness B being extended by ten years to 2018, five years beyond the extension assumed as part of the restructuring related fair value exercise.

Key Points on Results

•

EBITDA for the quarter was £121m* before re-measurement impact, £89m after re-measurement impact.

•

Operating profit was £77m* in the quarter before re-measurement impact, £45m after re-measurement impact.

•

Profit before tax of £64m* was recorded in the quarter before re-measurement impact, £32m after re-measurement impact.

•

Total output for the quarter was 17.4 TWh. Nuclear output in the quarter (94 days) was up by 5% to 15.7 TWh, compared with 15.0 TWh in the 2004/05 first quarter (91 days). Coal output was 1.7 TWh in the quarter compared to 1.4 TWh in the first quarter of 2004/05.

•

Realised price (which is calculated by dividing revenue, before any re-measurement impact, energy supply costs recharged to customers and miscellaneous income, and is net of energy purchase costs, by total output during the period) was £24.7/MWh for the quarter.

•

Total operating unit costs, excluding revalorisation (which are calculated by dividing the total operating costs, before any re-measurement, energy supply costs recharged to customers and energy purchases, by total output during the period), were £20.6/MWh for the quarter.

•

Operating cash inflow from operations was £59m for the quarter. Net debt decreased in the quarter by £54m to £166m.

•

The Nuclear Liabilities Fund (NLF) Cash Sweep percentage was 64.80% at 3 July 2005, down from 64.99% at 31 March 2005 as a result of the exercise of a number of the Company’s warrants. No accrual for any potential NLF Cash Sweep payment has been made in these quarterly financial statements. In accordance with the Government Contribution Agreement, an accrual will be made for the weighted average NLF Cash Sweep percentage payment applied to adjusted net cash flow as at 31 March 2006 to the extent adjusted net cash flow arising from operations during the year is above £290m plus posted collateral (subject to a £200m minimum) at 31 March 2006.

Items marked * represent the results of operations adjusted to reflect the result before exceptional charges and other movements arising from re-measurement. During the quarter there were no exceptional charges. For the first quarter the re-measurement adjustments relate solely to the re-measurement impact of IAS 39 on the results for the quarter. British Energy believes that the adjusted measures provide a better indication of the underlying business performance.

Explanatory Notes

This report contains British Energy’s results prepared under International Financial Reporting Standards (IFRS) for the quarter ended 3 July 2005. This is the first set of quarterly results prepared under IFRS. As part of the transition from United Kingdom Generally Accepted Accounting Principles (UK GAAP) to IFRS a Restatement of Results for Transition to International Financial Reporting Standards was published on 21 September 2005. The main areas of difference between UK GAAP and IFRS for British Energy are:

•

goodwill

•

pensions

•

deferred tax

•

financial instruments

This is the first time since completion of the restructuring of the Group on 14 January 2005 that British Energy has published results for its first quarter. Therefore this report does not contain any comparative quarterly financial information but, where appropriate, does contain comparative quarterly non-financial information.

From 1 April 2005, the Company has operated a 4:4:5 week reporting cycle for quarterly reporting, with reporting periods ending on a Sunday. Accordingly, this set of quarterly results has been prepared to 3 July 2005. The annual results will be prepared to 31 March 2006.

Certain statements in this document are ‘forward-looking’ statements as defined in Section 21E of the US Securities Exchange Act of 1934. Such forward-looking statements include, among others:

•

other matters that are not historical facts concerning the Group’s 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 the Group’s control and may cause its actual results or performance to differ materially from those expressed or implied by such forward-looking statements. Due to the uncertainties and risks associated with these forward-looking statements, which apply only as at the date hereof, the Company is claiming the benefit of the safe harbour provision contained in Section 21E of the US Securities Exchange Act of 1934.

British Energy has also prepared a quarterly report on a Form 6-K under US GAAP for the quarter ended 3 July 2005. The full financial statements prepared under UK GAAP for the period ended 31 March 2005 and the notes thereto are not included in this report but are available on the British Energy website (www.british-energy.com).

The following discussion and analysis should be read in conjunction with the unaudited financial statements for the quarter ended 3 July 2005 and the notes thereto which are included in this report.

OPERATIONAL REVIEW

Plant Output

Nuclear output was 15.7 TWh (a 73% load factor) for the quarter (94 days). The nuclear output for the quarter ended 30 June 2004 (91 days) was 15.0 TWh (a 72% load factor). During the period a statutory outage was completed at Sizewell B, and one started at each of Heysham 1 and Hunterston B. Since successfully completing its statutory outage, following an overrun, Sizewell B has operated continuously at full power. There were planned outages amounting to 3.8 TWh of lost output. Unplanned losses for the quarter were 1.8 TWh leading to reduced UCLF at most stations, offset by the Sizewell B statutory outage overrun.

Output from the coal-fired power station at Eggborough was 1.7 TWh during the quarter. For the quarter ended 30 June 2004, the output was 1.4 TWh. As Eggborough is operated primarily as a flexible mid-merit plant, its output level is influenced by market prices, the Company’s contracted trading position and the extent to which it is operated as cover for unplanned outages at the nuclear power stations.

Performance Improvements

Work continues to implement PiP with the aim to improve the reliability of the nuclear power stations and reduce the level of unplanned nuclear losses. Last year the focus was on improvements relating to people, plant and processes and is now on implementation, with an emphasis on integrating PiP across the business.

Non-outage defect backlog has reduced by 11% in the quarter as a result of focusing on equipment reliability, work management and an improved operational focus. Both nuclear reportable events and unplanned trips show an improving trend in the quarter.

Independent of internal improvement monitoring arrangements, a number of favourable WANO assessments have been received recently with positive reports received from recent reviews at Sizewell B, Hinkley Point and Heysham 1 and 2.

Investment Expenditure

During the quarter, investment expenditure across the whole Group on plant projects, major repairs and strategic spares, including costs associated with PiP, totalled £41m, of which £18m has been capitalised. In addition, £24m of overhaul costs were capitalised in the quarter. The main investment in plant in the period included additional safety work at Hartlepool and Heysham 1, turbine work at Heysham 1, low pressure rotor refurbishment at Heysham 2 and Hunterston and generator transformer refurbishment at Hartlepool. Based on its current expectations of future electricity prices and output, and therefore financial resources, the Company reconfirms that investment in plant projects, major repairs and strategic spares including costs associated with PiP across the whole Group is expected to be in the range of £230m to £250m for the year ending 31 March 2006.

Safety and Environmental Performance

A key priority of the Group is to manage the safety of our plant, people and the general public. Lost time accidents for staff and non-staff have increased during the quarter largely due to an increased number of accidents involving non-staff. We remain absolutely committed to safety and ensuring the safety of our staff, non-staff and the general public.

The environmental performance of the Group also continues to remain a fundamental priority of the Company. Environmental performance indicators have been reclassified and as a result we have no comparable data but the indicators in the year to date are ahead of the Group’s expectations.

Operational Update

Flue Gas Desulphurisation (FGD) installation on Units 3 and 4 at Eggborough has been completed and the plant was taken over from the contractors on 1 September 2005.

Inspections carried out during the Unit 4 outage at Eggborough in the quarter revealed evidence of cracking on a number of the turbine blades. The affected turbine blades will be removed and this unit is expected to return to service as planned, albeit with a small reduction in capacity. Inspections of other units showed that cracking was not widespread.

On 21 September 2005, the Department for Environment Food and Rural Affairs issued an update regarding the implementation of the Large Combustion Plant Directive (LCPD) pending a formal decision by the Government expected before the end of this year. The update indicated that the Government will apply emission limit values to control emissions of sulphur dioxide, nitrogen oxides and particulates from power stations in the UK from January 2008. The update repeated the European Commission’s view that existing plants whose waste gases are discharged through a common stack should be considered as a single plant for the purposes of the LCPD, however it gave no further clarification of whether multiple generating units each with their own separate flue (as at Eggborough) can be treated as separate plants for the purposes of the LCPD pending further discussions with the European Commission.

NDA Strategy

The Nuclear Decommissioning Authority published its draft strategy document and has provided an opportunity for full and open consultation on the issue of decommissioning the UK’s nuclear waste legacy. As major stakeholders, we intend to play a full part in this consultation.

The Company has contracts with Springfields Fuels Limited (a subsidiary of BNFL plc) for the supply of AGR fuel and with British Nuclear Group (a subsidiary of BNFL plc) for the receipt of all the spent fuel from the Group’s AGR stations. These contracts are for the full lifetime of the Group’s AGR stations.

Quinquennial Review

The quinquennial review of our nuclear liabilities is underway and the results of this review will be finalised towards the end of 2005. The review may result in a significant change in value of the nuclear liabilities due to changes in strategy and cost estimates but as a result of the arrangements with the NLF and Government, any change in value of the nuclear liabilities will be offset by an equal and opposite change in the value of the NLF receivable.

TRADING REVIEW

Trading Position

Forward market prices for electricity for winter 2005/06 delivery have increased during the quarter, however they continue to show considerable volatility. As at 25 September 2005, the Company had fixed price contracts in place for approximately 85% of planned output for the financial year 2005/06 at an average contract price of approximately £31.8/MWh. This price includes the impact of capped price arrangements of approximately 5 TWh at around £30/MWh and the benefit of higher prices achieved as a result of Eggborough taking advantage of the differential between peak and baseload prices. This price excludes Balancing Services Use of System and other electricity market participation charges of around £0.7/MWh and market costs incurred through output variation and unreliability expected to be around £1.0/MWh. The level of output at fixed prices has been impacted by unplanned losses at Heysham 1 and Hartlepool and the requirement to manage collateral. The Company intends to progressively close out its exposure to market prices for the financial year 2005/06 subject to limits on trading collateral which are easing and has made satisfactory progress in fixing prices for the financial year 2006/07.

Collateral

The Group’s strategy for securing part of its income through fixed price contracts means that in a volatile and rising electricity market collateral requirements are also volatile and rising. The Group’s ability to secure longer term certainty on its income is limited by the amount of collateral and headroom available to cover collateral volatility. The Group mitigates a certain amount of this risk by selling electricity through a number of routes to market including through its direct supply business (to large industrial and commercial customers) which does not require as much collateral and also through the use of financial products which provide electricity price protection but require less collateral.

FINANCIAL REVIEW FOR THE QUARTER ENDED 3 JULY 2005

Group Performance

The unaudited results for the quarter can be summarised as follows:


	Quarter ended 3 July 2005 Business performance £m		Quarter ended 3 July 2005 Re-measurement £m		Quarter ended 3 July 2005 Total £m
Group revenue	521		(34	)	487
EBITDA	121		(32	)	89
Operating profit/(loss)	77		(32	)	45
Financing charges	(13	)	—		(13	)

Profit/(loss) before tax	64		(32	)	32

The discussion below focuses on the business performance results as British Energy believes that this adjusted measure provides a better indication of underlying performance.

Revenue

Group revenue from continuing activities comprised generation sales, direct supply sales and miscellaneous income. Revenue was £521m for the quarter.

The analysis of revenue for the quarter is as follows:


		Quarter ended 3 July 2005 £m
Group revenue
Wholesale generation sales		230
Direct supply sales net of energy supply costs		204

		434
Energy supply costs recharged to customers		82
Miscellaneous income		5

Revenue		521

Wholesale generation sales includes revenue from Energy Purchases which cost £4m.

Output can be analysed as follows:


		Quarter ended 3 July 2005 TWh
Nuclear		15.7
Eggborough		1.7

Total		17.4

The realised price for the quarter was £24.7/MWh.

Operating Costs

Operating costs were £444m for the quarter, as detailed below.


	Quarter ended 3 July 2005 £m
Fuel costs – nuclear	84
Fuel costs – fossil	53

Total fuel costs	137
Energy purchases	4
Materials and services	100
Staff costs	80
Depreciation	43
Amortisation	1
Other operating income	(3	)
Energy supply costs	82
NLF Cash Sweep payment	—

Total operating costs	444

Total operating unit costs were £20.6/MWh for the quarter.

The component elements of the operating costs are discussed below.

Fuel Costs

Total fuel costs amounted to £137m for the quarter. Nuclear fuel costs were £84m for the quarter and Eggborough fuel costs for the quarter were £53m. Eggborough fuel costs included £24m attributable to carbon costs.

The market price of CO2 allowances has risen since the beginning of 2005 and was approximately €25/tonne at 3 July 2005, increasing the marginal cost of coal and gas generation.

Energy Purchases

Energy purchases of £4m primarily represent the cost of contracts entered into in order to obtain Renewable Obligation Certificates (ROCs) and Levy Exemption Certificates (LECs).

Materials and Services

Materials and services costs comprise the operating expenses of the power stations and support functions excluding fuel costs, staff costs and depreciation. The costs during the quarter were £100m.

Staff Costs

Staff costs were £80m for the quarter and included pension costs of £14m.

Employer contributions to the pension scheme were £17m for the quarter reflecting the impact of new salary sacrifice arrangements introduced from 1 April 2005.

Depreciation

Depreciation charges were £43m for the quarter.

Amortisation

Amortisation charges on capitalised software costs were £1m for the quarter.

Other Operating Income

The other operating income of £3m for the quarter relates to utilisation, excluding revalorisation, of the net commodity contracts provision, which was established on restructuring.

Energy Supply Costs

Energy supply costs mainly comprise the costs incurred for the use of the distribution and transmission systems and accrued costs of ROCs under the Renewable Obligation and are fully recovered through revenue. Total energy supply costs were £82m for the quarter.

NLF Cash Sweep Payment

In accordance with the Group’s accounting policy these quarterly financial statements make no accrual for any potential future NLF Cash Sweep payment that may be payable based on the full year results.

Operating Profit

The Group operating profit for business performance was £77m for the quarter.

Financing Charges

The total financing charges are analysed below:


	Quarter ended 3 July 2005 £m
Revalorisation of nuclear liabilities	67
Revalorisation of nuclear liabilities receivable and NLF receivable	(67	)
Revalorisation of fixed decommissioning obligation	4
Revalorisation of contracts provision	4

Total revalorisation	8
Net interest expense	7
Net credit to finance charge for pension liability	(2	)

Total financing charges	13

Revalorisation of nuclear liabilities arises because nuclear liabilities are stated in the balance sheet at current price levels, discounted at 3% per annum real from the eventual payment dates. The revalorisation charge is the adjustment that results from restating these liabilities to take into account the effect of inflation in the period and to remove the effect of the discount for the quarter.

A revalorisation credit arises in respect of movements in the value of nuclear liabilities receivable and the NLF receivable to take account of the underlying movement in nuclear liabilities.

Revalorisation charges arise in respect of the fixed decommissioning obligation and the contracts provision to reflect the unwinding of the discount for the quarter.

IAS 39 and Contract Provisions

The total movements on the IAS 39 values and the net commodity contracts provision established as part of the fair value exercise are analysed below:


	IAS 39 values £m	Contract provision £m		Total £m
As at 1 April 2005	34	238		272
Charge/(credit) to the income statement	32	(3	)	29
Revalorisation	—	4		4
Increase in hedge reserve through the statement of recognised income and expense	52	—		52

As at 3 July 2005	118	239		357

Following the adoption of IAS 39 at 1 April 2005 the opening value of £34m has risen by £84m to £118m. The effect on operating profit in the quarter has been a reduction of £32m with the balance of £52m being recognised through the statement of recognised income and expense.

The contract provision relates to contracts outwith the scope of IAS 39, which were initially valued at the restructuring effective date of 14 January 2005. The provision is being utilised over the lives of these contracts. The provision has increased by £1m in the quarter.

Taxation

Income tax is calculated on the profit for the period, before taking account of the income statement effect of any adjustments to the measurement and classification of financial instruments required by IAS 39, at the anticipated annual effective rate applicable to this profit. Any charge for the NLF Cash Sweep payment included in the annual results will not be tax deductible and therefore the anticipated annual effective rate is significantly more than the standard rate of 30%. Adjustments to profit arising from the application of measurement and classification rules for financial instruments contained in IAS 39 are tax effected at the standard rate of 30%. There is no current tax charge in the period due to the availability of trading losses carried forward. The charge of £26m before re-measurement and £16m after re-measurement in the period consists of deferred tax only.

Profit after Tax

As a result of the factors discussed above, the net profit for the period attributable to equity shareholders was £38m before re-measurement and £16m after re-measurement.

Earnings per Share

There was an earnings per share of 6.7p for the quarter, based on the net profit for the period before the effect of re-measurement divided by the weighted average number of ordinary shares in issue during the period. After the effect of re-measurement, earnings per share was 2.8p for the quarter.

The diluted earnings per share for the quarter was 6.6p before the effect of re-measurement and 2.8p after the effect of re-measurement. The conversion rights of the NLF Cash Sweep is not considered dilutive.

Actuarial Loss on Pensions

There has been one significant change in the actuarial assumptions adopted at 3 July 2005 compared with 31 March 2005 that mainly contributed to the actuarial loss on pensions of £172m that has been recorded in the statement of recognised income and expense. The discount rate used to value the liabilities has changed from 5.5% per annum to 5.0% per annum in line with market changes in the yield on long-dated corporate bonds over the period. The effect of the change in the discount rate is to place a higher value on the pension liabilities, resulting in a significant actuarial loss in the quarter.

Research and Development

The Group supports primarily scientific and engineering research activities directed toward securing further improvements in the reliability, performance and safety of the generating business and related activities. For the quarter expenditure on research and development was £3m which is included within material and services costs.

Future Reporting

At the Company’s recent Annual General Meeting a resolution was passed that amended the Company’s Articles of Association. These changes allow the Group to deregister from the US Securities and Exchange Commission subject to receiving consent from the holders of the Group’s bonds to the cessation of reporting under US GAAP.

The next set of quarterly results to be presented will be for the quarter ending 2 October 2005.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flow from Operating Activities

A reconciliation of profit after tax to earnings before interest, income taxes, depreciation and amortisation (EBITDA) is shown in the following table. EBITDA is a measure commonly reported and widely used by analysts, certain investors and other interested parties, as well as a measure used internally by the Group. The EBITDA is further reconciled to the operating cash inflow and movement in restricted cash and then to the increase in total cash.


	Quarter ended 3 July 2005 £m
Profit after tax before the effect of re-measurement	38
Net interest expense	7
Net revalorisation charges	8
Net credit to financing charges for pension liabilities	(2	)
Taxation	26
Amortisation	1
Depreciation	43

EBITDA before the effect of re-measurement	121
Effect of re-measurement	(32	)

EBITDA after the effect of re-measurement	89
Regular contributions to NLF	(12	)
Working capital movements	(26	)
Loss on disposal of property, plant and equipment	1
Net interest paid	(6	)
IAS 39 movements	47

Operating cash inflow and movement in restricted cash	93
Capital expenditure	(44	)
Exercise of warrants	5

Increase in total cash	54

Represented by:
Increase in cash and cash equivalents	20
Increase in restricted cash	34

Total decrease in net debt	54

The operating cash inflow and movement in restricted cash for the quarter was £93m. When adjusted for capital expenditure, net interest paid and the exercise of warrants there was an increase in total cash of £54m for the quarter. The adverse movement on working capital of £26m for the quarter can be attributed mainly to a reduction in trade and other payables.

Management of Restricted Cash

The balances on the term deposit accounts holding the collateral amounts increased by £34m from £216m at 31 March 2005 to £250m at 3 July 2005. Also included in restricted cash at 31 March 2005 and 3 July 2005 was £5m.

Capital Resources

At 3 July 2005, total debt of £676m comprised:

•

The Amended Credit Agreement, a long-term project finance loan, of £145m secured on the assets of Eggborough Power Limited (EPL), a subsidiary company that operates the Eggborough coal-fired power station. The loan bears interest at a rate of 7.0%.

•

An aggregate principal amount of £531m Sterling denominated guaranteed bonds due between 2005 and 2022 (the Bonds). The Bonds have a coupon of 7.0%.

The long-term project finance loan is secured by a mortgage of shares in EPL, an assignment of the EPL Share Purchase Agreement and Tax Deed of Covenant and a debenture comprising fixed and floating charges over EPL assets.

Net debt decreased in the quarter by £54m to £166m.

Liquidity

At 3 July 2005 the Group had cash and cash equivalents and restricted cash, including amounts posted as collateral, amounting to £510m, of which £250m was deposited as collateral in support of trading activities.

The Group’s main source of liquidity is its operating businesses. Cash generation by the operating businesses is dependent upon the reliability of the Group’s power stations in producing electricity, the realised selling price for electricity, operational risk and investment expenditure and maintenance requirements.

The lack of an investment grade credit rating has meant that the Group continues to provide significant levels of collateral to counterparties in order to cover their trading exposures and maintain trading arrangements, thereby substantially reducing the levels of cash resources available to the Group.

The Group’s future liquidity may also be impacted by the additional employer pension contributions set out within the ‘Financial Review’ section of our report and accounts for the period ended 31 March 2005. Our exposures to market risk have not changed materially since 31 March 2005.

Post Balance Sheet Events

Contingent Liabilities

On 12 February 2004, British Energy Limited and certain of its subsidiaries received a notice of warranty claims from the consortium which purchased the Group’s 82.4% interest in Bruce Power LP alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce power station.

The principal tax claim relates to the treatment of expenditure at the Bruce Power plant during the period of the Group’s part ownership and is currently being considered by the Canadian tax authorities. The treatment proposed by British Energy could result in a rebate of a material amount of tax to the Group that has never been recognised in the financial statements. The consortium claims that allowance of the expenditure for that period would cause it to lose future deductions. British Energy has rejected the tax claim and expects to defend it if it is pursued further. The Company is confident that the amount of the tax claim should not, in any event, materially exceed the amount of the rebate, and that the tax claim should have no material cash flow impact on the Group.

The claim relating to the condition of the plant is based upon alleged erosion of certain parts of the steam generators, including the support plates, through which boiler tubes pass, which it is alleged resulted in an extended outage of one unit at the plant to carry out repair works and loss of revenues and costs of approximately C$64.5m. The consortium also claims that the alleged erosion may reduce the operating life of the unit and/or result in further repairs involving further losses. British Energy has rejected the claim and expects to defend it if it is pursued further. No provision has been made in the financial statements at 3 July 2005 for either claim.

Under the agreement with the consortium C$20m is retained in trust to meet any representation and warranty claims, and this may be retained pending agreement or determination of the claims.

Dividend Policy

The Board intends to distribute to shareholders as much of the Company’s available cash flow as prudently possible, but not until the operational requirements of the business permit. In addition, under the terms of the restructuring, there are certain restrictions on or factors affecting the Board’s ability to pay dividends, including:

•

the requirement to fund a cash reserve out of the Group’s post-debt service cash flow in order to support the Group’s collateral and liquidity requirements following the restructuring. The initial target amount for the cash reserve is £490m plus the amount by which cash employed as collateral exceeds £200m (the Target Amount). There will be no distributions to shareholders until such time as the cash reserve is at the required level. As a result of the requirements to fund the cash reserve, the Board is not proposing a dividend in respect of the quarter ended 3 July 2005 and does not currently expect to propose a dividend before the financial year ending 31 March 2007.

•

the terms of the Nuclear Liabilities Agreements entered into as part of the restructuring also require that once the cash reserve is funded to the Target Amount, the Company must make NLF Cash Sweep payments to the NLF. The NLF Cash Sweep payment was initially defined as 65% of the movement in cash, cash equivalents and other liquid assets during the year after adjusting for, among other things, certain payments made to the NLF or dividends paid in the year. The requirement to make the NLF Cash Sweep payment greatly reduces the amount of cash available for distribution to shareholders.

•

the terms of the bonds issued as part of the restructuring contain certain covenants, including a restriction that allows British Energy to pay a dividend only if no event of default has occurred; and

•

the requirement for the Company to have distributable reserves.

Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk, see the ‘Financial Review’ section of our report and accounts for the period ended 31 March 2005. Our exposures to market risk have not changed materially since 31 March 2005.

NON-GAAP FINANCIAL MEASURES

Business Performance

Business performance excludes certain re-measurement items (see below) and is presented as management believes that exclusion of these items provides readers with a clear and consistent presentation of the underlying operating performance of the Group’s business.

Re-measurement

The impact of re-measurement reflects exceptional charges and other movements, including the impact of IAS 39. The scope of IAS 39 includes all financial instruments i.e. loans, trade receivables, payables, investments, cash and derivatives, as well as certain commodity contracts. The standard requires that all derivatives, including certain commodity contracts, are fair valued on the balance sheet, with changes from re-measurement being recorded in the income statement unless cash flow hedge accounting is applied.

Unrealised gains and losses in respect of commodity contracts are disclosed separately as re-measurements. Realised gains and losses relating to these contracts are included in business performance. Management considers that this presentation best reflects the underlying performance of the business since it distinguishes between the temporary timing differences associated with re-measurement under IAS 39 rules and actual realised gains and losses.

Exceptional charges, by their nature, are not indicative of the underlying operating performance of the Group.

For a reconciliation between the overall results and business performance and details of re-measurement items, see the consolidated income statement.

Realised Price

Realised price is calculated by dividing revenue (before any re-measurement impact, energy supply costs recharged to customers and miscellaneous income, and net of energy purchase costs) by total output during the period. The adjustments to revenue allow management and investors a better understanding of the net price that customers are paying for our electricity.

Total Operating Unit Costs

Total operating unit costs are calculated by dividing the total operating costs (before any re-measurement, energy supply costs recharged to customers and energy purchase costs) by total output during the period.

EBITDA

EBITDA is operating profit before interest, income taxes, depreciation and amortisation and has been presented both including and excluding the effects of re-measurement. The Company has included information concerning EBITDA because it believes that it is used by certain investors as one measure of the Company’s financial performance. EBITDA is not a measure of financial performance under IFRS and is not necessarily comparable to similarly titled measures used by other companies. EBITDA should not be construed as an alternative to operating income or to cash flows from operating activities (as determined in accordance with IFRS) as a measure of liquidity.

CONSOLIDATED INCOME STATEMENT

FOR THE QUARTER ENDED 3 JULY 2005 (UNAUDITED)


	Notes	Quarter ended 3 July 2005 Business performance £m		Quarter ended 3 July 2005 Re-measurement £m		Quarter ended 3 July 2005 Total £m		2 July 2004 to 31 March 2005 £m
Revenue	2	521		(34	)	487		499
Energy purchases		(4	)	4		—		(17	)
Fuel costs		(137	)	(2	)	(139	)	(127	)
Materials and services		(100	)	—		(100	)	(82	)
Staff costs		(80	)	—		(80	)	(82	)
Energy supply costs		(82	)	—		(82	)	(73	)
Other operating income/(costs)		3		—		3		(8	)

Operating profit/(loss) before depreciation and amortisation (EBITDA)		121		(32	)	89		110

Depreciation		(43	)	—		(43	)	(40	)
Amortisation		(1	)	—		(1	)	(1	)

Operating profit/(loss)		77		(32	)	45		69

Financing (charges)/credits
Net revalorisation charges	3	(8	)	—		(8	)	(5	)
Interest payable		(12	)	—		(12	)	(10	)
Interest receivable		5		—		5		5
Net credit to finance charges for pension liabilities		2		—		2		1

Profit/(loss) before tax		64		(32	)	32		60

Taxation	4	(26	)	10		(16	)	(19	)

Net profit/(loss) for the period attributable to equity shareholders		38		(22	)	16		41

Earnings/(deficit) per share (p):
Basic	5	6.7		(3.9	)	2.8		7.3
Diluted	5	6.6		(3.8	)	2.8		7.0

The Income Statement for the period 2 July 2004 to 31 March 2005 represents the trading results for the period from 15 January 2005 to 31 March 2005, the period after the acquisition of British Energy Limited by British Energy Group plc.

CONSOLIDATED BALANCE SHEET

AS AT 3 JULY 2005 (UNAUDITED)


	Notes	As at 3 July 2005 £m		As at 31 March 2005 £m
Assets
Non-current assets
Property, plant and equipment		1,684		1,686
NLF receivable		1,902		1,863
Nuclear liabilities receivable		2,118		2,131
Deferred income tax asset		487		429
Goodwill and intangible assets		377		376
Receivables due after more than one year		3		4

		6,571		6,489

Current assets
Inventories		335		331
Nuclear liabilities receivable		185		181
Trade and other receivables		315		327
Cash and cash equivalents		255		235
Restricted cash		255		221
Financial instruments - commodity contracts		20		—

		1,365		1,295

Total assets		7,936		7,784

Liabilities
Current liabilities
Borrowings		(50	)	(50	)
Trade and other payables		(388	)	(378	)
Nuclear liabilities		(185	)	(181	)
Provisions for other liabilities and charges		(166	)	(230	)
Financial instruments - commodity contracts		(118	)	—

		(907	)	(839	)

Non-current liabilities
Borrowings		(626	)	(626	)
Pension fund liability	6	(548	)	(381	)
Provision for nuclear liabilities		(1,902	)	(1,863	)
Provisions for other liabilities and charges		(130	)	(108	)
Nuclear liabilities		(2,118	)	(2,131	)
NLF liabilities		(209	)	(210	)
Financial instruments - commodity contracts		(20	)	—
Deferred income		(5	)	(5	)

		(5,558	)	(5,324	)

Total liabilities		(6,465	)	(6,163	)

Net assets		1,471		1,621

Equity
Called up equity share capital		57		56
Share premium		13		—
Other reserves		767		767
Hedge reserve		(57	)	—
Warrant reserve		42		51
Retained earnings		649		747

Total equity		1,471		1,621

CONSOLIDATED STATEMENT OF RECOGNISED INCOME AND EXPENSE

FOR THE QUARTER ENDED 3 JULY 2005 (UNAUDITED)


	Quarter ended 3 July 2005 £m		2 July 2004 to 31 March 2005 £m
Adjustment for the implementation of IAS 39 after tax at 1 April 2005	(15	)	—
Losses on hedges recognised for the period ended 3 July 2005	(52	)	—
Actuarial (losses)/gains on retirement benefits for the period ended 3 July 2005	(172	)	82
Tax on items taken directly to equity for the period ended 3 July 2005	67		(25	)

Net (losses)/gains recognised directly in equity	(172	)	57
Profit for the period	16		41

Total recognised income and expense for the period	(156	)	98

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE QUARTER ENDED 3 JULY 2005 (UNAUDITED)


	Called up equity share capital £m	Other reserves £m	Hedge reserve £m		Warrant reserve £m		Share premium £m	Retained earnings £m		Total equity £m
Balance at 1 April 2005	56	767	—		51		—	747		1,621
Net (losses)/gains recognised directly on equity	—	—	(57	)	—		—	(115	)	(172	)
Share based payments	—	—	—		—		—	1		1
Profit for the period	—	—	—		—		—	16		16
Exercise of warrants	1	—	—		(9	)	13	—		5

Balance at 3 July 2005	57	767	(57	)	42		13	649		1,471

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE QUARTER ENDED 3 JULY 2005 (UNAUDITED)


	Quarter ended 3 July 2005 £m		2 July 2004 to 31 March 2005 £m
Operating activities
Operating profit for the period	45		69
Amortisation charges	1		1
Depreciation	43		40
Loss on disposal of property, plant and equipment	1		—
IAS 39 movement	47		—
Movement in other provisions	—		19
Interest paid	(12	)	(12	)
Interest received	6		3
Regular contributions to NLF	(12	)	(5	)
(Increase)/decrease in inventories	(4	)	23
Decrease in trade and other receivables	12		65
(Increase)/decrease in restricted cash	(34	)	69
Decrease in trade payables and other payables	(34	)	(84	)

Net cash inflow generated from operations	59		188

Cash flows from investing activities
Net cash acquired with subsidiary	—		113
Purchases of property, plant and equipment	(42	)	(35	)
Purchases of intangible assets	(2	)	—
Proceeds from disposal of property	—		7

Net cash used in investing activities	(44	)	85

Cash flows from financing activities
Exercise of warrants	5		—
Repayments of borrowings	—		(28	)
Share issue expense	—		(10	)
Proceeds from sale of own shares	—		3
Costs associated with sale of investments	—		(3	)

Net cash used in financing activities	5		(38	)

Net change in cash and cash equivalents	20		235
Cash and cash equivalents at beginning of the period	235		—

Cash and cash equivalents at the end of the period	255		235

The Statement of Cash Flows for the period 2 July 2004 to 31 March 2005 represents the trading cash flows for the period from 15 January 2005 to 31 March 2005, the period after the acquisition of British Energy Limited by British Energy Group plc, except the financing category which, prior to the date of the acquisition, also reflects the cash flows from the issue of equity by the Company following its incorporation.

Notes to the financial statements

1. Basis of Preparation

These quarterly financial statements have been prepared on a basis consistent with International Financial Reporting Standards (IFRS) in issue that are effective or available for early adoption at the Group’s first annual reporting date, 31 March 2006, but do not include all the disclosures in IAS 34 on interim reporting. Based on these IFRSs, the Board of Directors have made assumptions about the accounting policies expected to be adopted when the first IFRS annual financial statements are prepared for the year ending 31 March 2006. The quarterly financial statements require management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses.

The accounting policies are consistent with those that the Directors intend to use in the next annual financial statements as set out in the ‘Restatement of Results for Transition to International Financial Reporting Standards’ as published on 21 September 2005. The Group’s proposed accounting policies are included in note 10. Notwithstanding this, the IFRSs that will be effective or available for voluntary early adoption in the annual financial statements for the year ending 31 March 2006 are subject to change and to the issue of additional interpretations and therefore cannot be determined with certainty.

This is the first set of quarterly results for the first three months of the financial year for British Energy and therefore no comparative information is provided.

To assist investors to compare the underlying financial performance of the Group, ‘business performance’ income statement figures are shown before the impact of exceptional charges and other movements arising from re-measurement. For the first quarter the adjustments relate solely to the re-measurement of IAS 39.

References to ‘British Energy’ or the ‘Company’ are to British Energy Group plc. References to the ‘Group’ are to the Company and its subsidiaries.

The financial statements for the quarter ended 3 July 2005 are unaudited but have been reviewed by the auditors and their report to the Company is set out below.

These quarterly financial statements were approved by the Board of Directors on 28 September 2005.

2. Output, Revenue and Segment Information

Through consideration of our product, geographic area and regulatory environment, the Group has concluded that it has one business, being the generation and sale of electricity in the UK, resulting in one operating segment of Generation and Trading.


	Quarter ended 3 July 2005	15 January to 31 March 2005
	TWh	TWh
Output
Nuclear power stations	15.7	14.3
Coal-fired power station	1.7	2.5

	17.4	16.8


	Quarter ended 3 July 2005 Business performance	Quarter ended 3 July 2005 Re-measurement		Quarter ended 3 July 2005 Total	2 July 2004 to 31 March 2005
	£m	£m		£m	£m
Revenue
Wholesale generation sales	230	(34	)	196	250
Direct supply sales net of energy supply costs	204	—		204	170

	434	(34	)	400	420
Energy supply costs recharged to customers	82	—		82	73
Miscellaneous income	5	—		5	6

	521	(34	)	487	499

Wholesale generation sales includes revenue from Energy Purchases which cost £4m (2005 £17m).

3. Net Revalorisation Charges


	Quarter ended 3 July 2005		2 July 2004 to 31 March 2005
	£m		£m
Revalorisation of nuclear liabilities
– changes in price levels	35		23
– discharge of discount for period	32		27
Revalorisation of nuclear liabilities receivable	(38	)	(29	)
Revalorisation of NLF receivable	(29	)	(21	)
Revalorisation of contracts provision	4		2
Revalorisation of fixed decommissioning obligations	4		3

Net revalorisation charges	8		5

4. Taxation

There is no current tax charge in the period due to the availability of trading losses carried forward. The charge in the period of £26m before re-measurement and £16m after re-measurement consists solely of deferred tax.

5. Earnings Per Share

The basic earnings per share for the period has been calculated by dividing the profit after taxation by the weighted average number of ordinary shares in issue during the period. The diluted earnings per share calculation is based on the weighted average of 564 million ordinary shares in issue together with the dilutive potential of 17 million ordinary shares in respect of warrants. The effect of the NLF Cash Sweep is not considered to be dilutive. The adjustment mechanism for the NLF Cash Sweep percentage set out in the Contribution Agreement is designed such that the shareholders’ interest in the Group after taking account of the NLF Cash Sweep remains consistent. For example, in the event that a NLF Cash Sweep payment is made without a corresponding dividend then the NLF Cash Sweep percentage is diluted as if shareholders had reinvested a corresponding amount as new equity in the Group.


	3 July 2005 Basic	3 July 2005 Diluted	31 March 2005 Basic	31 March 2005 Diluted
Net profit for the period (£m)	16	16	41	41
Weighted average share capital (number of shares, million)	564	581	561	579

6. Pension Costs

There has been one significant change in the actuarial assumptions adopted at 3 July 2005 compared with 31 March 2005. The discount rate used to value the liabilities has changed from 5.5% per annum to 5.0% per annum in line with changes in the yield on long-dated corporate bonds over the period. The effect of the change in the discount rate is to place a higher value on the pension liabilities, giving rise to a significant actuarial loss over the period.

7. Contingent Assets

The Group has certain contingent assets as a result of its disposal of its 82.4% interest in Bruce Power LP. In addition to the consideration payable by the consortium under the master purchase agreement, up to a further C$100m was payable to British Energy contingent upon the restart of two of the Bruce A units under a trust agreement (the Trust Agreement) entered into on the same date. Had the first unit restarted by 15 June 2003, C$50m would have been released to British Energy and an additional C$50m would have been released to British Energy had the second unit restarted by 1 August 2003. An amount of C$5m was to be deducted from the C$50m payable in respect of each unit for its failure to restart by the scheduled restart date or by the first day of each successive calendar month following the scheduled restart date. The Group received C$20m on 22 March 2004 and C$10m on 25 May 2004 in partial consideration under the Trust Agreement. British Energy commenced arbitration proceedings in Ontario against the Ontario Provincial Government (the Province) in December 2004 seeking the payment of additional consideration under the Trust Agreement on the basis that Bruce A Units 3 and 4 restarted earlier than the dates claimed by the Province. No additional amounts appear on our balance sheet at 3 July 2005 because of uncertainties regarding their realisation. The amounts recoverable in respect of the restarted units will be substantially lower than the maximum C$100m but the amounts and timing of the payments have still to be confirmed.

8. Contingent Liabilities

On 12 February 2004 British Energy Limited received a notice of warranty claims from the consortium which purchased the Group’s 82.4% interest in Bruce Power LP alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce Power Station.

The principal tax claim relates to the treatment of expenditure at the Bruce Power Station during the period of the Group’s part ownership and is currently being considered by the Canadian tax authorities. The treatment proposed by British Energy could result in a rebate of a material amount of tax to the Group that has not been recognised in the financial statements. The consortium claims that allowance of the expenditure for that period would cause it to lose future deductions. British Energy has rejected the tax claim and expects to defend it if it is pursued further. The Group is confident that the amount of the claim should not, in any event, materially exceed the amount of the rebate, and that the tax claim should have no material cash flow impact on the Group.

The claim relating to the condition of the plant is based upon alleged erosion of certain parts of the steam generators, including the support plates, through which boiler tubes pass, which it is alleged resulted in an extended outage of one unit at the plant to carry out repair works and loss of revenues and costs of approximately C$64.5m. The consortium also claims that the alleged erosion may reduce the operating life of the unit and/or result in further repairs involving further losses. British Energy has rejected the claim and expects to defend it if it is pursued further.

Under the agreement with the consortium C$20m is retained in trust to meet any representation and warranty claims, and this may be retained pending agreement or determination of the claims.

The Group has given certain indemnities and guarantees in respect of the disposal of its investment in AmerGen.

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.

9. Non-adjusting Post Balance Sheet Events

On 15 September 2005, the Group announced the completion of the necessary technical and economic evaluation regarding the potential accounting life extension at Dungeness B. This has resulted in the life of Dungeness B being extended by ten years to 2018, five years beyond the extension assumed as part of the restructuring related fair value exercise.

10. Proposed IFRS Accounting Policies

The principal accounting policies as set out below are expected to be applied in preparing the Group’s results for the year ending 31 March 2006.

Basis of consolidation

The Group financial statements consolidate the financial statements of British Energy Group plc (BEG plc) and all of its subsidiary undertakings. BEG plc was incorporated on 2 July 2004. As a consequence of the restructuring, under a Scheme of Arrangement under section 425 of the Companies Act 1985, the Company acquired British Energy plc on 14 January 2005. The restructuring has been accounted for under the principles of acquisition accounting. The application of acquisition accounting principles means that all the separate assets and liabilities of British Energy plc have been recorded at fair value at the date of acquisition with goodwill arising on the difference between the value of net assets of British Energy plc and the acquisition consideration paid. Only the post acquisition results are included in the Group income statement, statement of changes in equity and cash flow statement.

Inter-company profits, transactions and balances are eliminated on consolidation.

Significant estimates used in applying accounting policies

The principal accounting polices adopted by BEG plc in the consolidated financial statements are as set out below. The application of a number of these policies required the Group to use a variety of estimation techniques and applying judgement to best reflect the substance of underlying transactions.

Significant factors considered when assessing the carrying value of assets include future electricity prices, expected annual output, expected station operating costs, remaining station lives and discount rates. BEG plc has determined that a number of its accounting policies can be considered significant, in terms of the management judgement that has been required to determine the various assumptions underpinning their application in the financial statements presented, which, under different conditions, could lead to material difference in these statements. The policies where significant judgements and estimates have been made are:

•

Application of business combination accounting rules;

•

Accounting for property, plant and equipment;

•

Estimation of liabilities for spent nuclear fuel and decommissioning costs; and

•

Estimation of defined benefit pension scheme liabilities.

Revenue

Revenue is recognised by the Group when persuasive evidence of a sales arrangement exists, delivery of goods or services has occurred, the amount of revenue can be measured reliably, collectibility of the related receivable amount is probable and the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Revenue represents the fair value of the consideration receivable for sales of electricity and sales of other related goods and services. It is shown net of value added tax, electricity purchases relating to short term balancing and hedging activities, and climate change levy. Revenue is also shown after elimination of sales within the Group.

Wholesale generation and direct supply sales are recognised on an accruals basis with reference to meter readings of electricity supplied. Where required, a management estimate is included of the value of units supplied to customers between the date of their last meter reading and the accounting period end.

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. All costs are capitalised into inventory and charged to the income statement in proportion to the amount of fuel burnt.

Pressurised Water Reactor (PWR)

All front end fuel costs are variable and are capitalised into inventory and subsequently charged to the income statement in proportion to the amount of fuel burnt.

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:-

a)	a cost per tonne of uranium in AGR fuel, in respect of amounts payable on loading of fuel into any one of the AGR reactors and

b)	a rebate/surcharge against the cost mentioned in (a) above that is dependent on the out-turn electricity price in the year and the amount of electricity generated.

The loading related cost and the rebate/surcharge is capitalised into inventory and charged to the income statement 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 current prices discounted back to current value. Back end fuel costs are capitalised into inventory on loading and charged to the income statement in proportion to the amount of fuel burnt.

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 costs of this unburnt fuel (final core) is fully provided at the balance sheet date and any changes in the carrying value of nuclear fuel attributed to the final core are charged to the income statement in the accounting period.

Fuel Costs – Coal (including Emission Rights)

Fuel costs for coal are determined on a weighted average cost basis. Fuel costs for coal also include costs of emission allowances. The Group recognises liabilities in respect of its obligations to deliver emission allowances to the extent that the allowances to be delivered exceed those previously acquired by the Group, either by allocation from the Government or a similar body or through purchase. Any liabilities recognised are measured based on the period end estimates of the amounts that will be required to satisfy the net obligation.

Inventory - Stores

Inventory held in stores is recorded at the lower of cost and net realisable value.

Employee Benefits - Post Retirement Benefit Obligations

The Group provides for pension costs in accordance with IAS 19 (2004) ‘Employee Benefits’. Contributions to the Group’s defined benefit pension schemes are assessed by qualified actuaries. BEG plc operates two separate pension arrangements in the UK within the Electricity Supply Pension Scheme, which is a defined benefit scheme. Pension scheme assets are measured using market values, which for securities is based on bid price values. Pension costs are assessed using the projected unit method so that the cost of providing pensions is charged to the income statement in a manner which spreads the service cost over the expected service lives of employees. The pension obligation is measured as the present value of the estimated future cash outflows, discounted using the interest rates on UK government securities of appropriate maturity. The expected return on the schemes’ assets and the increase during the period in the present value of the schemes’ liabilities arising from the passage of time are included in other finance income. Actuarial gains and losses are recognised immediately within the Statement of Recognised Income and Expense.

The capital cost of ex-gratia and supplementary pensions is charged to the income statement, to the extent that the arrangements are not covered by the surplus in schemes, in the accounting period in which they are granted.

Certain additional unfunded retirement benefits are provided to eligible employees. The cost of providing such benefits is charged to the income statement as they accrue.

NLF Funding Arrangements

Under the arrangements with the Secretary of State the NLF will fund, subject to certain exceptions, the Group’s qualifying uncontracted nuclear liabilities and qualifying decommissioning costs. To the extent there is any surplus remaining in the NLF after all obligations have been discharged, this amount will be paid to the Secretary of State. The Group is responsible for funding certain excluded or disqualified liabilities and will, in certain circumstances, be required to compensate or indemnify the NLF and the Secretary of State in relation to such liabilities. The Group’s obligations under these arrangements with the Secretary of State are guaranteed by certain companies within the Group.

In consideration for the assumption of these liabilities by the Secretary of State and the NLF, British Energy Holdings plc (a subsidiary of BEG plc) issued £275m in New Bonds to the NLF at RED. The Group will also make the following payments to the NLF (i) an annual contribution (NLF Cash Sweep payment) initially equal to 65% of the British Energy Group’s adjusted net cash flow, adjusted for certain corporate actions but never to exceed 65% (ii) fixed decommissioning contributions equal to £20m per annum (indexed to RPI but tapering off as the nuclear power stations are currently scheduled to close); and (iii) £150,000 (indexed to RPI) for every tonne of uranium in PWR fuel loaded into the Sizewell B reactor after RED.

The NLF has the right from time to time to convert all or part of the NLF Cash Sweep payment into convertible shares of the Company. On a full conversion, the NLF would hold up to 65% of the thereby enlarged equity share capital of the Company. However, the terms of the Convertible Shares include a limit on the voting rights of such shares equal to a maximum of 29.9% whilst held by the NLF.

The annual NLF Cash Sweep payment can only be determined after the end of the financial year and is contingent based on cash generation in the year. Therefore, it is only recognised and provided for when it becomes determinable and not in any interim financial periods. It will be recorded as an operating cost of the applicable financial year. The annual NLF Cash Sweep payment becomes payable twenty business days after publication of the annual report and accounts.

The fixed decommissioning obligations of annum have been recorded as a liability on the balance sheet at their discounted value and disclosed as the NLF liability. The NLF liability is reduced as payments are made to the NLF. Each year the financing charges in the income statement include the revalorisation of NLF liabilities required to discharge one year’s discount from the liability.

PWR fuel loaded after RED will increase the qualifying nuclear liability recognised for back end PWR fuel costs as set out above and will increase the NLF receivable by a corresponding amount. The difference between the payment of £150,000 (indexed to RPI) per tonne made to the NLF on the loading of PWR fuel and the increase in the liability recognised, and therefore the increase in NLF receivable, is recorded as a back end fuel cost or credit as appropriate in the year of loading.

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 capitalised as an intangible asset on the balance sheet. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill balances are assessed for impairment at least annually and at other balance sheet dates if there is any indication of impairment.

Taxation

The tax expense represents the sum of the tax currently payable and deferred tax.

The tax currently payable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the income statement because it excludes items of income and expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group’s liability for tax currently payable is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

The tax expense relating to items recognised directly in equity are recognised in equity and not in the income statement.

Deferred tax is provided in full, using the liability method, on temporary differences, carry-forward of unused tax assets and unused tax losses, arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements.

Deferred tax assets are recognised to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilised.

Property, Plant and Equipment and Depreciation, including Decommissioning Costs

Property, plant and equipment comprises assets acquired or constructed by the Group. Property, plant and equipment (other than assets in the course of construction) are stated in the balance sheet at cost less accumulated depreciation. The fair value of property, plant and equipment acquired as a result of the restructuring has been deemed to be the cost amount recognised at that date. Cost includes expenditure that is directly attributable to the acquisition of the items. 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 charge for depreciation of property, plant and equipment 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. The asset lives adopted are reviewed annually and for the year ended 31 March 2006 were:


AGR power stations		5 - 17 years
PWR power station		29 years
Coal power station		10 years
Other buildings		30 years
Other plant and equipment		18 months - 5 years

Expenditure incurred to replace a component of an item of property, plant and equipment that is accounted for separately, or to improve its operational performance is included in the asset’s carrying amount or recognised as a separate asset as appropriate when it is probable that future economic benefits in excess of the originally assessed standard of performance of the existing asset will flow to the Group and the cost of the item can be measured reliably. Expenditure to improve safety or in order to meet increased regulatory standards is also capitalised. Expenditure on major inspection and overhauls of production plant is capitalised, within other plant and equipment, when it meets the asset recognition criteria and is depreciated over the period until the next outage. 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. Asset additions are depreciated over the remaining useful life of the related asset.

The estimated costs for decommissioning the Group’s nuclear power stations and restoring the sites on which they are located are capitalised 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.

Major spare parts are classified as property, plant and equipment and assigned to individual stations when they are expected to be utilised over more than one period. They are depreciated using the applicable station lifetime estimate.

Other expenditure, including that incurred on preliminary studies and on the initiation of new technologies not yet adopted, is charged to the income statement as incurred. All other maintenance, repairs and renewals are charged to the income statement during the financial period in which they are incurred.

Gains and losses on the disposal of property, plant and equipment are included in operating profit/loss.

Intangible Assets (excluding Goodwill)

The costs of acquired computer software costs are capitalised on the basis of the costs incurred to acquire and bring the specific software in to use, and are amortised over their estimated operational lives for a maximum of five years. Costs directly associated with the development of computer software programmes that are expected to generate economic benefits over a period in excess of one year are also capitalised and amortised over their estimated operational lives.

ROCs and LECs are classified as intangible assets and are valued at cost.

Impairment of Tangible and Intangible Assets (excluding Goodwill)

At each balance sheet date, the Group reviews its tangible and intangible assets (excluding goodwill) to determine whether there is any indication that those assets may have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated to determine the extent of any impairment loss.

NLF Receivable and Nuclear Liabilities Receivable

The Government indemnity is provided to indemnify any future shortfall on NLF funding of qualifying uncontracted nuclear liabilities (including PWR back-end fuel services) and qualifying nuclear decommissioning costs.

The NLF receivable asset recognised represents the aggregate value of the NLF and the Government indemnity such that the receivable equals the present value of the associated qualifying nuclear liabilities.

The Government indemnity is also provided to cover services for spent AGR fuel loaded pre-restructuring. The nuclear liabilities receivable is recognised in respect of the indemnity such that the receivable equals the present value of the associated qualifying nuclear liabilities.

The NLF receivable and the nuclear liabilities receivable 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 income statement include the revalorisation of these receivables required to match the revalorisation of the nuclear liabilities.

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. 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 income statement has been dealt with under the accounting policies for fuel costs above. These nuclear liabilities 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.

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.

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 income statement include the revalorisation of liabilities required to discharge one year’s discount from provisions made in prior years and restate these provisions to current price levels.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, with banks and short-term deposits with a maturity of three months or less. Restricted cash primarily consists of cash pledged as collateral.

Financial Instruments

Implementation of IAS 32 and IAS 39

The Group has applied IAS 32 and the full version of IAS 39 in the financial year ending 31 March 2006 rather than the European Union (‘EU’) adopted regulation of November 2004 which endorsed IAS 39 with the exception of certain provisions relating to (i) the use of the full fair value option for liabilities and (ii) hedge accounting. Applying the full version of the standard has no impact on the group’s financial statements.

In accordance with the transitional arrangements set out in IFRS 1, the Group has not restated the prior period’s comparative figures to show the effect of IAS 32 and IAS 39. For the period ended 31 March 2005, financial instruments continue to be accounted for in accordance with the Group’s previous policies for financial instruments under UK GAAP.

Recognition, classification and subsequent measurement of financial assets and liabilities

IAS 39 requires that all financial assets be initially recognised at fair value in the balance sheet with changes in fair value reported through the income statement. Exceptions apply to assets classified as loans and receivables and held-to-maturity investments, which are measured at amortised cost using the effective interest method, and also to equity investments in instruments whose fair value can not be reliably measured, which are recognised and measured at cost.

Financial liabilities are measured at amortised cost using the effective interest method. The Group measures all debt instruments initially at fair value, and this is taken to be the fair value of the consideration received.

Transaction costs (any such costs incremental to and directly attributable to the issue of the financial instruments) are included in the calculation of the effective interest rate and are, in effect, amortised through the income statement over the life of the instrument. Derivative instruments, and commodity contracts that fall within the scope of IAS 39, are carried at fair value with special rules applying to all financial instruments which form part of a hedging relationship.

Accounting for derivatives and commodity contracts

The Group’s activities expose it primarily to risks associated with electricity generation, the purchase of fuel for use in the generation process, and the supply of electricity to end customers in both the wholesale and retail markets. The Group follows a trading strategy of selling forward a proportion of the Company’s output to reduce the Group’s exposure to potential falls in the market price of electricity. The use of derivative financial instruments occurs primarily within the Group’s electricity trading and coal procurement activities.

The Group’s accounting objective is to report earnings results that are consistent with its operational strategies. As such, the Group aims to recognise the earnings effects of derivative transactions executed to hedge economic business risks in the income statement in the period in which the economically hedged operational activity affects earnings. The Board has endorsed

the use of derivative financial instruments as hedging tools and the Group uses derivative and non-derivative financial instruments to manage its exposures. Physical and financially settled instruments are held by the Group to match offsetting physical positions and are not held for financial trading purposes.

Where commodity contracts, such as electricity and fuel, are entered into in accordance with the Group’s own purchase, sale or usage requirements they are accounted for on an accruals basis following delivery of the commodity and are thereby excluded from the scope of IAS 39. Amounts payable or receivable in respect of these contracts are recorded within trade creditors and trade receivables respectively. Where a commodity contract is not entered in to or does not continue to be held to meet the Group’s own purchase, sale or usage requirements the recognition and measurement requirements of IAS 39 are applied.

Derivative financial instruments are initially recognised at fair value and all changes in fair value are subsequently accounted for through the income statement unless the derivative qualifies as a hedging instrument.

Changes in the fair value of derivative financial instruments that are designated and are effective as hedges of future cash flows are recognised directly in equity, in the cash flow hedge reserve, and the ineffective portion of the hedge is recognised immediately in the income statement.

The Group designates derivatives as hedging instruments when it is expected that there will be a high inverse correlation between the changes in fair value of the hedging instrument and the changes in the fair value of the cash flows of the hedged item. This is measured primarily using the dollar offset method. Such correlation is required to be within the limits of 80% to 125% for hedge accounting to be permitted. Prospective and retrospective testing is carried out on a regular basis, at least on each reporting date, to establish whether the assumptions and application criteria for hedge accounting going forward continue to be supported. The Group discontinues hedge accounting where the hedging relationship correlation is outside the required parameters.

Derivative instruments are de-designated from a hedge relationship when:

•

The hedging instrument or item expires or is settled;

•

The forecast transaction is no longer considered to be highly probable; and

•

The hedging instrument no longer qualifies for hedge accounting under IAS 39 rules.

At that time, any cumulative gain or loss on the hedging instrument recognised in equity is retained in equity until the forecast transaction is settled. If a hedged transaction is no longer expected to occur, the net cumulative gain or loss recognised within equity is transferred to the income statement of the period.

Valuation of commodity contracts and derivatives

The group’s valuation policy for derivative and other financial instruments is to maximise the use of quoted prices from active trading markets.

Futures, swaps, and forward agreements are valued against the appropriate market-based curves. Three types of curves (price, volatility and correlation) may be required depending upon the liquidity of the market and type of product traded forward price curves are developed using market prices from independent sources for liquid commodities, markets and products and modelled for illiquid commodities, markets and products. Volatility curves are modelled for open positions in illiquid markets and implied volatility curves are developed from actively traded options. Correlation curves are developed using either implied correlations or using historical forward correlations and other relevant market data.

Where necessary, structured transactions are disaggregated into their traded core components, and each component is valued against the appropriate market-based curves. The fair value of a structured deal is the summation of the fair value of its core components.

Purchase contracts are valued against the quoted bid price and sales contracts are valued against the quoted offer prices, with no provisions made for liquidity. Valuation adjustments are made for the time value of money, which is applied to all contracts, and credit risk, which will be applied where applicable.

Embedded derivatives

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 IAS 39 requirements. Where embedded derivatives have terms that are not 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 the income statement, to the extent that the hybrid instrument is not already accounted for at fair value.

Embedded derivatives are valued either by directly valuing the derivative element in line with the processes described above or by valuing the embedded derivative as the difference between the value of the hybrid instrument and the host contract (excluding the derivative element).

Offsetting of derivative assets and liabilities

The Group offsets a financial asset and a financial liability and reports the net amount only when the Group has a legally enforceable right to set off the amounts and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.

Impact on Effective Tax Rate

Income tax for interim reporting periods is calculated by applying an estimate of the annual effective tax rate to the interim result excluding IAS 39 adjustments, and by calculating tax at the standard rate for the IAS 39 adjustments arising within the period.

Share-based Payments

BEG has two share compensation schemes, a Long Term Deferred Bonus Plan, and a Share Incentive Plan. BEG plc accounts for its share compensation schemes in accordance with IFRS 2 ‘Share-based Payments’ using the Black-Scholes option pricing model under which fair value is calculated for the share compensation schemes and updated at subsequent balance sheet dates.

The fair value of the share compensation schemes is charged to the income statement over the period from the date the schemes were granted to the date at which the compensation is expected to vest on the employees. The corresponding credit is included in Shareholders’ Equity. The Group issues equity-settled share-based payments to certain employees under the terms of the Group’s various employee share compensation schemes. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value determined at the grant date of equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on an estimate of the shares that will ultimately vest.

INDEPENDENT REVIEW REPORT TO BRITISH ENERGY GROUP PLC

Introduction

We have been instructed by the company to review the financial information for the quarter ended 3 July 2005 which comprises the consolidated income statement, consolidated balance sheet, consolidated statement of recognised income and expense, consolidated statement of changes in equity, consolidated statement of cash flows, and associated notes. We have read the other information contained in the quarterly report and considered whether it contains any apparent misstatements or material inconsistencies with the financial information.

Directors’ responsibilities

The quarterly report, including the financial information contained therein, is the responsibility of, and has been approved by the directors. The directors are responsible for preparing the interim report in accordance with the Listing Rules of the Financial Services Authority.

As disclosed in note 1, the next annual financial statements of the group will be prepared in accordance with accounting standards adopted for use in the European Union. This quarterly report has been prepared in accordance with the basis set out in Note 1.

The accounting policies are consistent with those that the directors intend to use in the next annual financial statements. As explained in note 1, there is, however, a possibility that the directors may determine that some changes are necessary when preparing the full annual financial statements for the first time in accordance with accounting standards adopted for use in the European Union. The IFRS standards and IFRIC interpretations that will be applicable and adopted for use in the European Union at 31 March 2006 are not known with certainty at the time of preparing this interim financial information.

Review work performed

We conducted our review in accordance with guidance contained in Bulletin 1999/4 issued by the Auditing Practices Board for use in the United Kingdom. A review consists principally of making enquiries of group management and applying analytical procedures to the financial information and underlying financial data and, based thereon, assessing whether the disclosed accounting policies have been applied. A review excludes audit procedures such as tests of controls and verification of assets, liabilities and transactions. It is substantially less in scope than an audit and therefore provides a lower level of assurance. Accordingly we do not express an audit opinion on the financial information. This report, including the conclusion, has been prepared for and only for the company for the purpose of the Listing Rules of the Financial Services Authority and for no other purpose. We do not, in producing this report, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

Review conclusion

On the basis of our review we are not aware of any material modifications that should be made to the financial information as presented for the quarter ended 3 July 2005.

PricewaterhouseCoopers LLP

Chartered Accountants

Edinburgh

28 September 2005

Notes:

(a) The maintenance and integrity of the British Energy Group plc website is the responsibility of the Directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the quarterly report since it was initially presented on the website.

(b) Legislation in the United Kingdom governing the preparation and dissemination of financial information may differ from legislation in other jurisdictions.

GLOSSARY

AGR (Advanced Gas-cooled Reactor)

The second generation of gas-cooled nuclear reactor built in the UK.

BETTA

British Electricity Transmission and Trading Arrangements.

Baseload Generation

Mode of operation of a power station at a constant high level of output for a sustained period of time to assist in meeting minimum national demand.

Bruce

The Bruce A and B nuclear power stations in Ontario, Canada.

Decommissioning

The process whereby a nuclear power station is shut down at the end of its economic life, eventually dismantled, and the site made available for other purposes.

DSB

Direct supply business.

Energy Supply Costs

These mainly comprise the costs incurred for the use of the distribution and transmission systems, recovered through revenue, and accrued costs of Renewable Obligation Certificates (ROCs).

EPL

Eggborough Power Limited.

ETS

Emissions Trading Scheme.

FGD (Flue Gas Desulphurisation)

Equipment fitted to coal-fired power stations to reduce sulphur dioxide emissions.

Market Price

The price for annual forward baseload contracts.

MW (megawatt): MWh (megawatt-hour)

One megawatt equals 1,000 kW: one megawatt-hour represents one hour of electricity consumption at a constant rate of 1 MW.

NDA

Nuclear Decommissioning Authority.

NLF

An independently administered fund into which the Group makes contributions to cover all qualifying uncontracted nuclear liabilities including costs of decommissioning nuclear power stations and PWR back end fuel costs.

Operating Unit Cost

Calculated by dividing the total operating cost, excluding re-measurement, energy supply costs recharged to customers and energy purchases, by total output.

Outage (Planned and Unplanned)

A period during which a reactor is shut down. The periodic shutdown of a reactor including for maintenance, inspection and testing or, in some cases, for refuelling is known as a planned outage. In the UK, some planned outages are known as statutory outages and are required by the conditions attached to the nuclear site licence needed to operate the station. Unscheduled shutdown of a reactor for a period is known as an unplanned outage.

PiP

The Performance Improvement Programme.

PWR (Pressurised Water Reactor)

The most recent type of nuclear reactor to be constructed in the UK which uses pressurised water as both the coolant and the moderator.

Quinquennial Review

The five-yearly review of the assumptions underlying the Group’s provision for certain nuclear liabilities.

Realised Price

This is the average price of electricity sold during the relevant period. It is calculated by dividing revenue, excluding re-measurement impact, energy supply costs recharged to customers and miscellaneous income, and net of energy purchase costs, by total output during the period.

Renewable Obligation Certificates

Eligible renewable generators receive Renewable Obligation Certificate (ROCs) for each MWh of electricity generated. These certificates can then be sold to suppliers, in order to fulfil their renewables obligation.

Restructuring

The restructuring of the Group completed on 14 January 2005.

Restructuring Effective Date (RED)

14 January 2005.

Revalorisation

Revalorisation arises because nuclear liabilities are stated in the balance sheet at current price levels, discounted at 3% per annum from the eventual payment dates. The revalorisation charge is the adjustment that results from restating these liabilities to take into account the effect of inflation in the year and to remove the effect of one year’s discount as the eventual dates of payment become one year closer. Revalorisation charges arise in respect of the fixed decommissioning obligation to reflect the unwinding of the discount for the period. A revalorisation credit arises in respect of movements in the value of nuclear liabilities and the NLF receivable to take account of the underlying movement in nuclear liabilities.

Statutory Outage

The planned shutdown of nuclear reactors for regulatory inspection and maintenance.

TW (terawatt): TWh (terawatt-hour)

One terawatt equals 1,000 GW: one terawatt-hour represents one hour of electricity consumption at a constant rate of 1 TW.

Unit Capability Factor

The percentage of maximum energy generation that a plant is capable of supplying to the electrical grid, limited only by factors within the control of plant management.

Unplanned Capability Loss Factor

Unplanned capability loss factor is defined as the ratio of the unplanned energy losses during a given period of time, to the reference energy generation, expressed as a percentage.

WANO

The World Association of Nuclear Operators. A nuclear industry organisation which encourages peer review and collects and shares operating data worldwide which is then used to benchmark performance.

Warrants

Warrants entitling the holder to subscribe for shares in British Energy Group plc.